UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

~~[X]~~


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

~~SECURITIES EXCHANGE ACT OF 1934~~

For the quarterly period ended ~~September~~June 30, ~~2009~~2010

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

~~SECURITIES EXCHANGE ACT OF 1934~~

~~For the transition period from~~
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period fromto

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 (An Ohio Corporation)	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~~Yes~~ ~~(X)~~þ No~~( )~~o		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~~Yes~~ ~~(X)~~þ No~~( )~~o		FirstEnergy Corp.


Yes~~Yes~~ ~~( )~~o No~~( )~~o		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~~“large accelerated filer,~~" "accelerated filer"~~” “accelerated filer” and ~~"smaller~~“smaller reporting ~~company"~~company” in Rule 12b-2 of the Exchange Act.


Large Accelerated Filerþ ~~(X)~~		FirstEnergy Corp.

Accelerated Filero ~~( )~~		N/A

Non-accelerated Filer (Do not check if a smaller reporting company)þ ~~(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 Companyo ~~Company~~ ~~( )~~		N/A

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


Yes~~Yes~~ ~~( )~~o No~~(X)~~þ		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~~issuer’s classes of common stock, as of the latest practicable date:


		OUTSTANDING
CLASS		AS OF ~~Novembe 6, 2009~~JULY 31, 2010
FirstEnergy Corp., ~~$0.10~~$10 par value	~~304,835, 407~~		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 ~~PUCO’s~~ regulatory process on the pending matters in Ohio, ~~Companies associated with the distribution rate case.~~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.~~recover regulatory assets or increased costs.

·
~~Operating~~	•		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 proposed rules promulgated by EPA on July 6, 2010, in response to 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.~~rules.

·
	•		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.

·
	•		Ultimate resolution of Met-Ed’s and Penelec’s ~~transmission service charge~~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.~~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~~state of the national and regional ~~economy~~economies and ~~its impact~~associated impacts 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~~Page

Glossary of Terms		iii-v

Item 1. Financial Statements

FirstEnergy Corp.

	Consolidated Statements of Income			1

Consolidated Statements of Comprehensive Income ~~(Loss)~~			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

~~TABLE OF CONTENTS (Cont'd)~~

		~~Pages~~

~~Combined Notes To~~ Consolidated ~~Financial Statements~~Balance Sheets	~~26-65~~

~~Report of Independent Registered Public Accounting Firm~~24

~~FirstEnergy Corp.~~	66
~~FirstEnergy Solutions Corp.~~Consolidated Statements of Cash Flows	67		25
~~Ohio Edison Company~~Exhibit 12				68
~~The Cleveland Electric Illuminating Company~~Exhibit 31.1				69
~~The Toledo Edison Company~~Exhibit 31.2				70
~~Jersey Central Power & Light Company~~Exhibit 32				71
~~Metropolitan Edison Company~~EX-101 INSTANCE DOCUMENT				72
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

TABLE OF CONTENTS (Cont’d)

~~Pennsylvania Electric Company~~

	73
		Page

Combined Notes To Consolidated Financial Statements			26

Item 2. ~~Management's~~Management’s Discussion and Analysis of Registrant and Subsidiaries	~~74-118~~		65

~~Management's~~Management’s Narrative Analysis of Results of Operations

FirstEnergy Solutions Corp.	~~119-121~~		103

Ohio Edison Company	~~122-123~~		106

The Cleveland Electric Illuminating Company	~~124-125~~		108

The Toledo Edison Company	~~126-127~~		110

Jersey Central Power & Light Company	~~128-129~~		112
~~Metropolitan Edison Company~~	~~130-131~~
~~Pennsylvania Electric Company~~		~~132-133~~

Metropolitan Edison Company			114

Pennsylvania Electric Company			116

Item 3. Quantitative and Qualitative Disclosures About Market Risk	~~134~~		118

Item 4. Controls and Procedures –— FirstEnergy	~~134~~		118

Item 4T. Controls and Procedures –— FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec	~~134~~

~~Part II. Other Information~~118

~~Item 1. Legal Proceedings~~Part II. Other Information	~~135~~

Item ~~1A. Risk Factors~~1. Legal Proceedings	~~135~~		119

Item 1A. Risk Factors			119

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	~~135~~		119

~~Item 5. Other Information~~		~~135~~

Item 5. Other Information			119

Item 6. Exhibits	~~136-137~~		120

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~~ Met-Ed	~~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~~Shippingport	~~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:


~~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~~AOCL	~~American Municipal Power-Ohio, Inc.~~
~~AOCL~~	Accumulated Other Comprehensive Loss
AQC		Air Quality Control
ARO		Asset Retirement Obligation
BGS CAA		Basic Generation Service
~~CAA~~	Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CBP		Competitive Bid Process
CO₂		Carbon Dioxide
CTC		Competitive Transition Charge
DOE		United States Department of Energy
DOJ		United States Department of Justice
DPA		Department of the Public Advocate, Division of Rate Counsel (New Jersey)
EDCP		Executive Deferred Compensation Plan
EE&C		Energy Efficiency and Conservation
EMAAC		Eastern Mid-Atlantic Area Council
EMP		Energy Master Plan
EPA		United States Environmental Protection Agency
~~EPACT~~EPRI	~~Energy Policy Act of 2005~~	Electric Power Research Institute

iii

GLOSSARY OF TERMS, Cont’d.


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		Generally Accepted Accounting Principles ~~Generally Accepted~~ in the United States
GHG		Greenhouse Gases

~~iii~~

~~GLOSSARY OF TERMS, Cont'd.~~

IRS		Internal Revenue Service
JOA		Joint Operating Agreement
kV		Kilovolt
KWH		Kilowatt-hours
LED	~~Light-emitting~~	Light-Emitting Diode
~~LIBOR~~LOC	~~London Interbank Offered Rate~~
~~LOC~~	Letter of Credit
MAAC		Mid-Atlantic Area Council
MACT		Maximum Achievable Control Technology
MDPSC		Maryland Public Service Commission
MISO		Midwest Independent Transmission System Operator, Inc.
~~Moody's~~Moody’s	~~Moody's~~	Moody’s Investors Service, Inc.
MRO		Market Rate Offer
MW		Megawatts
MWH		Megawatt-hours
NAAQS		National Ambient Air Quality Standards
NERC		North American Electric Reliability Corporation
NJBPU		New Jersey Board of Public Utilities
NNSR		Non-Attainment New Source Review
NOAC		Northwest Ohio Aggregation Coalition
NOPEC		Northeast Ohio Public Energy Council
NOV		Notice of Violation
NO_X		Nitrogen Oxide
NRC		Nuclear Regulatory Commission
NSR		New Source Review
NUG		Non-Utility Generation
NUGC		Non-Utility Generation Charge
~~NYMEX~~OCI	~~New York Mercantile Exchange~~
~~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~~POLR		Provider of Last Resort; an electric ~~utility's~~utility’s obligation to provide generation service to customers whose alternative supplier fails to deliver service
PPUC		Pennsylvania Public Utility Commission
PSCWV		Public Service Commission of West Virginia
PSA		Power Supply Agreement
PSD		Prevention of Significant Deterioration
PPUC		Pennsylvania Public Utility Commission
PUCO		Public Utilities Commission of Ohio
~~QSPE~~RCP	~~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~~Poor’s Ratings Service
SB221		Amended Substitute Senate Bill 221
SBC		Societal Benefits Charge

GLOSSARY OF TERMS, Cont’d.


SEC		U.S. Securities and Exchange Commission
~~SECA~~SIP	~~Seams Elimination Cost Adjustment~~
~~SIP~~	State Implementation Plan(s) Under the Clean Air Act
SNCR		Selective Non-Catalytic Reduction
SO₂		Sulfur Dioxide
TBC		Transition Bond Charge
TMI-2		Three Mile Island Unit 2
TSC		Transmission Service Charge
~~VERO~~VIE	~~Voluntary Enhanced Retirement Option~~	Variable Interest Entity
VSCC		Virginia State Corporation Commission
VIE		Variable Interest Entity

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)


	Three Months						Six Months
	Ended June 30						Ended June 30
	2010			2009			2010			2009
	*(In millions, except per share amounts)*
REVENUES:
Electric utilities	$	2,373		$	2,791		$	4,916		$	5,811
Unregulated businesses		755			480			1,511			794

Total revenues*		3,128			3,271			6,427			6,605


EXPENSES:
Fuel		350			276			684			588
Purchased power		1,052			1,024			2,290			2,167
Other operating expenses		673			612			1,374			1,439
Provision for depreciation		190			185			383			362
Amortization of regulatory assets		161			233			373			642
Deferral of new regulatory assets		—			(45	)		—			(136	)
General taxes		176			184			381			395

Total expenses		2,602			2,469			5,485			5,457


OPERATING INCOME		526			802			942			1,148


OTHER INCOME (EXPENSE):
Investment income		31			27			47			16
Interest expense		(207	)		(206	)		(420	)		(400	)
Capitalized interest		40			33			81			61

Total other expense		(136	)		(146	)		(292	)		(323	)


INCOME BEFORE INCOME TAXES		390			656			650			825

INCOME TAXES		134			248			245			302


NET INCOME		256			408			405			523

Noncontrolling interest loss		(9	)		(6	)		(15	)		(10	)


EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	265		$	414		$	420		$	533


BASIC EARNINGS PER SHARE OF COMMON STOCK	$	0.87		$	1.36		$	1.38		$	1.75


WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304			304			304


DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.87		$	1.36		$	1.37		$	1.75


WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		305			305			305			306


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


*		Includes excise tax collections of $99 million and $95 million in the three months ended June 30, 2010 and 2009, respectively, and $208 million and $204 million in the six months ended June 30, 2010 and 2009, respectively.

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)


	Three Months						Six Months
	Ended June 30						Ended June 30
	2010			2009			2010			2009
	*(In millions)*

NET INCOME	$	256		$	408		$	405		$	523


OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		17			469			30			504
Unrealized gain on derivative hedges		6			23			10			38
Change in unrealized gain on available-for-sale securities		6			37			12			32

Other comprehensive income		29			529			52			574
Income tax expense related to other comprehensive income		9			227			16			242

Other comprehensive income, net of tax		20			302			36			332


COMPREHENSIVE INCOME		276			710			441			855

COMPREHENSIVE LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST		(9	)		(6	)		(15	)		(10	)


COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	285		$	716		$	456		$	865

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

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In millions)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	281		$	874
Receivables-
Customers (less allowances of $33 million in 2010 and 2009)		1,409			1,244
Other (less allowances of $7 million in 2010 and 2009)		146			153
Materials and supplies, at average cost		675			647
Prepaid taxes		397			248
Other		206			154

		3,114			3,320

PROPERTY, PLANT AND EQUIPMENT:
In service		28,274			27,826
Less — Accumulated provision for depreciation		11,724			11,397

		16,550			16,429
Construction work in progress		3,000			2,735

		19,550			19,164

INVESTMENTS:
Nuclear plant decommissioning trusts		1,880			1,859
Investments in lease obligation bonds		486			543
Other		589			621

		2,955			3,023

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		5,575			5,575
Regulatory assets		2,313			2,356
Power purchase contract asset		134			200
Other		825			666

		8,847			8,797

	$	34,466		$	34,304

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	1,571		$	1,834
Short-term borrowings		1,463			1,181
Accounts payable		848			829
Accrued taxes		256			314
Other		907			1,130

		5,045			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		5,440			5,448
Accumulated other comprehensive loss		(1,379	)		(1,415	)
Retained earnings		4,747			4,495

Total common stockholders’ equity		8,839			8,559
Noncontrolling interest		(20	)		(2	)

Total equity		8,819			8,557
Long-term debt and other long-term obligations		11,861			11,908

		20,680			20,465

NONCURRENT LIABILITIES:
Accumulated deferred income taxes		2,710			2,468
Retirement benefits		1,531			1,534
Asset retirement obligations		1,372			1,425
Deferred gain on sale and leaseback transaction		976			993
Power purchase contract liability		691			643
Lease market valuation liability		239			262
Other		1,222			1,226

		8,741			8,551

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	34,466		$	34,304

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
(In millions, except per share amounts)
REVENUES:
Electric utilities $ 2,940 $ 3,469 $ 8,751 $ 9,247
Unregulated businesses 468 435 1,262 1,179
Total revenues * 3,408 3,904 10,013 10,426

EXPENSES:
Fuel 302 356 890 1,000
Purchased power 1,313 1,306 3,480 3,376
Other operating expenses 665 794 2,103 2,374
Provision for depreciation 188 168 550 500
Amortization of regulatory assets 261 291 903 795
Deferral of regulatory assets - (58 ) (136 ) (261 )
General taxes 192 201 587 596
Total expenses 2,921 3,058 8,377 8,380

OPERATING INCOME 487 846 1,636 2,046

OTHER INCOME (EXPENSE):
Investment income 191 40 207 73
Interest expense (355 ) (192 ) (755 ) (559 )
Capitalized interest 35 15 96 36
Total other expense (129 ) (137 ) (452 ) (450 )

INCOME BEFORE INCOME TAXES 358 709 1,184 1,596

INCOME TAXES 128 238 430 585

NET INCOME 230 471 754 1,011

Noncontrolling interest income (loss) (4 ) - (14 ) 1

EARNINGS AVAILABLE TO FIRSTENERGY CORP. $ 234 $ 471 $ 768 $ 1,010

BASIC EARNINGS PER SHARE OF COMMON STOCK $ 0.77 $ 1.55 $ 2.52 $ 3.32

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING 304 304 304 304

DILUTED EARNINGS PER SHARE OF COMMON STOCK $ 0.77 $ 1.54 $ 2.51 $ 3.29

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING 306 307 306 307

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK $ 1.10 $ 1.10 $ 1.65 $ 1.65

* Includes excise tax collections of $106 million and $115 million in the three months ended September 30, 2009 and 2008, respectively,
and $310 million and $329 million in the nine months ended September 2009 and 2008, respectively.

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

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In millions)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	405		$	523
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		383			362
Amortization of regulatory assets		373			642
Deferral of new regulatory assets		—			(136	)
Nuclear fuel and lease amortization		76			52
Deferred purchased power and other costs		(146	)		(135	)
Deferred income taxes and investment tax credits, net		159			69
Investment impairment		19			39
Deferred rents and lease market valuation liability		(62	)		(59	)
Stock-based compensation		(6	)		(2	)
Accrued compensation and retirement benefits		(27	)		(93	)
Interest rate swap transactions		43			—
Commodity derivative transactions, net		(29	)		18
Cash collateral received (paid), net		(63	)		48
Decrease (increase) in operating assets-
Receivables		(156	)		32
Materials and supplies		(17	)		6
Prepayments and other current assets		(81	)		(179	)
Increase (decrease) in operating liabilities-
Accounts payable		18			(11	)
Accrued taxes		(58	)		(101	)
Other		27			27

Net cash provided from operating activities		858			1,102


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			1,679
Short-term borrowings, net		281			—
Redemptions and Repayments-
Long-term debt		(407	)		(881	)
Common stock dividend payments		(335	)		(335	)
Other		(23	)		(37	)

Net cash provided from (used for) financing activities		(484	)		426


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(997	)		(1,143	)
Proceeds from asset sales		116			19
Sales of investment securities held in trusts		1,915			1,001
Purchases of investment securities held in trusts		(1,934	)		(1,041	)
Customer acquisition costs		(105	)		—
Cash investments		59			40
Other		(21	)		(49	)

Net cash used for investing activities		(967	)		(1,173	)


Net change in cash and cash equivalents		(593	)		355
Cash and cash equivalents at beginning of period		874			545

Cash and cash equivalents at end of period	$	281		$	900

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

FIRSTENERGY SOLUTIONS CORP.

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
(In millions)

NET INCOME $ 230 $ 471 $ 754 $ 1,011

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (480 ) (20 ) 24 (60 )
Unrealized gain (loss) on derivative hedges 19 26 57 21
Change in unrealized gain on available-for-sale securities (108 ) (100 ) (76 ) (181 )
Other comprehensive income (loss) (569 ) (94 ) 5 (220 )
Income tax expense (benefit) related to other comprehensive income (216 ) (34 ) 26 (81 )
Other comprehensive income (loss), net of tax (353 ) (60 ) (21 ) (139 )

COMPREHENSIVE INCOME (LOSS) (123 ) 411 733 872

COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE
TO NONCONTROLLING INTEREST (4 ) - (14 ) 1

COMPREHENSIVE INCOME (LOSS) AVAILABLE TO FIRSTENERGY CORP. $ (119 ) $ 411 $ 747 $ 871

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

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
	*(In thousands)*
REVENUES:
Electric sales to affiliates	$	538,545		$	839,751		$	1,145,847		$	1,732,441
Electric sales to non-affiliates		728,803			205,379			1,397,488			485,125
Other		47,326			296,022			159,432			349,692

Total revenues		1,314,674			1,341,152			2,702,767			2,567,258


EXPENSES:
Fuel		342,411			270,309			670,632			576,467
Purchased power from affiliates		68,898			51,249			129,851			114,456
Purchased power from non-affiliates		298,820			185,613			749,035			345,955
Other operating expenses		303,895			278,264			608,406			585,620
Provision for depreciation		63,319			65,548			126,237			126,921
General taxes		22,272			21,285			49,018			44,661

Total expenses		1,099,615			872,268			2,333,179			1,794,080


OPERATING INCOME		215,059			468,884			369,588			773,178


OTHER INCOME (EXPENSE):
Investment income (loss)		13,366			5,643			14,083			(23,231	)
Miscellaneous income		4,393			7,622			5,703			10,133
Interest expense to affiliates		(2,560	)		(3,315	)		(4,865	)		(6,294	)
Interest expense — other		(51,372	)		(26,271	)		(101,016	)		(48,798	)
Capitalized interest		23,905			14,028			43,595			24,106

Total other expense		(12,268	)		(2,293	)		(42,500	)		(44,084	)


INCOME BEFORE INCOME TAXES		202,791			466,591			327,088			729,094

INCOME TAXES		68,866			169,189			113,237			261,011


NET INCOME		133,925			297,402			213,851			468,083


OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		885			72,121			(8,949	)		74,689
Unrealized gain on derivative hedges		3,017			15,041			4,291			26,057
Change in unrealized gain on available-for-sale securities		6,060			39,504			11,088			38,027

Other comprehensive income		9,962			126,666			6,430			138,773
Income tax expense related to other comprehensive income		3,544			50,625			2,204			55,334

Other comprehensive income, net of tax		6,418			76,041			4,226			83,439


TOTAL COMPREHENSIVE INCOME	$	140,343		$	373,443		$	218,077		$	551,522

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

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	11		$	12
Receivables-
Customers (less accumulated provisions of $14,523,000 and $12,041,000, respectively, for uncollectible accounts)		315,178			195,107
Associated companies		354,127			318,561
Other (less accumulated provisions of $6,702,000 for uncollectible accounts)		36,392			51,872
Notes receivable from associated companies		173,931			805,103
Materials and supplies, at average cost		578,521			539,541
Prepayments and other		172,514			107,782

		1,630,674			2,017,978

PROPERTY, PLANT AND EQUIPMENT:
In service		10,500,405			10,357,632
Less — Accumulated provision for depreciation		4,695,180			4,531,158

		5,805,225			5,826,474
Construction work in progress		2,622,865			2,423,446

		8,428,090			8,249,920

INVESTMENTS:
Nuclear plant decommissioning trusts		1,107,594			1,088,641
Other		7,965			22,466

		1,115,559			1,111,107

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		—			86,626
Customer intangibles		118,219			16,566
Goodwill		24,248			24,248
Property taxes		50,125			50,125
Unamortized sales and leaseback costs		77,646			72,553
Other		128,315			121,665

		398,553			371,783

	$	11,572,876		$	11,750,788

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	1,381,783		$	1,550,927
Short-term borrowings-
Associated companies		85,128			9,237
Other		100,000			100,000
Accounts payable-
Associated companies		412,507			466,078
Other		236,720			245,363
Accrued taxes		109,082			83,158
Other		369,086			359,057

		2,694,306			2,813,820

CAPITALIZATION:
Common stockholders’ equity-
Common stock, without par value, authorized 750 shares, 7 shares outstanding		1,467,158			1,468,423
Accumulated other comprehensive loss		(98,775	)		(103,001	)
Retained earnings		2,363,000			2,149,149

Total common stockholders’ equity		3,731,383			3,514,571
Long-term debt and other long-term obligations		2,585,918			2,711,652

		6,317,301			6,226,223

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		976,012			992,869
Accumulated deferred investment tax credits		56,310			58,396
Asset retirement obligations		863,409			921,448
Retirement benefits		223,853			204,035
Property taxes		50,125			50,125
Lease market valuation liability		239,447			262,200
Other		152,113			221,672

		2,561,269			2,710,745

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	11,572,876		$	11,750,788

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

FIRSTENERGY SOLUTIONS CORP.

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2009 2008
(In millions)
ASSETS

CURRENT ASSETS:
Cash and cash equivalents $ 838 $ 545
Receivables-
Customers (less accumulated provisions of $28 million for uncollectible accounts) 1,260 1,304
Other (less accumulated provisions of $9 million for uncollectible accounts) 132 167
Materials and supplies, at average cost 621 605
Prepaid taxes 585 283
Other 334 149
3,770 3,053
PROPERTY, PLANT AND EQUIPMENT:
In service 27,526 26,482
Less - Accumulated provision for depreciation 11,267 10,821
16,259 15,661
Construction work in progress 2,490 2,062
18,749 17,723
INVESTMENTS:
Nuclear plant decommissioning trusts 1,856 1,708
Investments in lease obligation bonds 553 598
Other 698 711
3,107 3,017
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 5,575 5,575
Regulatory assets 2,543 3,140
Power purchase contract asset 220 434
Other 710 579
9,048 9,728
$ 34,674 $ 33,521
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ 2,020 $ 2,476
Short-term borrowings 1,653 2,397
Accounts payable 692 794
Accrued taxes 257 333
Other 1,114 1,098
5,736 7,098
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 375,000,000 shares- 31 31
304,835,407 shares outstanding
Other paid-in capital 5,438 5,473
Accumulated other comprehensive loss (1,401 ) (1,380 )
Retained earnings 4,424 4,159
Total common stockholders' equity 8,492 8,283
Noncontrolling interest 1 32
Total equity 8,493 8,315
Long-term debt and other long-term obligations 11,647 9,100
20,140 17,415
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 2,562 2,163
Asset retirement obligations 1,401 1,335
Deferred gain on sale and leaseback transaction 1,001 1,027
Power purchase contract liability 685 766
Retirement benefits 1,500 1,884
Lease market valuation liability 274 308
Other 1,375 1,525
8,798 9,008
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
$ 34,674 $ 33,521

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	213,851		$	468,083
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		126,237			126,921
Nuclear fuel and lease amortization		78,324			53,265
Deferred rents and lease market valuation liability		(59,254	)		(55,493	)
Deferred income taxes and investment tax credits, net		113,978			63,309
Investment impairment		19,093			36,154
Accrued compensation and retirement benefits		7,132			(10,594	)
Commodity derivative transactions, net		(29,308	)		17,688
Gain on asset sales		(1,021	)		(9,635	)
Cash collateral, net		(38,211	)		40,471
Decrease (increase) in operating assets-
Receivables		(192,792	)		179,373
Materials and supplies		(28,470	)		16,609
Prepayments and other current assets		24,518			7,555
Increase (decrease) in operating liabilities-
Accounts payable		(31,610	)		(102,907	)
Accrued taxes		(8,462	)		(14,333	)
Accrued interest		(457	)		1,871
Other		24,907			(6,121	)

Net cash provided from operating activities		218,455			812,216


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			681,675
Short-term borrowings, net		75,891			145,009
Redemptions and Repayments-
Long-term debt		(295,037	)		(622,853	)
Other		(686	)		—

Net cash provided from (used for) financing activities		(219,832	)		203,831


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(566,187	)		(634,967	)
Proceeds from asset sales		115,657			15,771
Sales of investment securities held in trusts		956,813			537,078
Purchases of investment securities held in trusts		(978,785	)		(550,730	)
Loans from (to) associated companies, net		631,172			(241,170	)
Customer acquisition costs		(104,795	)		—
Leasehold improvement payments to associated companies		(51,204	)		—
Other		(1,295	)		(22,034	)

Net cash provided from (used for) investing activities		1,376			(896,052	)


Net change in cash and cash equivalents		(1	)		119,995
Cash and cash equivalents at beginning of period		12			39

Cash and cash equivalents at end of period	$	11		$	120,034

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

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
	*(In thousands)*
STATEMENTS OF INCOME

REVENUES:
Electric sales	$	415,437		$	647,224		$	895,362		$	1,367,235
Excise and gross receipts tax collections		23,949			24,948			52,424			53,928

Total revenues		439,386			672,172			947,786			1,421,163


EXPENSES:
Purchased power from affiliates		114,414			314,870			250,271			647,206
Purchased power from non-affiliates		98,462			98,330			210,513			236,143
Other operating expenses		88,275			111,938			177,130			269,768
Provision for depreciation		22,014			21,996			43,894			43,509
Amortization of regulatory assets, net		9,424			22,295			38,769			42,506
General taxes		43,362			43,903			90,854			93,023

Total expenses		375,951			613,332			811,431			1,332,155


OPERATING INCOME		63,435			58,840			136,355			89,008


OTHER INCOME (EXPENSE):
Investment income		6,309			10,149			11,553			19,511
Miscellaneous income		1,295			2,681			1,003			1,871
Interest expense		(22,155	)		(21,469	)		(44,465	)		(44,756	)
Capitalized interest		295			279			503			499

Total other expense		(14,256	)		(8,360	)		(31,406	)		(22,875	)


INCOME BEFORE INCOME TAXES		49,179			50,480			104,949			66,133

INCOME TAXES		11,856			16,852			31,465			20,857


NET INCOME		37,323			33,628			73,484			45,276


Noncontrolling interest income		130			143			262			289


EARNINGS AVAILABLE TO PARENT	$	37,193		$	33,485		$	73,222		$	44,987


STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	37,323		$	33,628		$	73,484		$	45,276


OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		322			89,864			4,337			95,602
Change in unrealized gain on available-for-sale securities		520			728			811			(1,981	)

Other comprehensive income		842			90,592			5,148			93,621
Income tax expense (benefit) related to other
comprehensive income		(26	)		37,310			667			37,839

Other comprehensive income, net of tax		868			53,282			4,481			55,782


COMPREHENSIVE INCOME		38,191			86,910			77,965			101,058

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		130			143			262			289


COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	38,061		$	86,767		$	77,703		$	100,769

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

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In millions)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 754 $ 1,011
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 550 500
Amortization of regulatory assets 903 795
Deferral of regulatory assets (136 ) (261 )
Nuclear fuel and lease amortization 92 82
Deferred purchased power and other costs (235 ) (138 )
Deferred income taxes and investment tax credits, net 421 278
Investment impairment 39 63
Deferred rents and lease market valuation liability (20 ) (62 )
Accrued compensation and retirement benefits 20 (127 )
Stock-based compensation (1 ) (74 )
Gain on asset sales (12 ) (43 )
Electric service prepayment programs (10 ) (58 )
Cash collateral, net (85 ) 21
Gain on investment securities held in trusts (172 ) (43 )
Loss on debt redemption 142 -
Pension trust contribution (500 ) -
Decrease (increase) in operating assets-
Receivables 78 (117 )
Materials and supplies 30 (34 )
Prepaid taxes (332 ) (259 )
Increase (decrease) in operating liabilities-
Accounts payable (103 ) (34 )
Accrued taxes (97 ) (166 )
Accrued interest 121 107
Other 17 (10 )
Net cash provided from operating activities 1,464 1,431

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 4,151 631
Short-term borrowings, net - 1,489
Redemptions and Repayments-
Long-term debt (2,213 ) (733 )
Short-term borrowings, net (764 ) -
Net controlled disbursement activity (15 ) 6
Common stock dividend payments (503 ) (503 )
Other (39 ) 21
Net cash provided from financing activities 617 911

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (1,575 ) (2,177 )
Proceeds from asset sales 19 64
Sales of investment securities held in trusts 3,039 1,144
Purchases of investment securities held in trusts (3,101 ) (1,215 )
Cash investments (4 ) 72
Restricted funds for debt redemption (150 ) (82 )
Other (16 ) (96 )
Net cash used for investing activities (1,788 ) (2,290 )

Net change in cash and cash equivalents 293 52
Cash and cash equivalents at beginning of period 545 129
Cash and cash equivalents at end of period $ 838 $ 181

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


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	51,679		$	324,175
Receivables-
Customers (less accumulated provisions of $4,685,000 and $5,119,000, respectively, for uncollectible accounts)		202,983			209,384
Associated companies		68,005			98,874
Other (less accumulated provisions of $6,000 and $18,000, respectively, for uncollectible accounts)		13,065			14,155
Notes receivable from associated companies		106,232			118,651
Prepayments and other		14,748			15,964

		456,712			781,203

UTILITY PLANT:
In service		3,086,689			3,036,467
Less — Accumulated provision for depreciation		1,189,802			1,165,394

		1,896,887			1,871,073
Construction work in progress		36,866			31,171

		1,933,753			1,902,244

OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		204,812			216,600
Nuclear plant decommissioning trusts		126,405			120,812
Other		96,633			96,861

		427,850			434,273

DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		422,559			465,331
Pension assets		36,199			19,881
Property taxes		67,037			67,037
Unamortized sales and leaseback costs		32,626			35,127
Other		17,765			39,881

		576,186			627,257

	$	3,394,501		$	3,744,977

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	7,975		$	2,723
Short-term borrowings-
Associated companies		—			92,863
Other		653			807
Accounts payable-
Associated companies		54,891			102,763
Other		31,087			40,423
Accrued taxes		55,976			81,868
Accrued interest		25,639			25,749
Other		79,382			81,424

		255,603			428,620

CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 175,000,000 shares - 60 shares outstanding		949,822			1,154,797
Accumulated other comprehensive loss		(159,096	)		(163,577	)
Retained earnings		58,112			29,890

Total common stockholder’s equity		848,838			1,021,110
Noncontrolling interest		6,100			6,442

Total equity		854,938			1,027,552
Long-term debt and other long-term obligations		1,152,303			1,160,208

		2,007,241			2,187,760

NONCURRENT LIABILITIES:
Accumulated deferred income taxes		678,669			660,114
Accumulated deferred investment tax credits		10,882			11,406
Retirement benefits		171,056			174,925
Asset retirement obligations		81,941			85,926
Other		189,109			196,226

		1,131,657			1,128,597

COMMITMENTS AND CONTINGENCIES (Note 8)
	$	3,394,501		$	3,744,977

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

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	73,484		$	45,276
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		43,894			43,509
Amortization of regulatory assets, net		38,769			42,506
Purchased power cost recovery reconciliation		(1,514	)		11,068
Amortization of lease costs		(4,619	)		(4,540	)
Deferred income taxes and investment tax credits, net		4,964			(11,252	)
Accrued compensation and retirement benefits		(16,154	)		(4,593	)
Accrued regulatory obligations		(2,309	)		18,350
Electric service prepayment programs		—			(4,603	)
Cash collateral from suppliers		1,215			6,380
Decrease (increase) in operating assets-
Receivables		49,250			(16,509	)
Prepayments and other current assets		5,072			(6,290	)
Increase (decrease) in operating liabilities-
Accounts payable		(57,208	)		(4,820	)
Accrued taxes		(25,685	)		(19,523	)
Accrued interest		(110	)		36
Other		(4	)		10,086

Net cash provided from operating activities		109,045			105,081


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			100,000
Short-term borrowings, net		—			114,617
Redemptions and Repayments-
Long-term debt		(2,957	)		(100,984	)
Short-term borrowings, net		(93,017	)		—
Common stock dividend payments		(250,000	)		(125,000	)
Other		(881	)		(1,627	)

Net cash used for financing activities		(346,855	)		(12,994	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(71,698	)		(69,512	)
Lease improvement payments from associated companies		18,375			—
Sales of investment securities held in trusts		59,804			24,941
Purchases of investment securities held in trusts		(64,063	)		(30,877	)
Loan repayments from associated companies, net		12,420			51,803
Cash investments		11,774			7,929
Other		(1,298	)		1,098

Net cash used for investing activities		(34,686	)		(14,618	)


Net change in cash and cash equivalents		(272,496	)		77,469
Cash and cash equivalents at beginning of period		324,175			146,343

Cash and cash equivalents at end of period	$	51,679		$	223,812

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009
2008
2009

2008

(In thousands)

REVENUES:
Electric sales to affiliates $ 616,300 $ 785,681 $ 2,348,741 $ 2,266,271
Electric sales to non-affiliates 443,819 381,483 928,944 994,100
Other 44,453 74,440 394,145 151,627
Total revenues 1,104,572 1,241,604 3,671,830 3,411,998

EXPENSES:
Fuel 294,693 349,946 871,160 982,185
Purchased power from non-affiliates 205,200 221,493 551,155 648,556
Purchased power from affiliates 35,290 15,821 149,746 75,834
Other operating expenses 305,935 279,184 891,555 863,468
Provision for depreciation 66,041 64,633 192,962 170,535
General taxes 21,700 21,736 66,361 64,728
Total expenses 928,859 952,813 2,722,939 2,805,306

OPERATING INCOME 175,713 288,791 948,891 606,692

OTHER INCOME (EXPENSE):
Investment income (loss) 158,857 11,961 135,723 (6,332 )
Miscellaneous income 2,804 6,466 12,840 19,781
Interest expense to affiliates (2,209 ) (8,015 ) (8,503 ) (25,953 )
Interest expense - other (42,187 ) (32,769 ) (90,985 ) (81,809 )
Capitalized interest 17,869 12,395 41,975 29,599
Total other income (expense) 135,134 (9,962 ) 91,050 (64,714 )

INCOME BEFORE INCOME TAXES 310,847 278,829 1,039,941 541,978

INCOME TAXES 111,164 93,174 372,175 198,245

NET INCOME 199,683 185,655 667,766 343,733

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (61,085 ) (1,821 ) 13,604 (5,462 )
Unrealized gain on derivative hedges 790 27,277 26,847 15,075
Change in unrealized gain on available-for-sale securities (89,401 ) (90,198 ) (51,374 ) (159,759 )
Other comprehensive loss (149,696 ) (64,742 ) (10,923 ) (150,146 )
Income tax benefit related to other comprehensive loss (58,883 ) (24,781 ) (3,549 ) (55,497 )
Other comprehensive loss, net of tax (90,813 ) (39,961 ) (7,374 ) (94,649 )

TOTAL COMPREHENSIVE INCOME $ 108,870 $ 145,694 $ 660,392 $ 249,084

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
	*(In thousands)*
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	280,180		$	458,287		$	592,677		$	889,692
Excise tax collections		15,495			16,799			33,068			35,119

Total revenues		295,675			475,086			625,745			924,811


EXPENSES:
Purchased power from affiliates		83,532			243,499			178,497			482,371
Purchased power from non-affiliates		48,541			49,414			100,367			121,160
Other operating expenses		28,937			39,177			60,172			104,007
Provision for depreciation		18,336			17,852			36,447			36,132
Amortization of regulatory assets		30,807			29,580			75,946			286,317
Deferral of new regulatory assets		—			(39,771	)		—			(134,587	)
General taxes		28,840			36,856			67,329			74,997

Total expenses		238,993			376,607			518,758			970,397


OPERATING INCOME (LOSS)		56,682			98,479			106,987			(45,586	)


OTHER INCOME (EXPENSE):
Investment income		6,605			7,614			14,152			16,034
Miscellaneous expense		675			798			1,257			2,792
Interest expense		(33,262	)		(32,757	)		(66,883	)		(66,079	)
Capitalized interest		7			51			33			118

Total other expense		(25,975	)		(24,294	)		(51,441	)		(47,135	)


INCOME (LOSS) BEFORE INCOME TAXES		30,707			74,185			55,546			(92,721	)

INCOME TAX EXPENSE (BENEFIT)		8,785			26,461			19,628			(35,045	)


NET INCOME (LOSS)		21,922			47,724			35,918			(57,676	)


Noncontrolling interest income		366			419			785			877


EARNINGS (LOSS) AVAILABLE TO PARENT	$	21,556		$	47,305		$	35,133		$	(58,553	)


STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME (LOSS)	$	21,922		$	47,724		$	35,918		$	(57,676	)


OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		3,228			43,903			(19,357	)		47,870
Income tax expense (benefit) related to other comprehensive income		976			17,936			(7,301	)		19,306

Other comprehensive income (loss), net of tax		2,252			25,967			(12,056	)		28,564


COMPREHENSIVE INCOME (LOSS)		24,174			73,691			23,862			(29,112	)

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		366			419			785			877


COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT	$	23,808		$	73,272		$	23,077		$	(29,989	)

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	245		$	86,230
Receivables-
Customers (less accumulated provisions of $4,809,000 and $5,239,000, respectively, for uncollectible accounts)		198,970			209,335
Associated companies		73,008			98,954
Other		10,377			11,661
Notes receivable from associated companies		24,480			26,802
Prepayments and other		4,390			9,973

		311,470			442,955

UTILITY PLANT:
In service		2,350,804			2,310,074
Less — Accumulated provision for depreciation		911,368			888,169

		1,439,436			1,421,905
Construction work in progress		30,665			36,907

		1,470,101			1,458,812

OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		340,033			388,641
Other		10,108			10,220

		350,141			398,861

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		468,119			545,505
Pension assets (Note 5)		—			13,380
Property taxes		77,319			77,319
Other		12,912			12,777

		2,246,872			2,337,502

	$	4,378,584		$	4,638,130

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	137		$	117
Short-term borrowings-
Associated companies		224,031			339,728
Accounts payable-
Associated companies		35,605			68,634
Other		15,707			17,166
Accrued taxes		77,051			90,511
Accrued interest		18,557			18,466
Other		49,897			45,440

		420,985			580,062

CAPITALIZATION:
Common stockholders’ equity-
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding		884,878			884,897
Accumulated other comprehensive loss		(150,214	)		(138,158	)
Retained earnings		532,380			597,248

Total common stockholders’ equity		1,267,044			1,343,987
Noncontrolling interest		18,017			20,592

Total equity		1,285,061			1,364,579
Long-term debt and other long-term obligations		1,852,488			1,872,750

		3,137,549			3,237,329

NONCURRENT LIABILITIES:
Accumulated deferred income taxes		632,696			644,745
Accumulated deferred investment tax credits		11,415			11,836
Retirement benefits		81,872			69,733
Other		94,067			94,425

		820,050			820,739

COMMITMENTS AND CONTINGENCIES (Note 8)
	$	4,378,584		$	4,638,130

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 266,958 $ 39
Receivables-
Customers (less accumulated provisions of $4,676,000 and $5,899,000,
respectively, for uncollectible accounts) 155,489 86,123
Associated companies 344,387 378,100
Other (less accumulated provisions of $6,702,000 and $6,815,000
respectively, for uncollectible accounts) 47,579 24,626
Notes receivable from associated companies 428,016 129,175
Materials and supplies, at average cost 528,278 521,761
Prepayments and other 120,362 112,535
1,891,069 1,252,359
PROPERTY, PLANT AND EQUIPMENT:
In service 10,254,698 9,871,904
Less - Accumulated provision for depreciation 4,487,832 4,254,721
5,766,866 5,617,183
Construction work in progress 2,195,999 1,747,435
7,962,865 7,364,618
INVESTMENTS:
Nuclear plant decommissioning trusts 1,101,884 1,033,717
Long-term notes receivable from associated companies 8,817 62,900
Other 26,642 61,591
1,137,343 1,158,208
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits 38,099 267,762
Lease assignment receivable from associated companies 71,356 71,356
Goodwill 24,248 24,248
Property taxes 50,104 50,104
Unamortized sale and leaseback costs 58,350 69,932
Other 226,134 96,434
468,291 579,836
$ 11,459,568 $ 10,355,021
LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt $ 1,631,766 $ 2,024,898
Short-term borrowings-
Associated companies - 264,823
Other 100,000 1,000,000
Accounts payable-
Associated companies 387,182 472,338
Other 156,053 154,593
Accrued taxes 105,574 79,766
Other 227,788 248,439
2,608,363 4,244,857
CAPITALIZATION:
Common stockholder's equity -
Common stock, without par value, authorized 750 shares,
7 shares outstanding 1,466,697 1,464,229
Accumulated other comprehensive loss (99,245 ) (91,871 )
Retained earnings 2,239,831 1,572,065
Total common stockholder's equity 3,607,283 2,944,423
Long-term debt and other long-term obligations 2,640,092 571,448
6,247,375 3,515,871
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction 1,001,298 1,026,584
Accumulated deferred investment tax credits 59,479 62,728
Asset retirement obligations 906,199 863,085
Retirement benefits 200,097 194,177
Property taxes 50,104 50,104
Lease market valuation liability 273,624 307,705
Other 113,029 89,910
2,603,830 2,594,293
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 11,459,568 $ 10,355,021

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	35,918		$	(57,676	)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation		36,447			36,132
Amortization of regulatory assets, net		75,946			286,317
Deferral of new regulatory assets		—			(134,587	)
Purchased power cost recovery reconciliation		—			2,072
Deferred income taxes and investment tax credits, net		(18,083	)		(58,506	)
Accrued compensation and retirement benefits		5,421			2,092
Accrued regulatory obligations		(444	)		12,057
Electric service prepayment programs		—			(3,510	)
Cash collateral from suppliers		685			5,365
Decrease (increase) in operating assets-
Receivables		51,757			(84,469	)
Prepayments and other current assets		5,392			(1,145	)
Increase (decrease) in operating liabilities-
Accounts payable		(34,488	)		18,991
Accrued taxes		(11,317	)		(29,434	)
Accrued interest		91			232
Other		1,932			3,265

Net cash provided from (used for) operating activities		149,257			(2,804	)


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		—			47,423
Redemptions and Repayments-
Long-term debt		(54	)		(368	)
Short-term borrowings, net		(136,013	)		—
Common stock dividend payments		(100,000	)		(25,000	)
Other		(3,367	)		(3,019	)

Net cash provided from (used for) financing activities		(239,434	)		19,036


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(44,373	)		(46,434	)
Loan repayments from (loans to) associated companies, net		2,322			(5,449	)
Redemptions of lessor notes		48,608			37,070
Other		(2,365	)		(1,415	)

Net cash provided from (used for) investing activities		4,192			(16,228	)


Net change in cash and cash equivalents		(85,985	)		4
Cash and cash equivalents at beginning of period		86,230			226

Cash and cash equivalents at end of period	$	245		$	230

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
	*(In thousands)*
STATEMENTS OF INCOME

REVENUES:
Electric sales	$	114,691		$	219,911		$	240,122		$	456,996
Excise tax collections		6,059			6,297			13,100			14,026

Total revenues		120,750			226,208			253,222			471,022


EXPENSES:
Purchased power from affiliates		38,654			130,564			85,654			255,888
Purchased power from non-affiliates		23,675			18,244			49,784			58,781
Other operating expenses		25,499			35,480			51,044			80,484
Provision for depreciation		8,013			7,717			15,963			15,289
Amortization (deferral) of regulatory assets, net		(1,800	)		11,771			(10,299	)		21,668
General taxes		12,282			12,349			25,743			26,599

Total expenses		106,323			216,125			217,889			458,709


OPERATING INCOME		14,427			10,083			35,333			12,313


OTHER INCOME (EXPENSE):
Investment income		5,057			7,529			8,857			13,013
Miscellaneous income (expense)		(945	)		1,375			(2,351	)		35
Interest expense		(10,455	)		(9,262	)		(20,942	)		(14,795	)
Capitalized interest		80			50			158			92

Total other expense		(6,263	)		(308	)		(14,278	)		(1,655	)


INCOME BEFORE INCOME TAXES		8,164			9,775			21,055			10,658

INCOME TAXES		948			3,370			6,330			3,261


NET INCOME		7,216			6,405			14,725			7,397


Noncontrolling interest income		2			1			5			3


EARNINGS AVAILABLE TO PARENT	$	7,214		$	6,404		$	14,720		$	7,394


STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME	$	7,216		$	6,405		$	14,725		$	7,397


OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits		714			19,016			1,010			19,149
Change in unrealized gain on available-for-sale securities		(330	)		(2,739	)		39			(3,548	)

Other comprehensive income		384			16,277			1,049			15,601
Income tax expense related to other comprehensive income		65			7,224			235			7,205

Other comprehensive income, net of tax		319			9,053			814			8,396


COMPREHENSIVE INCOME		7,535			15,458			15,539			15,793

COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		2			1			5			3


COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	7,533		$	15,457		$	15,534		$	15,790

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

THE TOLEDO EDISON COMPANY

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30

2009

2008

(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 667,766 $ 343,733
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 192,962 170,535
Nuclear fuel and lease amortization 94,244 81,950
Deferred rents and lease market valuation liability (40,143 ) (36,702 )
Deferred income taxes and investment tax credits, net 268,812 91,082
Investment impairment 36,169 58,173
Accrued compensation and retirement benefits 5,860 (2,110 )
Commodity derivative transactions, net 25,794 3,634
Gain on asset sales (9,832 ) (11,319 )
Gain on investment securities held in trusts (154,723 ) (34,032 )
Cash collateral, net (92,618 ) (8,827 )
Decrease (increase) in operating assets:
Receivables (55,774 ) 106,574
Materials and supplies 38,543 (35,498 )
Prepayments and other current assets (35,315 ) (10,762 )
Increase (decrease) in operating liabilities:
Accounts payable (72,181 ) (61,035 )
Accrued taxes 23,846 (90,767 )
Accrued interest 31,770 15,420
Other (43,369 ) (25,916 )
Net cash provided from operating activities 881,811 554,133

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 2,356,762 537,375
Equity contribution from parent - 280,000
Short-term borrowings, net - 747,686
Redemptions and Repayments-
Long-term debt (618,213 ) (460,902 )
Short-term borrowings, net (1,164,823 ) -
Common stock dividend payments - (43,000 )
Other (20,006 ) -
Net cash provided from financing activities 553,720 1,061,159

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (842,600 ) (1,417,205 )
Proceeds from asset sales 16,129 15,218
Sales of investment securities held in trusts 2,152,717 596,291
Purchases of investment securities held in trusts (2,175,135 ) (624,899 )
Loans to associated companies, net (298,841 ) (64,142 )
Restricted funds for debt redemption - (81,640 )
Other (20,882 ) (38,915 )
Net cash used for investing activities (1,168,612 ) (1,615,292 )

Net change in cash and cash equivalents 266,919 -
Cash and cash equivalents at beginning of period 39 2
Cash and cash equivalents at end of period $ 266,958 $ 2

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

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	77,843		$	436,712
Receivables-
Customers		128			75
Associated companies		52,068			90,191
Other (less accumulated provisions of $298,000 and $208,000, respectively, for uncollectible accounts)		18,866			20,180
Notes receivable from associated companies		95,919			85,101
Prepayments and other		3,503			7,111

		248,327			639,370

UTILITY PLANT:
In service		932,788			912,930
Less — Accumulated provision for depreciation		437,327			427,376

		495,461			485,554
Construction work in progress		7,906			9,069

		503,367			494,623

OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		103,872			124,357
Nuclear plant decommissioning trusts		75,540			73,935
Other		1,539			1,580

		180,951			199,872

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576			500,576
Regulatory assets		81,799			69,557
Property taxes		23,658			23,658
Other		38,655			55,622

		644,688			649,413

	$	1,577,333		$	1,983,278

LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	216		$	222
Accounts payable-
Associated companies		16,535			78,341
Other		6,972			8,312
Notes payable to associated companies		—			225,975
Accrued taxes		20,069			25,734
Lease market valuation liability		36,900			36,900
Other		22,244			29,273

		102,936			404,757

CAPITALIZATION:
Common stockholders’ equity-
Common stock, $5 par value, authorized 60,000,000 shares, 29,402,054 shares outstanding		147,010			147,010
Other paid-in-capital		178,136			178,181
Accumulated other comprehensive loss		(48,989	)		(49,803	)
Retained earnings		99,210			214,490

Total common stockholders’ equity		375,367			489,878
Noncontrolling interest		2,590			2,696

Total equity		377,957			492,574
Long-term debt and other long-term obligations		600,463			600,443

		978,420			1,093,017

NONCURRENT LIABILITIES:
Accumulated deferred income taxes		112,670			80,508
Accumulated deferred investment tax credits		6,148			6,367
Retirement benefits		67,507			65,988
Asset retirement obligations		27,819			32,290
Lease market valuation liability		217,750			236,200
Other		64,083			64,151

		495,977			485,504

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	1,577,333		$	1,983,278

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	14,725		$	7,397
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		15,963			15,289
Amortization (deferral) of regulatory assets, net		(10,299	)		21,668
Purchased power cost recovery reconciliation		60			(4,197	)
Deferred rents and lease market valuation liability		(42,264	)		(40,697	)
Deferred income taxes and investment tax credits, net		16,503			(1,206	)
Accrued compensation and retirement benefits		2,600			711
Accrued regulatory obligations		(632	)		4,450
Electric service prepayment programs		—			(1,458	)
Cash collateral from suppliers		343			2,755
Decrease (increase) in operating assets-
Receivables		52,754			1,075
Prepayments and other current assets		3,608			(220	)
Increase (decrease) in operating liabilities-
Accounts payable		(61,195	)		5,533
Accrued taxes		(4,007	)		(2,936	)
Accrued interest		—			3,983
Other		(9,020	)		1,788

Net cash provided from (used for) operating activities		(20,861	)		13,935


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			297,422
Short-term borrowings, net		—			59,938
Redemptions and Repayments-
Long-term debt		(111	)		(236	)
Short-term borrowings, net		(225,975	)		—
Common stock dividend payments		(130,000	)		(25,000	)
Other		(112	)		(247	)

Net cash provided from (used for) financing activities		(356,198	)		331,877


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(20,237	)		(21,661	)
Leasehold improvement payments from associated companies		32,829			—
Loans to associated companies, net		(10,818	)		(19,819	)
Redemptions of lessor notes		20,485			18,330
Sales of investment securities held in trusts		106,814			77,323
Purchases of investment securities held in trusts		(107,978	)		(78,700	)
Other		(2,905	)		(1,845	)

Net cash provided from (used for) investing activities		18,190			(26,372	)


Net change in cash and cash equivalents		(358,869	)		319,440
Cash and cash equivalents at beginning of period		436,712			14

Cash and cash equivalents at end of period	$	77,843		$	319,454

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

JERSEY CENTRAL POWER & LIGHT COMPANY

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009
2008

2009

2008

(In thousands)
STATEMENTS OF INCOME

REVENUES:
Electric sales $ 575,377 $ 671,761 $ 1,942,612 $ 1,877,300
Excise and gross receipts tax collections 27,127 30,500 81,055 87,165
Total revenues 602,504 702,261 2,023,667 1,964,465

EXPENSES:
Purchased power from affiliates 200,506 313,912 847,712 913,647
Purchased power from non-affiliates 161,732 35,462 397,875 83,962
Other operating costs 102,463 146,048 372,231 423,993
Provision for depreciation 22,407 14,997 65,916 57,904
Amortization of regulatory assets, net 17,404 42,582 59,910 87,664
General taxes 45,164 49,255 138,187 144,097
Total expenses 549,676 602,256 1,881,831 1,711,267

OPERATING INCOME 52,828 100,005 141,836 253,198

OTHER INCOME (EXPENSE):
Investment income 20,285 19,323 39,796 45,866
Miscellaneous income (expense) 237 (938 ) 2,108 (4,716 )
Interest expense (22,961 ) (17,309 ) (67,717 ) (51,851 )
Capitalized interest 231 55 730 324
Total other income (expense) (2,208 ) 1,131 (25,083 ) (10,377 )

INCOME BEFORE INCOME TAXES 50,620 101,136 116,753 242,821

INCOME TAXES 15,885 28,501 36,742 77,122

NET INCOME 34,735 72,635 80,011 165,699

Noncontrolling interest income 140 151 429 464

EARNINGS AVAILABLE TO PARENT $ 34,595 $ 72,484 $ 79,582 $ 165,235

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME $ 34,735 $ 72,635 $ 80,011 $ 165,699

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (49,043 ) (3,994 ) 46,559 (11,982 )
Change in unrealized gain on available-for-sale securities (7,695 ) (9,936 ) (9,676 ) (20,310 )
Other comprehensive income (loss) (56,738 ) (13,930 ) 36,883 (32,292 )
Income tax expense (benefit) related to other comprehensive income (21,924 ) (5,105 ) 15,915 (11,931 )
Other comprehensive income (loss), net of tax (34,814 ) (8,825 ) 20,968 (20,361 )

COMPREHENSIVE INCOME (LOSS) (79 ) 63,810 100,979 145,338

COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST 140 151 429 464

COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT $ (219 ) $ 63,659 $ 100,550 $ 144,874

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

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
				*(In thousands)*
REVENUES:
Electric sales	$	709,606		$	697,061		$	1,400,998		$	1,457,981
Excise tax collections		11,012			11,031			23,364			23,762

Total revenues		720,618			708,092			1,424,362			1,481,743


EXPENSES:
Purchased power		410,470			423,950			824,486			905,191
Other operating expenses		75,177			70,876			170,837			156,746
Provision for depreciation		27,093			25,301			55,064			50,404
Amortization of regulatory assets, net		81,326			80,018			150,774			166,849
General taxes		14,902			12,587			31,338			30,083

Total expenses		608,968			612,732			1,232,499			1,309,273


OPERATING INCOME		111,650			95,360			191,863			172,470


OTHER INCOME (EXPENSE):
Miscellaneous income		1,649			2,007			3,482			2,812
Interest expense		(30,041	)		(29,671	)		(59,464	)		(57,539	)
Capitalized interest		156			218			289			280

Total other expense		(28,236	)		(27,446	)		(55,693	)		(54,447	)


INCOME BEFORE INCOME TAXES		83,414			67,914			136,170			118,023

INCOME TAXES		33,521			29,848			57,051			52,399


NET INCOME		49,893			38,066			79,119			65,624


OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		4,135			20,918			20,063			25,039
Unrealized gain on derivative hedges		69			69			138			138

Other comprehensive income		4,204			20,987			20,201			25,177
Income tax expense related to other comprehensive income		1,441			11,059			7,999			12,489

Other comprehensive income, net of tax		2,763			9,928			12,202			12,688


TOTAL COMPREHENSIVE INCOME	$	52,656		$	47,994		$	91,321		$	78,312

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	99		$	27
Receivables-
Customers (less accumulated provisions of $3,362,000 and $3,506,000, respectively, for uncollectible accounts)		345,136			300,991
Associated companies		11,778			12,884
Other		25,626			21,877
Notes receivable — associated companies		17,883			102,932
Prepaid taxes		146,898			34,930
Other		11,357			12,945

		558,777			486,586


UTILITY PLANT:
In service		4,524,706			4,463,490
Less — Accumulated provision for depreciation		1,651,304			1,617,639

		2,873,402			2,845,851
Construction work in progress		55,825			54,251

		2,929,227			2,900,102


OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		166,148			166,768
Nuclear fuel disposal trust		204,088			199,677
Other		2,209			2,149

		372,445			368,594


DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,810,936			1,810,936
Regulatory assets		800,898			888,143
Other		29,849			27,096

		2,641,683			2,726,175

	$	6,502,132		$	6,481,457


LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	31,508		$	30,639
Short-term borrowings-
Associated companies		57,850			—
Accounts payable-
Associated companies		15,158			26,882
Other		202,049			168,093
Accrued taxes		1,786			12,594
Accrued interest		18,189			18,256
Other		82,524			111,156

		409,064			367,620


CAPITALIZATION:
Common stockholders’ equity-
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding		136,284			136,284
Other paid-in capital		2,507,003			2,507,049
Accumulated other comprehensive loss		(230,810	)		(243,012	)
Retained earnings		189,194			200,075

Total common stockholders’ equity		2,601,671			2,600,396
Long-term debt and other long-term obligations		1,787,235			1,801,589

		4,388,906			4,401,985


NONCURRENT LIABILITIES:
Accumulated deferred income taxes		705,219			687,545
Nuclear fuel disposal costs		196,623			196,511
Retirement benefits		132,565			150,603
Asset retirement obligations		104,878			101,568
Power purchase contract liability		378,448			399,105
Other		186,429			176,520

		1,704,162			1,711,852

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	6,502,132		$	6,481,457

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

JERSEY CENTRAL POWER & LIGHT COMPANY

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 329,745 $ 146,343
Receivables-
Customers (less accumulated provisions of $6,113,000 and $6,065,000, respectively,
for uncollectible accounts) 217,775 277,377
Associated companies 163,407 234,960
Other (less accumulated provisions of $17,000 and $7,000, respectively,
for uncollectible accounts) 16,862 14,492
Notes receivable from associated companies 89,410 222,861
Prepayments and other 15,394 5,452
832,593 901,485
UTILITY PLANT:
In service 2,993,708 2,903,290
Less - Accumulated provision for depreciation 1,148,804 1,113,357
1,844,904 1,789,933
Construction work in progress 32,292 37,766
1,877,196 1,827,699
OTHER PROPERTY AND INVESTMENTS:
Long-term notes receivable from associated companies 192,550 256,974
Investment in lease obligation bonds 230,025 239,625
Nuclear plant decommissioning trusts 121,638 116,682
Other 97,949 100,792
642,162 714,073
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets 493,955 575,076
Pension assets 17,336 -
Property taxes 60,542 60,542
Unamortized sale and leaseback costs 36,378 40,130
Other 33,695 33,710
641,906 709,458
$ 3,993,857 $ 4,152,715
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 2,719 $ 101,354
Short-term borrowings-
Associated companies 75,002 -
Other 1,052 1,540
Accounts payable-
Associated companies 61,507 131,725
Other 36,503 26,410
Accrued taxes 73,666 77,592
Accrued interest 25,614 25,673
Other 127,056 85,209
403,119 449,503
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares -
60 shares outstanding 1,228,463 1,224,416
Accumulated other comprehensive loss (163,417 ) (184,385 )
Retained earnings 183,605 254,023
Total common stockholder's equity 1,248,651 1,294,054
Noncontrolling interest 6,975 7,106
Total equity 1,255,626 1,301,160
Long-term debt and other long-term obligations 1,161,237 1,122,247
2,416,863 2,423,407
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 699,399 653,475
Accumulated deferred investment tax credits 11,969 13,065
Asset retirement obligations 84,600 80,647
Retirement benefits 179,549 308,450
Other 198,358 224,168
1,173,875 1,279,805
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 3,993,857 $ 4,152,715

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	79,119		$	65,624
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		55,064			50,404
Amortization of regulatory assets, net		150,774			166,849
Deferred purchased power and other costs		(67,664	)		(50,542	)
Deferred income taxes and investment tax credits, net		(1,425	)		3,440
Accrued compensation and retirement benefits		2,608			(2,883	)
Cash collateral paid, net		(23,400	)		(209	)
Decrease (increase) in operating assets-
Receivables		(46,788	)		41,228
Prepayments and other current assets		(112,155	)		(145,740	)
Increase (decrease) in operating liabilities-
Accounts payable		11,924			(19,321	)
Accrued taxes		10,368			(14,007	)
Accrued interest		(67	)		9,373
Tax collections payable		—			(9,714	)
Other		(6,192	)		4,555

Net cash provided from operating activities		52,166			99,057


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			299,619
Short-term borrowings, net		57,850			—
Redemptions and Repayments-
Common stock		—			(150,000	)
Long-term debt		(13,830	)		(13,093	)
Short-term borrowings, net		—			(56,267	)
Common stock dividend payments		(90,000	)		(88,000	)
Other		—			(2,260	)

Net cash used for financing activities		(45,980	)		(10,001	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(80,727	)		(78,401	)
Loan repayments from (loans to) associated companies, net		85,049			(1,341	)
Sales of investment securities held in trusts		281,242			244,880
Purchases of investment securities held in trusts		(289,454	)		(252,856	)
Other		(2,224	)		(1,266	)

Net cash used for investing activities		(6,114	)		(88,984	)


Net change in cash and cash equivalents		72			72
Cash and cash equivalents at beginning of period		27			66

Cash and cash equivalents at end of period	$	99		$	138

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
				*(In thousands)*
REVENUES:
Electric sales	$	422,030		$	360,022		$	873,590		$	769,708
Gross receipts tax collections		20,629			17,586			42,196			37,569

Total revenues		442,659			377,608			915,786			807,277


EXPENSES:
Purchased power from affiliates		149,000			78,652			310,080			178,729
Purchased power from non-affiliates		85,276			123,299			177,204			247,210
Other operating expenses		90,151			51,309			192,134			157,666
Provision for depreciation		13,440			12,919			26,198			25,058
Amortization of regulatory assets, net		48,589			61,548			97,389			89,139
General taxes		19,894			22,034			41,634			43,969

Total expenses		406,350			349,761			844,639			741,771


OPERATING INCOME		36,309			27,847			71,147			65,506


OTHER INCOME (EXPENSE):
Interest income		880			2,769			2,097			5,955
Miscellaneous income		1,381			1,058			3,554			1,914
Interest expense		(13,002	)		(14,763	)		(26,775	)		(28,122	)
Capitalized interest		159			62			285			77

Total other expense		(10,582	)		(10,874	)		(20,839	)		(20,176	)


INCOME BEFORE INCOME TAXES		25,727			16,973			50,308			45,330

INCOME TAXES		8,618			6,968			20,884			18,703


NET INCOME		17,109			10,005			29,424			26,627


OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		2,162			27,369			11,871			31,922
Unrealized gain on derivative hedges		84			84			168			168

Other comprehensive income		2,246			27,453			12,039			32,090
Income tax expense related to other comprehensive income		724			13,592			4,901			15,385

Other comprehensive income, net of tax		1,522			13,861			7,138			16,705


TOTAL COMPREHENSIVE INCOME	$	18,631		$	23,866		$	36,562		$	43,332

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	126		$	120
Receivables-
Customers (less accumulated provisions of $3,877,000 and $4,044,000, respectively, for uncollectible accounts)		188,771			171,052
Associated companies		45,551			29,413
Other		13,221			11,650
Notes receivable from associated companies		11,207			97,150
Prepaid taxes		46,475			15,229
Other		649			1,459

		306,000			326,073

UTILITY PLANT:
In service		2,196,713			2,162,815
Less — Accumulated provision for depreciation		830,042			810,746

		1,366,671			1,352,069
Construction work in progress		30,214			14,901

		1,396,885			1,366,970

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		263,752			266,479
Other		881			890

		264,633			267,369

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499			416,499
Regulatory assets		385,392			356,754
Power purchase contract asset		120,436			176,111
Other		42,546			36,544

		964,873			985,908

	$	2,932,391		$	2,946,320


LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,500		$	128,500
Short-term borrowings-
Associated companies		17,898			—
Accounts payable-
Associated companies		51,308			40,521
Other		30,997			41,050
Accrued taxes		20,689			11,170
Accrued interest		16,085			17,362
Other		28,588			24,520

		194,065			263,123

CAPITALIZATION:
Common stockholders’ equity-
Common stock, without par value, authorized 900,000 shares, 859,500 shares outstanding		1,197,014			1,197,070
Accumulated other comprehensive loss		(136,413	)		(143,551	)
Retained earnings		33,824			4,399

Total common stockholders’ equity		1,094,425			1,057,918
Long-term debt and other long-term obligations		713,920			713,873

		1,808,345			1,771,791

NONCURRENT LIABILITIES:
Accumulated deferred income taxes		454,777			453,462
Accumulated deferred investment tax credits		7,090			7,313
Nuclear fuel disposal costs		44,416			44,391
Retirement benefits		29,194			33,605
Asset retirement obligations		186,373			180,297
Power purchase contract liability		158,987			143,135
Other		49,144			49,203

		929,981			911,406

COMMITMENTS AND CONTINGENCIES (Note 8)
	$	2,932,391		$	2,946,320

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

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 80,011 $ 165,699
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 65,916 57,904
Amortization of regulatory assets, net 59,910 87,664
Purchased power cost recovery reconciliation 15,372 -
Amortization of lease costs 28,394 28,535
Deferred income taxes and investment tax credits, net 32,658 17,267
Accrued compensation and retirement benefits (3,542 ) (41,190 )
Accrued regulatory obligations 19,172 -
Electric service prepayment programs (4,634 ) (31,895 )
Cash collateral from suppliers 6,469 -
Pension trust contributions (103,035 ) -
Decrease (increase) in operating assets-
Receivables 128,688 (26,009 )
Prepayments and other current assets (2,553 ) 2,065
Decrease in operating liabilities-
Accounts payable (60,125 ) (27,463 )
Accrued taxes (17,196 ) (27,776 )
Accrued interest (59 ) (8,162 )
Other (8,596 ) (1,307 )
Net cash provided from operating activities 236,850 195,332

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 100,000 -
Short-term borrowings, net 74,514 189,148
Redemptions and Repayments-
Long-term debt (101,088 ) (175,583 )
Dividend Payments-
Common stock (150,000 ) (315,000 )
Other (2,138 ) (445 )
Net cash used for financing activities (78,712 ) (301,880 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (108,253 ) (135,450 )
Sales of investment securities held in trusts 207,280 115,988
Purchases of investment securities held in trusts (214,592 ) (121,871 )
Loan repayments from associated companies, net 134,975 234,577
Cash investments 7,070 5,143
Other (1,216 ) 8,144
Net cash provided from investing activities 25,264 106,531

Net increase (decrease) in cash and cash equivalents 183,402 (17 )
Cash and cash equivalents at beginning of period 146,343 732
Cash and cash equivalents at end of period $ 329,745 $ 715

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

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	29,424		$	26,627
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		26,198			25,058
Amortization of regulatory assets, net		97,389			89,139
Deferral of regulatory assets		(38,358	)		(47,592	)
Deferred income taxes and investment tax credits, net		(12,079	)		30,135
Accrued compensation and retirement benefits		(1,573	)		3,250
Cash collateral received (paid), net		50			(6,800	)
Decrease (increase) in operating assets-
Receivables		(29,439	)		346
Prepayments and other current assets		(30,436	)		(39,068	)
Increase (decrease) in operating liabilities-
Accounts payable		733			(18,624	)
Accrued taxes		9,519			(1,754	)
Accrued interest		(1,277	)		10,230
Other		6,743			7,870

Net cash provided from operating activities		56,894			78,817


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			300,000
Short-term borrowings, net		17,898			—
Redemptions and Repayments-
Long-term debt		(100,000	)		—
Short-term borrowings, net		—			(15,003	)
Other		—			(2,267	)

Net cash provided from (used for) financing activities		(82,102	)		282,730


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(54,405	)		(48,464	)
Sales of investment securities held in trusts		376,610			63,086
Purchases of investment securities held in trusts		(381,219	)		(67,668	)
Loans from (to) associated companies, net		85,943			(306,448	)
Other		(1,715	)		(2,072	)

Net cash provided from (used for) investing activities		25,214			(361,566	)


Net change in cash and cash equivalents		6			(19	)
Cash and cash equivalents at beginning of period		120			144

Cash and cash equivalents at end of period	$	126		$	125

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
				*(In thousands)*
REVENUES:
Electric sales	$	350,335		$	316,881		$	736,271		$	688,174
Gross receipts tax collections		16,162			14,804			33,686			32,096

Total revenues		366,497			331,685			769,957			720,270


EXPENSES:
Purchased power from affiliates		152,945			72,166			321,345			168,247
Purchased power from non-affiliates		86,829			125,317			178,252			252,483
Other operating expenses		67,070			46,301			139,464			123,590
Provision for depreciation		16,605			15,581			31,287			30,036
Amortization (deferral) of regulatory assets, net		(10,522	)		18,113			(20,488	)		26,889
General taxes		18,647			18,251			35,181			38,844

Total expenses		331,574			295,729			685,041			640,089


OPERATING INCOME		34,923			35,956			84,916			80,181


OTHER INCOME (EXPENSE):
Miscellaneous income		1,310			911			2,923			1,709
Interest expense		(17,630	)		(11,843	)		(34,920	)		(25,076	)
Capitalized interest		183			29			323			51

Total other expense		(16,137	)		(10,903	)		(31,674	)		(23,316	)


INCOME BEFORE INCOME TAXES		18,786			25,053			53,242			56,865

INCOME TAXES		5,812			10,232			22,969			23,354


NET INCOME		12,974			14,821			30,273			33,511


OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1,830			29,400			10,377			32,355
Unrealized gain on derivative hedges		16			16			32			32
Change in unrealized gain on available-for-sale securities		—			6			—			(16	)

Other comprehensive income		1,846			29,422			10,409			32,371
Income tax expense related to other comprehensive income		483			15,100			3,767			16,155

Other comprehensive income, net of tax		1,363			14,322			6,642			16,216


TOTAL COMPREHENSIVE INCOME	$	14,337		$	29,143		$	36,915		$	49,727

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009

2008

2009

2008

STATEMENTS OF INCOME (In thousands)

REVENUES:
Electric sales $ 417,900 $ 505,425 $ 1,307,592 $ 1,342,327
Excise tax collections 17,629 18,652 52,748 53,447
Total revenues 435,529 524,077 1,360,340 1,395,774

EXPENSES:
Purchased power from affiliates 153,556 211,417 635,927 587,203
Purchased power from non-affiliates 87,689 28 208,849 3,097
Other operating costs 37,822 66,342 141,829 194,119
Provision for depreciation 17,753 17,677 53,885 54,497
Amortization of regulatory assets 39,313 48,155 325,630 124,936
Deferral of new regulatory assets - (16,176 ) (134,587 ) (71,443 )
General taxes 37,752 36,722 112,749 109,230
Total expenses 373,885 364,165 1,344,282 1,001,639

OPERATING INCOME 61,644 159,912 16,058 394,135

OTHER INCOME (EXPENSE):
Investment income 7,565 8,390 23,599 25,972
Miscellaneous income (expense) 645 (656 ) 3,437 182
Interest expense (34,740 ) (31,024 ) (100,819 ) (94,479 )
Capitalized interest 27 200 145 584
Total other expense (26,503 ) (23,090 ) (73,638 ) (67,741 )

INCOME (LOSS) BEFORE INCOME TAXES 35,141 136,822 (57,580 ) 326,394

INCOME TAX EXPENSE (BENEFIT) 9,755 42,977 (25,290 ) 107,082

NET INCOME (LOSS) 25,386 93,845 (32,290 ) 219,312

Noncontrolling interest income 418 458 1,295 1,501

EARNINGS (LOSS) AVAILABLE TO PARENT $ 24,968 $ 93,387 $ (33,585 ) $ 217,811

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME (LOSS) $ 25,386 $ 93,845 $ (32,290 ) $ 219,312

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (48,024 ) (213 ) (154 ) (639 )
Unrealized loss on derivative hedges (1,451 ) - (1,451 ) -
Other comprehensive loss (49,475 ) (213 ) (1,605 ) (639 )
Income tax expense (benefit) related to other comprehensive income (17,854 ) (130 ) 1,452 (239 )
Other comprehensive loss, net of tax (31,621 ) (83 ) (3,057 ) (400 )

COMPREHENSIVE INCOME (LOSS) (6,235 ) 93,762 (35,347 ) 218,912

COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST 418 458 1,295 1,501

COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT $ (6,653 ) $ 93,304 $ (36,642 ) $ 217,411

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

CONSOLIDATED BALANCE SHEETS
(Unaudited)


	June 30,			December 31,
	2010			2009
	*(In thousands)*
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10		$	14
Receivables-
Customers (less accumulated provisions of $3,428,000 and $3,483,000, respectively, for uncollectible accounts)		137,450			139,302
Associated companies		88,612			77,338
Other		10,934			18,320
Notes receivable from associated companies		14,092			14,589
Prepaid taxes		56,450			18,946
Other		758			1,400

		308,306			269,909

UTILITY PLANT:
In service		2,481,942			2,431,737
Less — Accumulated provision for depreciation		918,963			901,990

		1,562,979			1,529,747
Construction work in progress		22,319			24,205

		1,585,298			1,553,952

OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		140,611			142,603
Non-utility generation trusts		96,988			120,070
Other		283			289

		237,882			262,962

DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Regulatory assets		138,557			9,045
Power purchase contract asset		6,031			15,362
Other		20,245			19,143

		933,461			812,178

	$	3,064,947		$	2,899,001

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	69,310		$	69,310
Short-term borrowings-
Associated companies		66,786			41,473
Accounts payable-
Associated companies		48,876			39,884
Other		28,460			41,990
Accrued taxes		5,071			6,409
Accrued interest		17,625			17,598
Other		24,696			22,741

		260,824			239,405

CAPITALIZATION:
Common stockholders’ equity-
Common stock, $20 par value, authorized 5,400,000 shares, 4,427,577 shares outstanding		88,552			88,552
Other paid-in capital		913,460			913,437
Accumulated other comprehensive loss		(155,462	)		(162,104	)
Retained earnings		121,774			91,501

Total common stockholders’ equity		968,324			931,386
Long-term debt and other long-term obligations		1,072,199			1,072,181

		2,040,523			2,003,567

NONCURRENT LIABILITIES:
Accumulated deferred income taxes		296,829			242,040
Retirement benefits		167,288			174,306
Asset retirement obligations		94,933			91,841
Power purchase contract liability		153,603			100,849
Other		50,947			46,993

		763,600			656,029

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 8)
	$	3,064,947		$	2,899,001

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)


	Six Months Ended
	June 30
	2010			2009
	*(In thousands)*
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	30,273		$	33,511
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		31,287			30,036
Amortization (deferral) of regulatory assets, net		(20,488	)		26,889
Deferred costs recoverable as regulatory assets		(38,955	)		(46,349	)
Deferred income taxes and investment tax credits, net		42,943			24,700
Accrued compensation and retirement benefits		4,216			490
Cash collateral		(3,613	)		2
Decrease (increase) in operating assets-
Receivables		3,266			42,494
Prepayments and other current assets		(36,864	)		(35,750	)
Increase (decrease) in operating liabilities-
Accounts payable		(4,603	)		(10,108	)
Accrued taxes		(1,339	)		(7,629	)
Accrued interest		28			(1,669	)
Other		9,559			2,302

Net cash provided from operating activities		15,710			58,919


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		25,313			146,654
Redemptions and Repayments-
Long-term debt		—			(100,000	)
Common stock dividend payments		—			(35,000	)
Other		5			—

Net cash provided from financing activities		25,318			11,654


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(58,293	)		(59,606	)
Loans from associated companies, net		498			63
Sales of investment securities held in trusts		133,934			53,504
Purchases of investment securities held in trusts		(113,067	)		(60,378	)
Other		(4,104	)		(4,168	)

Net cash used for investing activities		(41,032	)		(70,585	)


Net change in cash and cash equivalents		(4	)		(12	)
Cash and cash equivalents at beginning of period		14			23

Cash and cash equivalents at end of period	$	10		$	11

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 233 $ 226
Receivables-
Customers (less accumulated provisions of $6,603,000 and

$5,916,000, respectively, for uncollectible accounts) 241,469 276,400
Associated companies 134,558 113,182
Other 2,260 13,834
Notes receivable from associated companies 23,698 19,060
Prepayments and other 158,993 2,787
561,211 425,489
UTILITY PLANT:
In service 2,283,729 2,221,660
Less - Accumulated provision for depreciation 880,334 846,233
1,403,395 1,375,427
Construction work in progress 38,478 40,651
1,441,873 1,416,078
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes 398,609 425,715
Other 264 10,249
398,873 435,964
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 1,688,521 1,688,521
Regulatory assets 592,206 783,964
Property taxes 71,500 71,500
Other 24,543 10,818
2,376,770 2,554,803
$ 4,778,727 $ 4,832,334
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 150,738 $ 150,688
Short-term borrowings-
Associated companies 135,023 227,949
Accounts payable-
Associated companies 221,456 106,074
Other 16,573 7,195
Accrued taxes 77,298 87,810
Accrued interest 43,749 13,932
Other 49,267 40,095
694,104 633,743
CAPITALIZATION:
Common stockholder's equity
Common stock, without par value, authorized 105,000,000 shares -
67,930,743 shares outstanding 884,415 878,785
Accumulated other comprehensive loss (137,914 ) (134,857 )
Retained earnings 576,369 859,954
Total common stockholder's equity 1,322,870 1,603,882
Noncontrolling interest 20,196 22,555
Total equity 1,343,066 1,626,437
Long-term debt and other long-term obligations 1,871,401 1,591,586
3,214,467 3,218,023
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 662,422 704,270
Accumulated deferred investment tax credits 12,135 13,030
Retirement benefits 65,351 128,738
Lease assignment payable to associated companies 40,827 40,827
Other 89,421 93,703
870,156 980,568
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 4,778,727 $ 4,832,334

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

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss) $ (32,290 ) $ 219,312
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation 53,885 54,497
Amortization of regulatory assets 325,630 124,936
Deferral of new regulatory assets (134,587 ) (71,443 )
Purchased power cost recovery reconciliation (3,478 ) -
Deferred income taxes and investment tax credits, net (41,939 ) 4,623
Accrued compensation and retirement benefits 10,311 (3,291 )
Pension trust contribution (89,789 ) -
Electric service prepayment programs (3,510 ) (17,551 )
Cash collateral from suppliers 5,404 -
Decrease (increase) in operating assets-
Receivables 30,977 43,927
Prepayments and other current assets (633 ) (37 )
Increase (decrease) in operating liabilities-
Accounts payable (32,240 ) (4,443 )
Accrued taxes (17,003 ) (19,613 )
Accrued interest 29,816 23,990
Other 11,489 5,647
Net cash provided from (used for) operating activities 112,043 360,554

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 298,398 -
Redemptions and Repayments-
Long-term debt (558 ) (508 )
Short-term borrowings, net (111,128 ) (176,354 )
Dividend Payments-
Common stock (93,000 ) (150,000 )
Other (6,161 ) (2,955 )
Net cash provided from (used for) financing activities 87,551 (329,817 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (73,577 ) (97,326 )
Restricted cash (155,573 ) -
Loan repayments from (loans to) associated companies, net (4,638 ) 30,624
Redemption of lessor notes 37,072 37,714
Other (2,871 ) (1,744 )
Net cash used for investing activities (199,587 ) (30,732 )

Net increase in cash and cash equivalents 7 5
Cash and cash equivalents at beginning of period 226 232
Cash and cash equivalents at end of period $ 233 $ 237

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009

2008

2009

2008

(In thousands)
STATEMENTS OF INCOME

REVENUES:
Electric sales $ 206,086 $ 242,866 $ 663,082 $ 660,888
Excise tax collections 7,422 8,239 21,448 23,417
Total revenues 213,508 251,105 684,530 684,305

EXPENSES:
Purchased power from affiliates 86,278 111,794 342,166 314,124
Purchased power from non-affiliates 56,494 15 115,275 1,833
Other operating costs 30,238 47,010 110,722 143,144
Provision for depreciation 7,847 7,682 23,136 24,648
Amortization of regulatory assets, net 9,253 25,878 30,921 57,840
General taxes 13,205 13,609 39,804 40,591
Total expenses 203,315 205,988 662,024 582,180

OPERATING INCOME 10,193 45,117 22,506 102,125

OTHER INCOME (EXPENSE):
Investment income 9,302 5,580 22,315 17,285
Miscellaneous expense (1,725 ) (1,523 ) (1,690 ) (4,982 )
Interest expense (10,854 ) (5,832 ) (25,649 ) (17,445 )
Capitalized interest 46 19 138 144
Total other expense (3,231 ) (1,756 ) (4,886 ) (4,998 )

INCOME BEFORE INCOME TAXES 6,962 43,361 17,620 97,127

INCOME TAX EXPENSE (BENEFIT) (138 ) 12,174 3,123 27,614

NET INCOME 7,100 31,187 14,497 69,513

Noncontrolling interest income 14 6 17 10

EARNINGS AVAILABLE TO PARENT $ 7,086 $ 31,181 $ 14,480 $ 69,503

STATEMENTS OF COMPREHENSIVE INCOME

NET INCOME $ 7,100 $ 31,187 $ 14,497 $ 69,513

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (24,201 ) (64 ) (5,052 ) (191 )
Change in unrealized gain on available-for-sale securities (11,633 ) (247 ) (15,181 ) (767 )
Other comprehensive loss (35,834 ) (311 ) (20,233 ) (958 )
Income tax benefit related to other comprehensive income (13,187 ) (108 ) (5,982 ) (294 )
Other comprehensive loss, net of tax (22,647 ) (203 ) (14,251 ) (664 )

COMPREHENSIVE INCOME (LOSS) (15,547 ) 30,984 246 68,849

COMPREHENSIVE INCOME ATTRIBUTABLE
TO NONCONTROLLING INTEREST 14 6 17 10

COMPREHENSIVE INCOME (LOSS) AVAILABLE TO PARENT $ (15,561 ) $ 30,978 $ 229 $ 68,839

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 196,834 $ 14
Receivables-
Customers 485 751
Associated companies 44,103 61,854
Other (less accumulated provisions of $207,000 and $203,000,
respectively, for uncollectible accounts) 19,349 23,336
Notes receivable from associated companies 101,562 111,579
Prepayments and other 4,864 1,213
367,197 198,747
UTILITY PLANT:
In service 900,595 870,911
Less - Accumulated provision for depreciation 422,092 407,859
478,503 463,052
Construction work in progress 8,621 9,007
487,124 472,059
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes 124,329 142,687
Long-term notes receivable from associated companies 36,993 37,233
Nuclear plant decommissioning trusts 75,152 73,500
Other 1,603 1,668
238,077 255,088
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 500,576 500,576
Regulatory assets 77,128 109,364
Property taxes 22,970 22,970
Other 55,579 51,315
656,253 684,225
$ 1,748,651 $ 1,610,119
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 222 $ 34
Accounts payable-
Associated companies 27,454 70,455
Other 9,373 4,812
Notes payable to associated companies 9,673 111,242
Accrued taxes 23,660 24,433
Lease market valuation liability 36,900 36,900
Other 37,231 22,489
144,513 270,365
CAPITALIZATION:
Common stockholder's equity-
Common stock, $5 par value, authorized 60,000,000 shares -
29,402,054 shares outstanding 147,010 147,010
Other paid-in capital 177,992 175,879
Accumulated other comprehensive loss (47,623 ) (33,372 )
Retained earnings 205,013 190,533
Total common stockholder's equity 482,392 480,050
Noncontrolling interest 2,692 2,675
Total equity 485,084 482,725
Long-term debt and other long-term obligations 608,669 299,626
1,093,753 782,351
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 70,865 78,905
Accumulated deferred investment tax credits 6,476 6,804
Lease market valuation liability 245,425 273,100
Retirement benefits 62,155 73,106
Asset retirement obligations 31,757 30,213
Lease assignment payable to associated companies 30,529 30,529
Other 63,178 64,746
510,385 557,403
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 1,748,651 $ 1,610,119

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

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 14,497 $ 69,513
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 23,136 24,648
Amortization of regulatory assets, net 30,921 57,840
Purchased power cost recovery reconciliation 570 -
Deferred rents and lease market valuation liability (34,556 ) (32,918 )
Deferred income taxes and investment tax credits, net (2,242 ) (4,163 )
Accrued compensation and retirement benefits 3,039 (196 )
Accrued regulatory obligations 4,841 -
Electric service prepayment programs (1,458 ) (8,566 )
Pension trust contribution (21,590 ) -
Cash collateral from suppliers 2,830 -
Decrease (increase) in operating assets-
Receivables 24,561 29,088
Prepayments and other current assets 109 (556 )
Increase (decrease) in operating liabilities-
Accounts payable (13,440 ) (177,527 )
Accrued taxes (5,057 ) (9,737 )
Accrued interest 14,033 4,663
Other (4,264 ) (587 )
Net cash provided from (used for) operating activities 35,930 (48,498 )

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 297,422 -
Short-term borrowings, net - 81,807
Redemptions and Repayments-
Long-term debt (292 ) (26 )
Short-term borrowings, net (101,569 ) -
Dividend Payments-
Common stock (25,000 ) (40,000 )
Other (351 ) -
Net cash provided from financing activities 170,210 41,781

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (33,005 ) (44,695 )
Loan repayments from associated companies, net 10,256 43,083
Redemption of lessor notes 18,358 11,989
Sales of investment securities held in trusts 171,061 28,774
Purchases of investment securities held in trusts (173,214 ) (31,297 )
Other (2,776 ) (1,135 )
Net cash provided from (used for) investing activities (9,320 ) 6,719

Net change in cash and cash equivalents 196,820 2
Cash and cash equivalents at beginning of period 14 22
Cash and cash equivalents at end of period $ 196,834 $ 24

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009

2008

2009

2008

(In thousands)

REVENUES:
Electric sales $ 854,108 $ 1,087,245 $ 2,312,089 $ 2,691,782
Excise tax collections 14,128 15,358 37,890 39,792
Total revenues 868,236 1,102,603 2,349,979 2,731,574

EXPENSES:
Purchased power 509,035 720,996 1,414,226 1,751,854
Other operating costs 84,495 78,275 241,241 234,628
Provision for depreciation 26,565 23,205 76,969 70,030
Amortization of regulatory assets 96,051 102,954 262,900 280,980
General taxes 18,344 19,476 48,427 52,042
Total expenses 734,490 944,906 2,043,763 2,389,534

OPERATING INCOME 133,746 157,697 306,216 342,040

OTHER INCOME (EXPENSE):
Miscellaneous income 1,301 (565 ) 4,113 459
Interest expense (29,593 ) (25,747 ) (87,132 ) (75,051 )
Capitalized interest 139 257 419 963
Total other expense (28,153 ) (26,055 ) (82,600 ) (73,629 )

INCOME BEFORE INCOME TAXES 105,593 131,642 223,616 268,411

INCOME TAXES 43,435 55,752 95,834 115,623

NET INCOME 62,158 75,890 127,782 152,788

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (51,932 ) (3,449 ) (26,893 ) (10,347 )
Unrealized gain on derivative hedges 69 69 207 207
Other comprehensive loss (51,863 ) (3,380 ) (26,686 ) (10,140 )
Income tax benefit related to other comprehensive income (21,295 ) (1,469 ) (8,806 ) (4,408 )
Other comprehensive loss, net of tax (30,568 ) (1,911 ) (17,880 ) (5,732 )

TOTAL COMPREHENSIVE INCOME $ 31,590 $ 73,979 $ 109,902 $ 147,056

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
Setpember 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 1 $ 66
Receivables-
Customers (less accumulated provisions of $3,789,000 and $3,230,000
respectively, for uncollectible accounts) 339,025 340,485
Associated companies 147 265
Other 20,128 37,534
Notes receivable - associated companies 16,915 16,254
Prepaid taxes 94,140 10,492
Other 17,683 18,066
488,039 423,162
UTILITY PLANT:
In service 4,427,994 4,307,556
Less - Accumulated provision for depreciation 1,597,831 1,551,290
2,830,163 2,756,266
Construction work in progress 49,873 77,317
2,880,036 2,833,583
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust 196,253 181,468
Nuclear plant decommissioning trusts 161,629 143,027
Other 2,174 2,145
360,056 326,640
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 1,810,936 1,810,936
Regulatory assets 949,814 1,228,061
Other 25,987 29,946
2,786,737 3,068,943
$ 6,514,868 $ 6,652,328
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 30,227 $ 29,094
Short-term borrowings-
Associated companies 6,614 121,380
Accounts payable-
Associated companies 17,189 12,821
Other 153,704 198,742
Accrued taxes 3,994 20,561
Accrued interest 30,143 9,197
Other 113,232 133,091
355,103 524,886
CAPITALIZATION
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares-
13,628,447 shares outstanding 136,284 144,216
Other paid-in capital 2,506,930 2,644,756
Accumulated other comprehensive loss (234,418 ) (216,538 )
Retained earnings 196,358 156,576
Total common stockholder's equity 2,605,154 2,729,010
Long-term debt and other long-term obligations 1,810,367 1,531,840
4,415,521 4,260,850
NONCURRENT LIABILITIES:
Power purchase contract liability 424,921 531,686
Accumulated deferred income taxes 700,187 689,065
Nuclear fuel disposal costs 196,454 196,235
Asset retirement obligations 99,954 95,216
Retirement benefits 131,621 190,182
Other 191,107 164,208
1,744,244 1,866,592
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 6,514,868 $ 6,652,328

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

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 127,782 $ 152,788
Adjustments to reconcile net income to net cash from operating activities -
Provision for depreciation 76,969 70,030
Amortization of regulatory assets 262,900 280,980
Deferred purchased power and other costs (106,340 ) (107,649 )
Deferred income taxes and investment tax credits, net 40,989 1,051
Accrued compensation and retirement benefits 7,308 (32,087 )
Cash collateral received from (returned to) suppliers (210 ) 23,138
Pension trust contribution (100,000 ) -
Decrease (increase) in operating assets-
Receivables 18,984 (43,742 )
Prepaid taxes (83,648 ) (62,148 )
Other current assets 110 234
Increase (decrease) in operating liabilities-
Accounts payable (40,670 ) 36,099
Accrued taxes (13,399 ) 2,082
Accrued interest 20,946 17,276
Tax collections payable (9,714 ) (12,493 )
Other 12,606 (466 )
Net cash provided from operating activities 214,613 325,093

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 299,619 -
Short-term borrowings, net - 12,236
Redemptions and Repayments-
Long-term debt (20,570 ) (19,138 )
Common Stock (150,000 ) -
Short-term borrowings, net (114,766 ) -
Dividend Payments-
Common stock (88,000 ) (186,000 )
Other (2,275 ) -
Net cash used for financing activities (75,992 ) (192,902 )

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (121,342 ) (136,265 )
Proceeds from asset sales - 20,000
Loans to associated companies, net (660 ) 553
Sales of investment securities held in trusts 338,684 186,564
Purchases of investment securities held in trusts (351,216 ) (199,699 )
Other (4,152 ) (3,400 )
Net cash used for investing activities (138,686 ) (132,247 )

Net decrease in cash and cash equivalents (65 ) (56 )
Cash and cash equivalents at beginning of period 66 94
Cash and cash equivalents at end of period $ 1 $ 38

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009

2008

2009

2008

(In thousands)

REVENUES:
Electric sales $ 424,901 $ 434,742 $ 1,194,609 $ 1,188,171
Gross receipts tax collections 20,612 20,793 58,181 59,669
Total revenues 445,513 455,535 1,252,790 1,247,840

EXPENSES:
Purchased power from affiliates 94,768 81,846 273,497 233,496
Purchased power from non-affiliates 142,495 163,853 389,705 446,928
Other operating costs 63,654 126,659 221,320 350,704
Provision for depreciation 13,262 11,394 38,320 33,446
Amortization (deferral) of regulatory assets, net 84,631 3,680 173,770 (10,162 )
General taxes 22,540 23,030 66,509 64,887
Total expenses 421,350 410,462 1,163,121 1,119,299

OPERATING INCOME 24,163 45,073 89,669 128,541

OTHER INCOME (EXPENSE):
Interest income 2,169 4,016 8,124 14,368
Miscellaneous income 1,068 88 2,982 568
Interest expense (14,380 ) (11,014 ) (42,502 ) (33,666 )
Capitalized interest 47 93 124 73
Total other expense (11,096 ) (6,817 ) (31,272 ) (18,657 )

INCOME BEFORE INCOME TAXES 13,067 38,256 58,397 109,884

INCOME TAXES 2,324 16,270 21,027 45,866

NET INCOME 10,743 21,986 37,370 64,018

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (31,365 ) (2,233 ) 557 (6,699 )
Unrealized gain on derivative hedges 84 84 252 252
Other comprehensive income (loss) (31,281 ) (2,149 ) 809 (6,447 )
Income tax expense (benefit) related to other comprehensive income (13,112 ) (971 ) 2,273 (2,912 )
Other comprehensive loss, net of tax (18,169 ) (1,178 ) (1,464 ) (3,535 )

TOTAL COMPREHENSIVE INCOME (LOSS) $ (7,426 ) $ 20,808 $ 35,906 $ 60,483

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 124 $ 144
Receivables-
Customers (less accumulated provisions of $3,880,000 and $3,616,000,
respectively, for uncollectible accounts) 165,519 159,975
Associated companies 43,462 17,034
Other 11,472 19,828
Notes receivable from associated companies 18,032 11,446
Prepaid taxes 29,895 6,121
Other 4,650 1,621
273,154 216,169
UTILITY PLANT:
In service 2,141,513 2,065,847
Less - Accumulated provision for depreciation 800,750 779,692
1,340,763 1,286,155
Construction work in progress 11,718 32,305
1,352,481 1,318,460
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 258,475 226,139
Other 981 976
259,456 227,115
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 416,499 416,499
Regulatory assets 403,690 412,994
Power purchase contract asset 186,661 300,141
Other 33,977 31,031
1,040,827 1,160,665
$ 2,925,918 $ 2,922,409
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 128,500 $ 28,500
Short-term borrowings-
Associated companies - 15,003
Other - 250,000
Accounts payable-
Associated companies 26,817 28,707
Other 39,927 55,330
Accrued taxes 5,143 16,238
Accrued interest 11,756 6,755
Other 30,354 30,647
242,497 431,180
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 900,000 shares-
859,500 shares outstanding 1,197,007 1,196,172
Accumulated other comprehensive loss (142,448 ) (140,984 )
Accumulated deficit (13,754 ) (51,124 )
Total common stockholder's equity 1,040,805 1,004,064
Long-term debt and other long-term obligations 713,843 513,752
1,754,648 1,517,816
NONCURRENT LIABILITIES:
Accumulated deferred income taxes 448,951 387,757
Accumulated deferred investment tax credits 7,427 7,767
Nuclear fuel disposal costs 44,378 44,328
Asset retirement obligations 177,335 170,999
Retirement benefits 31,753 145,218
Power purchase contract liability 151,815 150,324
Other 67,114 67,020
928,773 973,413
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 2,925,918 $ 2,922,409

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

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 37,370 $ 64,018
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 38,320 33,446
Amortization (deferral) of regulatory assets, net 173,770 (10,162 )
Deferred costs recoverable as regulatory assets (70,044 ) (9,673 )
Deferred income taxes and investment tax credits, net 59,393 39,919
Accrued compensation and retirement benefits 6,712 (18,948 )
Pension trust contribution (123,521 ) -
Cash collateral (6,800 ) -
Decrease (Increase) in operating assets-
Receivables (23,370 ) (19,751 )
Prepayments and other current assets (22,614 ) (4,144 )
Increase (decrease) in operating liabilities-
Accounts payable (17,293 ) (9,250 )
Accrued taxes (11,095 ) (13,285 )
Accrued interest 5,001 495
Other 11,891 13,510
Net cash provided from operating activities 57,720 66,175

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 300,000 28,500
Short-term borrowings, net - 29,959
Redemptions and Repayments-
Long-term debt - (28,640 )
Short-term borrowings, net (265,003 ) -
Other (2,268 ) -
Net cash provided from financing activities 32,729 29,819

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (73,106 ) (87,536 )
Sales of investment securities held in trusts 88,802 131,915
Purchases of investment securities held in trusts (95,982 ) (140,429 )
Loans from (to) associated companies, net (6,586 ) 1,163
Other (3,597 ) (1,113 )
Net cash used for investing activities (90,469 ) (96,000 )

Net decrease in cash and cash equivalents (20 ) (6 )
Cash and cash equivalents at beginning of period 144 135
Cash and cash equivalents at end of period $ 124 $ 129

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME (LOSS)
(Unaudited)

Three Months Ended Nine Months Ended
September 30 September 30

2009

2008

2009

2008

(In thousands)
REVENUES:
Electric sales $ 340,246 $ 372,576 $ 1,028,420 $ 1,083,986
Gross receipts tax collections 15,246 17,200 47,342 52,704
Total revenues 355,492 389,776 1,075,762 1,136,690

EXPENSES:
Purchased power from affiliates 81,191 68,743 249,438 214,775
Purchased power from non-affiliates 144,777 161,913 397,260 442,906
Other operating costs 47,785 54,727 171,375 175,904
Provision for depreciation 15,038 14,097 45,074 40,531
Amortization of regulatory assets, net 17,201 23,415 44,090 55,346
General taxes 17,230 20,285 56,074 60,485
Total expenses 323,222 343,180 963,311 989,947

OPERATING INCOME 32,270 46,596 112,451 146,743

OTHER INCOME (EXPENSE):
Miscellaneous income 1,156 (93 ) 2,865 774
Interest expense (11,614 ) (14,934 ) (36,690 ) (45,157 )
Capitalized interest 23 57 74 (679 )
Total other expense (10,435 ) (14,970 ) (33,751 ) (45,062 )

INCOME BEFORE INCOME TAXES 21,835 31,626 78,700 101,681

INCOME TAXES 6,039 9,058 29,393 39,324

NET INCOME 15,796 22,568 49,307 62,357

OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (79,579 ) (3,474 ) (47,224 ) (10,421 )
Unrealized gain on derivative hedges 17 16 49 48
Change in unrealized gain on available-for-sale securities 19 2 3 (8 )
Other comprehensive loss (79,543 ) (3,456 ) (47,172 ) (10,381 )
Income tax benefit related to other comprehensive loss (33,141 ) (1,510 ) (16,986 ) (4,536 )
Other comprehensive loss, net of tax (46,402 ) (1,946 ) (30,186 ) (5,845 )

TOTAL COMPREHENSIVE INCOME (LOSS) $ (30,606 ) $ 20,622 $ 19,121 $ 56,512

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,

2009

2008

(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 9 $ 23
Receivables-
Customers (less accumulated provisions of $2,844,000 and $3,121,000,
respectively, for uncollectible accounts) 124,178 146,831
Associated companies 98,061 65,610
Other 14,116 26,766
Notes receivable from associated companies 14,186 14,833
Prepaid taxes 41,916 16,310
Other 641 1,517
293,107 271,890
UTILITY PLANT:
In service 2,397,432 2,324,879
Less - Accumulated provision for depreciation 891,835 868,639
1,505,597 1,456,240
Construction work in progress 28,729 25,146
1,534,326 1,481,386
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts 137,008 115,292
Non-utility generation trusts 119,163 116,687
Other 290 293
256,461 232,272
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill 768,628 768,628
Power purchase contract asset 23,979 119,748
Regulatory assets 3,433 -
Other 18,814 18,658
814,854 907,034
$ 2,898,748 $ 2,892,582
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 80,000 $ 145,000
Short-term borrowings-
Associated companies 41,632 31,402
Other - 250,000
Accounts payable-
Associated companies 27,126 63,692
Other 41,210 48,633
Accrued taxes 6,104 13,264
Accrued interest 10,561 13,131
Other 27,237 31,730
233,870 596,852
CAPITALIZATION:
Common stockholder's equity-
Common stock, $20 par value, authorized 5,400,000 shares-
4,427,577 shares outstanding 88,552 88,552
Other paid-in capital 913,374 912,441
Accumulated other comprehensive loss (158,183 ) (127,997 )
Retained earnings 75,420 76,113
Total common stockholder's equity 919,163 949,109
Long-term debt and other long-term obligations 1,096,745 633,132
2,015,908 1,582,241
NONCURRENT LIABILITIES:
Regulatory liabilities - 136,579
Accumulated deferred income taxes 220,925 169,807
Retirement benefits 168,767 172,718
Asset retirement obligations 90,334 87,089
Power purchase contract liability 108,160 83,600
Other 60,784 63,696
648,970 713,489
COMMITMENTS AND CONTINGENCIES (Note 9)
$ 2,898,748 $ 2,892,582

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

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

Nine Months Ended
September 30
2009 2008
(In thousands)

CASH FLOWS FROM OPERATING ACTIVITIES:
Net income $ 49,307 $ 62,357
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation 45,074 40,531
Amortization of regulatory assets, net 44,090 55,346
Deferred costs recoverable as regulatory assets (76,953 ) (20,304 )
Deferred income taxes and investment tax credits, net 56,144 68,377
Accrued compensation and retirement benefits 6,271 (21,190 )
Pension trust contribution (60,000 ) -
Decrease (increase) in operating assets-
Receivables 3,687 (42,971 )
Prepayments and other current assets (24,730 ) (28,730 )
Increase (decrease) in operating liabilities-
Accounts payable (8,988 ) (8,437 )
Accrued taxes (7,015 ) (11,521 )
Accrued interest (2,570 ) 867
Other 13,392 14,663
Net cash provided from operating activities 37,709 108,988

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 498,583 45,000
Short-term borrowings, net - 65,590
Redemptions and Repayments-
Long-term debt (100,000 ) (45,332 )
Short-term borrowings, net (239,770 ) -
Dividend Payments-
Common stock (85,000 ) (65,000 )
Other (3,865 ) -
Net cash provided from financing activities 69,948 258

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (92,070 ) (94,810 )
Loan repayments from associated companies, net 647 907
Sales of investment securities held in trust 80,986 84,499
Purchases of investment securities held in trust (91,105 ) (96,950 )
Other (6,129 ) (2,902 )
Net cash used for investing activities (107,671 ) (109,256 )

Net decrease in cash and cash equivalents (14 ) (10 )
Cash and cash equivalents at beginning of period 23 46
Cash and cash equivalents at end of period $ 9 $ 36

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

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. In preparing the financial statements, FirstEnergy and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through ~~November 6, 2009,~~ the date the financial statements were issued.

These statements should be read in conjunction with the financial statements and notes included in the combined Annual Report on Form 10-K for the year ended December 31, ~~2008~~2009 for FirstEnergy, FES and the ~~Utilities.~~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 ~~(see Note 7)~~ when it is determined ~~to be~~that it is the ~~VIE's~~ primary ~~beneficiary.~~beneficiary (see Note 6). Investments in ~~non-consolidated~~ affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but are not ~~control (20-50% owned companies, joint ventures~~the primary beneficiary and ~~partnerships)~~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~~entity’s earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of September 30, 2009 and for the three-month and nine-month periods ended September 30, 2009 and 2008, have been reviewed by PricewaterhouseCoopers LLP, an independent registered public accounting firm. Their report (dated November 6, 2009) is included herein. The report of PricewaterhouseCoopers LLP states that they did not audit and they do not express an opinion on that unaudited financial information. Accordingly, the degree of reliance on their report on such information should be restricted in light of the limited nature of the review procedures applied. PricewaterhouseCoopers LLP is not subject to the liability provisions of Section 11 of the Securities Act of 1933 for their report on the unaudited financial information because that report is not a "report" or a "part" of a registration statement prepared or certified by PricewaterhouseCoopers LLP within the meaning of Sections 7 and 11 of the Securities Act of 1933.

2. EARNINGS PER SHARE

Basic earnings per share of common stock ~~are~~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				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2010		2009		2010		2009
	*(In millions, except per share amounts)*

Earnings available to FirstEnergy Corp.	$	265	$	414	$	420	$	533


Weighted average number of basic shares outstanding		304		304		304		304
Assumed exercise of dilutive stock options and awards		1		1		1		2

Weighted average number of diluted shares outstanding		305		305		305		306


Basic earnings per share of common stock	$	0.87	$	1.36	$	1.38	$	1.75

Diluted earnings per share of common stock	$	0.87	$	1.36	$	1.37	$	1.75

Three Months Ended Nine Months Ended
Reconciliation of Basic and Diluted Earnings per Share
September 30

September 30

of Common Stock 2009 2008 2009 2008
(In millions, except per share amounts)
Earnings available to FirstEnergy Corp. $ 234 $ 471 $ 768 $ 1,010

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

Basic earnings per share of common stock $ .77 $ 1.55 $ 2.52 $ 3.32
Diluted earnings per share of common stock $ .77 $ 1.54 $ 2.51 $ 3.29

3. ~~GOODWILL~~

In a business combination, the excess of the purchase price over the estimated fair values of assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates its goodwill for impairment at least annually and more frequently as indicators of impairment arise. FirstEnergy's 2009 annual evaluation was completed in the third quarter of 2009 with no impairment indicated.

4. FAIR VALUE OF FINANCIAL INSTRUMENTS

~~(A)~~

~~LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS~~

(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~~“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 ~~September~~June 30, ~~2009~~2010 and December 31, ~~2008:~~2009:


	September 30, 2009				December 31, 2008				June 30, 2010				December 31, 2009
	Carrying		Fair		Carrying		Fair		Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value		Value		Value		Value		Value
	(In millions)										*(In millions)*
FirstEnergy	$	13,675	$	14,483	$	11,585	$	11,146	$	13,346	$	14,992	$	13,753	$	14,502
FES		4,233		4,304		2,552		2,528		3,932		4,386		4,224		4,306
OE		1,169		1,318		1,232		1,223		1,166		1,378		1,169		1,299
CEI		1,900		2,033		1,741		1,618		1,853		2,110		1,873		2,032
TE		600		656		300		244		600		682		600		638
JCP&L		1,849		1,977		1,569		1,520		1,826		2,013		1,840		1,950
Met-Ed		842		911		542		519		742		840		842		909
Penelec		1,179		1,221		779		721		1,144		1,233		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~~

(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.

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

Available-For-Sale Securities

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

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in ~~available-for-sale securities~~nuclear decommissioning trusts, nuclear fuel disposal trusts and NUG trusts as of ~~September~~June 30, ~~2009~~2010 and December 31, ~~2008:~~2009:


	June 30, 2010⁽¹⁾								December 31, 2009⁽²⁾
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	*(In millions)*
Debt securities
FirstEnergy	$	1,404	$	40	$	—	$	1,444	$	1,727	$	22	$	—	$	1,749
FES		702		18		—		720		1,043		3		—		1,046
OE		119		1		—		120		55		—		—		55
TE		14		—		—		14		72		—		—		72
JCP&L		278		11		—		289		271		9		—		280
Met-Ed		130		5		—		135		120		5		—		125
Penelec		161		5		—		166		166		5		—		171

Equity securities
FirstEnergy	$	250	$	24	$	—	$	274	$	252	$	43	$	—	$	295
JCP&L		74		4		—		78		74		11		—		85
Met-Ed		117		14		—		131		117		23		—		140
Penelec		59		6		—		65		61		9		—		70


⁽¹⁾		Excludes cash balances: FirstEnergy — $463 million; FES — $388 million; OE — $6 million; TE — $61 million; JCP&L — $3 million; Met-Ed — $(2) million and Penelec - $7 million.

⁽²⁾		Excludes cash balances: FirstEnergy — $137 million; FES — $43 million; OE - $66 million; TE — $2 million; JCP&L — $3 million and Penelec — $23 million.

September 30, 2009(1)

December 31, 2008(2)

Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair
Basis Gains Losses Value Basis Gains Losses Value
Debt securities (In millions)
FirstEnergy(3)

$
576

$
25

$
-

$
601

$
1,078

$
56

$
-

$
1,134

FES

7

1

-

8

401

28

-

429

OE

2

-

-

2

86

9

-

95

TE

-

-

-

-

66

8

-

74

JCP&L

266

13

-

279

249

9

-

258

Met-Ed

121

6

-

127

111

4

-

115

Penelec

180

5

-

185

164

3

-

167

Equity securities

FirstEnergy

$
245

$
33

$
-

$
278

$
589

$
39

$
-

$
628

FES

-

-

-

-

355

25

-

380

OE

-

-

-

-

17

1

-

18

JCP&L

72

8

-

80

64

2

-

66

Met-Ed

114

18

-

132

101

9

-

110

Penelec

59

7

-

66

51

2

-

53

(1) Excludes cash balances of $1,291 million at FirstEnergy, $1,094 million at FES, $2 million at JCP&L, $120 million at OE, $5 million at Penelec and $75 million at TE.
(2) Excludes cash balances of $244 million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed.
(3) Includes fair values as of September 30, 2009 and December 31, 2008 of $557 million and $953 million of government obligations, $44 million and $175 million of corporate debt and $1 million and $6 million of mortgage backed securities.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income for the ~~nine-month~~six-month period ended ~~September~~June 30, 2010 and 2009 were as follows:


June 30, 2010		FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
					*(In millions)*
Proceeds from sales	$	1,916	$	957	$	60	$	107	$	281	$	377	$	134
Realized gains		83		54		2		3		9		9		6
Realized losses		86		58		—		—		9		12		7
Interest and dividend income		37		22		1		1		7		3		3

	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
June 30, 2009															June 30, 2009		FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	(In millions)																			*(In millions)*
Proceeds from sales	$	3,040	$	2,153	$	207	$	171	$	339	$	89	$	81		$	1,001	$	537	$	25	$	77	$	245	$	63	$	54
Realized gains		186		162		11		7		4		1		1			30		24		-		3		3		1		-
Realized losses		96		62		3		-		11		13		7			91		58		3		-		11		12		7
Interest and dividend income		47		22		4		2		10		5		4			30		14		2		1		7		3		3

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

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

~~During the three-month period ended September 30, 2009, FES recognized $135 million of realized gains resulting from the sale of securities held in the nuclear decommissioning trust.~~

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities ~~(except for~~as of June 30, 2010 and December 31, 2009 (excluding emission allowances, employee benefits, cost method investments and equity method investments of ~~$271~~$251 million and ~~$293~~$264 million, respectively, that are not required to be disclosed) ~~as of September 30, 2009 and December 31, 2008:~~:


	June 30, 2010								December 31, 2009
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	*(In millions)*
Debt Securities
FirstEnergy	$	487	$	93	$	—	$	580	$	544	$	72	$	—	$	616
OE		205		55		—		260		217		29		—		246
CEI		340		38		—		378		389		43		—		432

September 30, 2009 December 31, 2008
Cost Unrealized Unrealized Fair Cost Unrealized Unrealized Fair
Basis Gains Losses Value Basis Gains Losses Value
Debt securities (In millions)
FirstEnergy
$ 621 $ 91 $ - $ 712 $ 673 $ 14 $ 13 $ 674
OE
230 57 - 287 240 - 13 227
CEI
389 34 - 423 426 9 - 435

Notes Receivable

The following table provides the approximate fair value and related carrying amounts of notes receivable as of ~~September~~June 30, ~~2009~~2010 and December 31, ~~2008:~~2009:

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair		June 30, 2010				December 31, 2009
	Value		Value		Value		Value		Carrying		Fair		Carrying		Fair
Notes receivable	(In millions)
									Value		Value		Value		Value
									*(In millions)*
Notes Receivable
FirstEnergy	$	45	$	42	$	45	$	44	$	36	$	34	$	36	$	35
FES		4		4		75		74		—		—		2		1
OE		193		234		257		294
TE		161		180		180		189		104		117		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.

(C) RECURRING 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 ~~maturity dates range from 2009~~hierarchy gives the highest priority to ~~2040.~~

~~(C)~~

~~RECURRING FAIR VALUE MEASUREMENTS~~

~~FirstEnergy's valuation techniques, including~~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 ~~disclosed~~as follows:

Level 1 — Quoted prices are available in ~~Note 5~~active markets for identical assets or liabilities as of the ~~Notes to Consolidated Financial Statements in FirstEnergy's Annual Report on Form 10-K~~reporting date. Active markets are those where transactions for the ~~year ended December 31, 2008.~~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 ~~September~~June 30, ~~2009~~2010 and December 31, ~~2008.~~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~~FirstEnergy’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.


	Recurring Fair Value Measures as of June 30, 2010
					Level 1
	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*
Assets
Nuclear Decommissioning Trust Investments
Equity securities — consumer products	$	122	$	—	$	—	$	—	$	35	$	58	$	29
Equity securities — technology		51		—		—		—		15		24		12
Equity securities — utilities & energy		52		—		—		—		15		25		12
Equity securities — financial		42		—		—		—		12		20		10
Equity securities — other		8		—		—		—		2		4		2

Total Assets⁽¹⁾	$	275	$	—	$	—	$	—	$	79	$	131	$	65


Liabilities
Derivatives — commodity contracts	$	5	$	5	$	—	$	—	$	—	$	—	$	—

Total Liabilities	$	5	$	5	$	—	$	—	$	—	$	—	$	—


	Level 2
	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*
Assets
Nuclear Decommissioning Trust Investments
U.S. government debt securities	$	538	$	265	$	121	$	14	$	36	$	92	$	10
U.S. state debt securities		94		—		—		—		31		2		61
Foreign government debt securities		297		297		—		—		—		—		—
Corporate debt securities		225		158		—		—		20		42		5
Other		458		388		5		62		1		1		1

Total nuclear decommissioning trust investments	$	1,612	$	1,108	$	126	$	76	$	88	$	137	$	77


Rabbi Trust Investments
Equity securities — financial	$	1	$	—	$	—	$	—	$	—	$	—	$	—
Other		12		—		1		—		—		—		—

Total rabbi trust investments	$	13	$	—	$	1	$	—	$	—	$	—	$	—


Nuclear Fuel Disposal Trust Investments
U.S. state debt securities	$	196	$	—	$	—	$	—	$	196	$	—	$	—
Other		8		—		—		—		8		—		—

Total nuclear fuel disposal trust investments	$	204	$	—	$	—	$	—	$	204	$	—	$	—


NUG Trust Investments
U.S. state debt securities	$	97	$	—	$	—	$	—	$	—	$	—	$	97

Total NUG trust investments	$	97	$	—	$	—	$	—	$	—	$	—	$	97


Derivatives
Commodity contracts	$	111	$	102	$	—	$	—	$	2	$	5	$	2
Interest rate contracts		62		—		—		—		—		—		—

Total derivatives contracts	$	173	$	102	$	—	$	—	$	2	$	5	$	2

Total Assets⁽¹⁾	$	2,099	$	1,210	$	127	$	76	$	294	$	142	$	176


Liabilities
Derivatives
Commodity contracts	$	273	$	273	$	—	$	—	$	—	$	—	$	—

Total Liabilities	$	273	$	273	$	—	$	—	$	—	$	—	$	—

Recurring Fair Value Measures as of September 30, 2009
Level 1 - Assets Level 1 - Liabilities
(In millions)
Derivatives
Available-for-
Sale Securities(1)
Other Investments Total Derivatives
NUG
Contracts(2)
Total
FirstEnergy $ - $ 278 $ - $ 278 $ 15 $ - $ 15
FES - 1 - 1 15 - 15
OE - - - - - - -
JCP&L - 81 - 81 - - -
Met-Ed - 125 - 125 - - -
Penelec - 71 - 71 - - -

Level 2 - Assets Level 2 - Liabilities
Derivatives
Available-for-
Sale Securities(1)
Other Investments Total Derivatives
NUG
Contracts(2)
Total
FirstEnergy $ 32 $ 1,896 $ 78 $ 2,006 $ 6 $ - $ 6
FES 13 1,103 - 1,116 5 - 5
OE - 123 - 123 - - -
TE - 75 - 75 - - -
JCP&L 5 276 - 281 - - -
Met-Ed 9 134 - 143 - - -
Penelec 5 185 - 190 - - -

Level 3 - Assets Level 3 - Liabilities
Derivatives
Available-for-
Sale Securities(1)

NUG
Contracts(2)
Total Derivatives
NUG
Contracts(2)
Total
FirstEnergy $ - $ - $ 220 $ 220 $ - $ 685 $ 685
JCP&L - - 9 9 - 425 425
Met-Ed - - 187 187 - 152 152
Penelec - - 24 24 - 108 108


	Level 3
	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*
Assets
Derivatives — NUG contracts⁽²⁾	$	134	$	—	$	—	$	—	$	7	$	121	$	6


Liabilities
Derivatives — NUG contracts⁽²⁾	$	691	$	—	$	—	$	—	$	378	$	159	$	154

	~~(1)~~	~~Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $2~~
⁽¹⁾		Excludes $(7) million of receivables, payables and accrued income.

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


	Recurring Fair Value Measures as of December 31, 2009
	Level 1
	FirstEnergy		FES		OE		TE			JCP&L		Met-Ed		Penelec
	*(In millions)*
Assets
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 Assets⁽¹⁾	$	294	$	—	$	—	$	—		$	87	$	133	$	74


Liabilities
Derivatives — commodity contracts	$	11	$	11	$	—	$	—		$	—	$	—	$	—

Total Liabilities	$	11	$	11	$	—	$	—		$	—	$	—	$	—


	Level 2
	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*
Assets
Nuclear Decommissioning Trust Investments
U.S. government debt securities	$	558	$	306	$	118	$	72	$	23	$	30	$	9
U.S. state debt securities		188		15		—		—		41		82		50
Foreign government debt securities		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	$	120	$	72	$	80	$	134	$	66


Rabbi Trust Investments
Equity securities — financial	$	1	$	—	$	—	$	—	$	—	$	—	$	—
Other		9		—		—		—		—		—		—

Total rabbi trust investments	$	10	$	—	$	—	$	—	$	—	$	—	$	—


Nuclear Fuel Disposal Trust Investments
U.S. state debt securities	$	189	$	—	$	—	$	—	$	189	$	—	$	—
Other		11		—		—		—		11		—		—

Total nuclear fuel disposal trust investments	$	200	$	—	$	—	$	—	$	200	$	—	$	—
��

NUG Trust Investments
U.S. state debt securities	$	101	$	—	$	—	$	—	$	—	$	—	$	101
Other		19		—		—		—		—		—		19

Total NUG trust investments	$	120	$	—	$	—	$	—	$	—	$	—	$	120


Derivatives — Commodity Contracts	$	34	$	15	$	—	$	—	$	5	$	9	$	5

Other	$	1	$	—	$	—	$	—	$	—	$	—	$	—

Total Assets⁽¹⁾	$	1,909	$	1,087	$	120	$	72	$	285	$	143	$	191


Liabilities
Derivatives — commodity contracts	$	224	$	224	$	—	$	—	$	—	$	—	$	—

Total Liabilities	$	224	$	224	$	—	$	—	$	—	$	—	$	—

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


	Level 3
	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	*(In millions)*
Assets
Derivatives — NUG contracts⁽²⁾	$	200	$	—	$	—	$	—	$	9	$	176	$	15


Liabilities
Derivatives — NUG contracts⁽²⁾	$	643	$	—	$	—	$	—	$	399	$	143	$	101

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

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

Level 3 - Assets Level 3 - Liabilities
Derivatives
Available-for-
Sale Securities(1)

NUG
Contracts(2)
Total Derivatives
NUG
Contracts(2)
Total
FirstEnergy $ - $ - $ 434 $ 434 $ - $ 766 $ 766
JCP&L - - 14 14 - 532 532
Met-Ed - - 300 300 - 150 150
Penelec - - 120 120 - 84 84

	~~(1)~~	~~Consists of investments in nuclear decommissioning trusts, spent nuclear fuel trusts and NUG trusts. Balance excludes $5~~
⁽¹⁾		Excludes $21 million of receivables, payables and accrued income.

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

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

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

The following tables set forth a reconciliation of changes in the fair value of NUG contracts classified as Level 3 in the fair value hierarchy for the three and ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 and ~~2008~~2009 (in millions):


	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2010	$	(444	)	$	(391	)	$	33		$	(86	)
Settlements⁽¹⁾		146			70			36			40
Unrealized losses⁽¹⁾		(259	)		(50	)		(107	)		(102	)

Balance as of June 30, 2010	$	(557	)	$	(371	)	$	(38	)	$	(148	)


Balance as of April 1, 2010	$	(590	)	$	(394	)	$	(30	)	$	(166	)
Settlements⁽¹⁾		68			30			19			19
Unrealized losses⁽¹⁾		(35	)		(7	)		(27	)		(1	)

Balance as of June 30, 2010	$	(557	)	$	(371	)	$	(38	)	$	(148	)

FirstEnergy JCP&L Met-Ed Penelec
Balance as of January 1, 2009 $ (332 ) $ (518 ) $ 150 $ 36
    Settlements(1)
273 132 63 78
    Unrealized gains (losses)(1)
(406) (30) (178) (198)
    Net transfers to (from) Level 3 - - - -
Balance as of September 30, 2009 $ (465) $ (416) $ 35 $ (84)

Change in unrealized gains (losses) relating to
instruments held as of September 30, 2009
$ (406) $ (30)

$

(178)

$

(198)

Balance as of July 1, 2009 $ (536 ) $ (466 ) $ 23 $ (93 )
    Settlements(1)
93 42 20 31
    Unrealized gains (losses)(1)
(22) 8 (8) (22)
    Net transfers to (from) Level 3 - - - -
Balance as of September 30, 2009 $ (465) $ (416) $ 35 $ (84)

Change in unrealized gains (losses) relating to
instruments held as of September 30, 2009
$ (22) $ 8

$

(8)

$

(22)


	FirstEnergy			JCP&L			Met-Ed			Penelec
Balance as of January 1, 2009	$	(332	)	$	(518	)	$	150		$	36
Settlements⁽¹⁾		179			90			43			47
Unrealized losses⁽¹⁾		(383	)		(38	)		(170	)		(176	)

Balance as of June 30, 2009	$	(536	)	$	(466	)	$	23		$	(93	)


Balance as of April 1, 2009	$	(476	)	$	(518	)	$	76		$	(34	)
Settlements⁽¹⁾		96			44			26			27
Unrealized gains (losses)⁽¹⁾		(156	)		8			(79	)		(86	)

Balance as of June 30, 2009	$	(536	)	$	(466	)	$	23		$	(93	)


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

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

FirstEnergy JCP&L Met-Ed Penelec
Balance as of January 1, 2008 $ (803 ) $ (750 ) $ (28 ) $ (25 )
    Settlements(1)
167 152 (5) 20
    Unrealized gains (losses)(1)
314 (43) 236 121
    Net transfers to (from) Level 3 - - - -
Balance as of September 30, 2008 $ (322) $ (641) $ 203 $ 116

Change in unrealized gains (losses) relating to
instruments held as of September 30, 2008
$ 314 $ (43)

$

236

$

121

Balance as of July 1, 2008 $ (17 ) $ (644 ) $ 350 $ 278
    Settlements(1)
57 57 (7) 7
    Unrealized gains (losses)(1)
(362) (54) (140) (169)
    Net transfers to (from) Level 3 - - - -
Balance as of September 30, 2008 $ (322) $ (641) $ 203 $ 116

Change in unrealized gains (losses) relating to
instruments held as of September 30, 2008
$ (362) $ (54)

$

(140)

$

(169)

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

5.4. 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~~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~~purchases and normal sales criteria. Derivatives that meet those criteria are accounted for at ~~cost.~~cost under the accrual method of accounting. The changes in the fair value of derivative instruments that do not meet the normal ~~purchase~~purchases 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. Based on derivative contracts held as of June 30, 2010, an adverse 10% change in commodity prices would decrease net income by approximately $9 million ($6 million net of tax) during the next twelve months. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by less than $1 million for the three and six months ended June 30, 2010.

~~Interest Rate Derivatives~~

Under the revolving credit facility, FirstEnergy, and its subsidiaries, incur variable interest charges based on LIBOR. FirstEnergy currently holds swaps with a notional value of $200 million to hedge against changes in associated interest rates.Cash Flow Hedges with a notional value of $100 million expire in November 2009 and $100 million expire in January 2010. The swaps are accounted for as cash flow hedges. As of September 30, 2009, the fair value of outstanding swaps was $(2) million.

FirstEnergy ~~uses~~has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives ~~are~~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. For the three months and nine months ended September 30, 2009, FirstEnergy terminated forward swaps with a notional value of $2.3 billion and $2.4 billion, respectively. FirstEnergy recognized losses of approximately $17 million and $18 million, respectively -- of which the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions will be amortized to interest expense over the life of the hedged debt.

As of ~~September~~June 30, 2009 and December 31, 2008, the fair value of outstanding interest rate derivatives was $(2) million and $(3) million, respectively. Interest rate derivatives are included in "Other Noncurrent Liabilities" on FirstEnergy’s consolidated balance sheets. The effects of interest rate derivatives on the consolidated statements of income and comprehensive income during the three months and nine months ended September 30, 2009 and 2008 were:2010, no forward starting swap agreements were outstanding.

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
(In millions)
Effective Portion
Loss Recognized in AOCL $ (17) $ (2) $ (18) $ (11)
Loss Reclassified from AOCL into Interest Expense (26) (4) (37) (11)
Ineffective Portion
Loss Recognized in Interest Expense - - - (5)

Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled ~~$94~~$109 million ($5771 million net of tax) as of ~~September~~June 30, ~~2009.~~2010. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. ~~FirstEnergy’s~~The table below provides the activity of AOCL related to interest rate cash flow hedges as of June 30, 2010 and 2009.


	Three Months Ended						Six Months Ended
	June 30						June 30
	2010			2009			2010			2009
	*(In millions)*						*(In millions)*
Effective Portion
Gain Recognized in AOCL	$	—		$	2		$	—		$	—
Reclassification from AOCL into Interest Expense		(3	)		(6	)		(6	)		(11	)

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. In May of 2010, FirstEnergy terminated fixed-for-floating interest rate swap agreements with a notional value of $3.15 billion, which resulted in cash proceeds of $43.1 million. These proceeds will generally be amortized to earnings over the life of the underlying debt.

Effective June 1, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with a combined notional value of $3.2 billion, which essentially replaced the swap agreements terminated in May of 2010. As of June 30, 2010, the debt underlying the $3.2 billion outstanding notional amount of interest rate swaps dohad a weighted average fixed interest rate of 6%, which the swaps have converted to a current weighted average variable rate of 4%.

On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $83.6 million. These proceeds will be amortized to earnings over the life of the underlying debt. While FirstEnergy currently does not ~~include~~have any ~~contingent credit risk related features.~~interest rate swaps outstanding, costs associated with entering into future swap transactions may be increased as a result of the recent passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires increased regulation of swaps, swap dealers and major swap participants.

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
	June 30,		December 31,			June 30,		December 31,
	2010		2009			2010		2009
	*(In millions)*					*(In millions)*
Fair Value Hedges					Fair Value Hedges
Interest Rate Swaps	$	62	$	—	Interest Rate Swaps	$	—	$	—

Noncurrent Assets	$	62	$	—	Noncurrent Liabilities	$	—	$	—

Commodity Derivatives

FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances ~~in which~~where the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges are marked to market through earnings. FirstEnergy’s risk policy does not allow derivatives to be used for speculative or trading purposes. FirstEnergy hedges forecasted electric sales and purchases and anticipated natural gas purchases using forwards and options. Heating oil futures are used to hedge both oil purchases and fuel surcharges associated with rail transportation contracts. FirstEnergy’s hedge term is typically two years. The effective portions of all cash flow hedges are initially recorded in AOCL and are subsequently included in net income as the underlying hedged commodities are delivered.

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


Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	June 30,		December 31,			June 30,		December 31,
	2010		2009			2010		2009
	*(In millions)*					*(In millions)*
Cash Flow Hedges					Cash Flow Hedges
Electricity Forwards					Electricity Forwards
Current Assets	$	40	$	3	Current Liabilities	$	50	$	7
NonCurrent Assets		57		11	NonCurrent Liabilities		54		12
Natural Gas Futures					Natural Gas Futures
Current Assets		—		—	Current Liabilities		4		9
NonCurrent Assets		—		—	NonCurrent Liabilities		—		—
Other					Other
Current Assets		—		—	Current Liabilities		1		2
NonCurrent Assets		—		—	NonCurrent Liabilities		—		—

	$	97	$	14		$	109	$	30

Derivative Assets Derivative Liabilities
Fair Value Fair Value
September 30 December 31 September 30 December 31
2009 2008 2009 2008
Cash Flow Hedges (In millions) Cash Flow Hedges (In millions)
Electricity Forwards Electricity Forwards
Current Assets $ 13 $ 11 Current Liabilities $ 5 $ 27
Natural Gas Futures Natural Gas Futures
Current Assets - - Current Liabilities 8 4
Long-Term Deferred Charges - - Noncurrent Liabilities 1 5
Other Other
Current Assets - - Current Liabilities 5 12
Long-Term Deferred Charges - - Noncurrent Liabilities 2 4
$ 13 $ 11 $ 21 52

Derivative Assets Derivative Liabilities
Fair Value Fair Value
September 30 2009 December 31 2008 September 30 2009 December 31 2008
Economic Hedges (In millions) Economic Hedges (In millions)
NUG Contracts NUG Contracts
Power Purchase Power Purchase
Contract Asset $ 220 $ 434 Contract Liability $ 685 $ 766
Other Other
Current Assets - 1 Current Liabilities - 1
Long-Term Deferred Charges 19 28 Noncurrent Liabilities - -
$ 239 $ 463 $ 685 $ 767
Total Commodity Derivatives $ 252 $ 474 Total Commodity Derivatives $ 706 $ 819


Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	June 30,		December 31,			June 30,		December 31,
	2010		2009			2010		2009
	*(In millions)*					*(In millions)*
Economic Hedges					Economic Hedges
NUG Contracts					NUG Contracts
Power Purchase					Power Purchase
Contract Asset	$	134	$	200	Contract Liability	$	691	$	643
Other					Other
Current Assets		4		—	Current Liabilities		114		106
NonCurrent Assets		10		19	NonCurrent Liabilities		55		97

		148		219			860		846

Total Commodity Derivatives	$	245	$	233	Total Commodity Derivatives	$	969	$	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 ~~September~~June 30, ~~2009.~~2010:


	Purchases		Sales			Net		Units
			*(In thousands)*
Electricity Forwards		21,596		(19,965	)		1,631	MWH
Heating Oil Futures		2,100		—			2,100	Gallons
Natural Gas Futures		1,250		(1,000	)		250	mmBtu

Purchases Sales Net Units
(In thousands)
Electricity Forwards 156 (2,913 ) (2,757 )    MWH
Heating Oil Futures 5,880 - 5,880    Gallons
Natural Gas Futures 3,000 (2,500 ) 500    mmBtu

The effect of derivative instruments on the consolidated statements of income and comprehensive income for the three ~~months~~ and ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 and ~~2008,~~2009, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:


	Three Months Ended June 30,
	Electricity			Natural Gas			Heating Oil
Derivatives in Cash Flow Hedging Relationships	Forwards			Futures			Futures			Total
	*(In millions)*
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(8	)	$	—		$	—		$	(8	)
Effective Gain (Loss) Reclassified to:⁽¹⁾
Purchased Power Expense		(7	)		—			—			(7	)
Fuel Expense		—			(3	)		(1	)		(4	)

2009
Gain (Loss) Recognized in AOCL (Effective Portion)	$	6		$	—		$	2		$	8
Effective Gain (Loss) Reclassified to:⁽¹⁾
Purchased Power Expense		1			—			—			1
Fuel Expense		—			(4	)		(4	)		(8	)

Derivatives in Cash Flow Hedging Relationships Electricity Natural Gas Heating Oil
Forwards Futures Futures Total
Three Months Ended September 30, 2009 (in millions)
Gain (Loss) Recognized in AOCL (Effective Portion) $ 15 $ (2 ) $ - $ 13
Effective Gain (Loss) Reclassified to:(1)

Purchased Power Expense 11 - - 11
Fuel Expense - (4 ) (2 ) (6 )

Nine Months Ended September 30, 2009
Gain (Loss) Recognized in AOCL (Effective Portion) $ 19 $ (9 ) $ - $ 10
Effective Gain (Loss) Reclassified to:(1)

Purchased Power Expense (6 ) - - (6 )
Fuel Expense - (9 ) (10 ) (19 )

Three Months Ended September 30, 2008
Gain (Loss) Recognized in AOCL (Effective Portion) $ 42 $ (2 ) $ - $ 40
Effective Gain (Loss) Reclassified to:(1)

Purchased Power Expense 3 - - 3
Fuel Expense - 3 - 3

Nine Months Ended September 30, 2008
Gain (Loss) Recognized in AOCL (Effective Portion) $ 12 $ 4 $ - $ 16
Effective Gain (Loss) Reclassified to:(1)

Purchased Power Expense (10 ) - - (10 )
Fuel Expense - 4 - 4

(1) The ineffective portion was immaterial.


	Six Months Ended June 30,
	Electricity			Natural Gas			Heating Oil
Derivatives in Cash Flow Hedging Relationships	Forwards			Futures			Futures			Total
	*(In millions)*
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(13	)	$	(1	)	$	—		$	(14	)
Effective Gain (Loss) Reclassified to:⁽¹⁾
Purchased Power Expense		(11	)		—			—			(11	)
Fuel Expense		—			(6	)		(2	)		(8	)

2009
Gain (Loss) Recognized in AOCL (Effective Portion)	$	4		$	(7	)	$	1		$	(2	)
Effective Gain (Loss) Reclassified to:⁽¹⁾
Purchased Power Expense		(17	)		—			—			(17	)
Fuel Expense		—			(4	)		(8	)		(12	)


⁽¹⁾		The ineffective portion was immaterial.


	Three Months Ended June 30,
	NUG
Derivatives Not in Hedging Relationships	Contracts			Other			Total
	*(In millions)*
2010
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	—		$	35		$	35
Regulatory Assets⁽²⁾		(35	)		—			(35	)

	$	(35	)	$	35		$	—


Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	—		$	(31	)	$	(31	)
Regulatory Assets⁽²⁾		(68	)		—			(68	)

	$	(68	)	$	(31	)	$	(99	)


2009
Unrealized Gain (Loss) Recognized in:
Fuel Expense⁽¹⁾	$	—			2		$	2
Regulatory Assets⁽²⁾		(156	)	$	—			(156	)

	$	(156	)	$	2		$	(154	)


Realized Gain (Loss) Reclassified to:
Fuel Expense⁽¹⁾	$	—		$	—		$	—
Regulatory Assets⁽²⁾		(96	)		—			(96	)

	$	(96	)	$	—		$	(96	)


	Six Months Ended June 30,
	NUG
Derivatives Not in Hedging Relationships	Contracts			Other			Total
	*(In millions)*
2010
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	—		$	(17	)	$	(17	)
Regulatory Assets⁽²⁾		(259	)		—			(259	)

	$	(259	)	$	(17	)	$	(276	)


Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	—		$	(56	)	$	(56	)
Regulatory Assets⁽²⁾		(146	)		9			(137	)

	$	(146	)	$	(47	)	$	(193	)


2009
Unrealized Gain (Loss) Recognized in:
Fuel Expense⁽¹⁾	$	—		$	2		$	2
Regulatory Assets⁽²⁾		(383	)		—			(383	)

		(383	)	$	2		$	(381	)

Realized Gain (Loss) Reclassified to:
Fuel Expense⁽¹⁾	$	—		$	(1	)	$	(1	)
Regulatory Assets⁽²⁾		(179	)		10			(169	)

	$	(179	)	$	9		$	(170	)


⁽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.

Three Months Ended September 30 Nine Months Ended September 30
Derivatives Not in Hedging Relationships NUG NUG
Contracts Other Total Contracts Other Total
2009 (In millions)
Unrealized Gain (Loss) Recognized in:
Fuel Expense(1)
$ - $ (1 ) $ (1 ) $ - $ 2 $ 2
Regulatory Assets(2)
(22 ) - (22 ) (406 ) - (406 )
$ (22 ) $ (1 ) $ (23 ) $ (406 ) $ 2 $ (404 )
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)
$ - $ 1 $ 1 $ - $ - $ -
Regulatory Assets(2)
(93 ) - (93 ) (273 ) 11 (262 )
$ (93 ) $ 1 $ (92 ) $ (273 ) $ 11 $ (262 )
2008
Unrealized Gain (Loss) Recognized in:
Fuel Expense(1)
$ - $ 2 $ 2 $ - $ 2 $ 2
Regulatory Assets(2)
(362 ) 1 (361 ) 314 1 315
$ (362 ) $ 3 $ (359 ) $ 314 $ 3 $ 317
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)
$ - $ 1 $ 1 $ - $ 1 $ 1
Regulatory Assets(2)
(57 ) 1 (56 ) (167 ) 11 (156 )
$ (57 ) $ 2 $ (55 ) $ (167 ) $ 12 $ (155 )

(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 $9$11 million ($57 million net of tax) as of ~~September~~June 30, ~~2009,~~2010, as compared to ~~$44~~$15 million ($279 million net of tax) as of December 31, ~~2008.~~2009. The net of tax change resulted from a net $7$10 million ~~decrease~~increase related to current hedging activity and a ~~$15~~$12 million decrease due to net hedge losses reclassified to earnings during the first ~~nine~~six months of ~~2009.~~2010. Based on current estimates, approximately $3$10 million ~~(after~~(net of tax) of the net deferred losses on derivative instruments in AOCL as of ~~September~~June 30, ~~2009~~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 ~~September~~June 30, ~~2009,~~2010, FirstEnergy posted ~~$133~~$194 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 ~~September~~June 30, ~~2009~~2010 was $2$177 million, for which ~~$106~~$194 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post ~~$18~~$37 million of additional collateral related to commodity derivatives.

6.5. PENSION AND OTHER POSTRETIREMENT BENEFITS

FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. FirstEnergy's funding policy is based on actuarial computations using the projected unit credit method. FirstEnergy uses a December 31 measurement date for its pension and other postretirement benefit plans. The fair value of the plan assets represents the actual market value as of December 31. FirstEnergy also provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are available upon retirement to employees hired prior to January 1, 2005, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension benefits and other postretirement benefits from the time employees are hired until they become eligible to receive those benefits. In addition, FirstEnergy has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

On June 2, 2009, FirstEnergy amended its health care benefits plan (Plan) for all employees and retirees eligible to participate in the Plan. The Plan amendment, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of participants, triggered a remeasurement of FirstEnergy’s other postretirement benefit plans as of May 31, 2009. As a result of the remeasurement, the Plan’s discount rate was revised to 7.5% while the expected long-term rate of return on assets remained at 9%. The remeasurement and Plan amendment increased FirstEnergy’s AOCI by approximately $449 million ($252 million, net of tax) in the second quarter of 2009 and reduced FirstEnergy’s 2009 net postretirement benefit cost (including amounts capitalized) by $48 million, including $27 million applicable to the first nine months of 2009.

In the third quarter of 2009, FirstEnergy incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees. The special termination benefits of the VERO included additional health care coverage subsidies paid by FirstEnergy to those qualified employees who elected to retire. A total of 715 employees accepted the VERO.

On September 2, 2009, the Utilities and ATSI made a $500 million voluntary contribution to the FirstEnergy Corp. Pension Plan (Pension Plan). Due to the significance of the voluntary contribution, FirstEnergy elected to remeasure its Pension Plan as of August 31, 2009. As a result of the remeasurement, the Pension Plan’s discount rate was revised to 6% while the expected long-term rate of return on assets remained at 9%. The remeasurement and voluntary contribution decreased FirstEnergy’s AOCI by approximately $494 million ($304 million, net of tax) in the third quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $7 million, including a $2 million reduction that is applicable to the third quarter of 2009.

FirstEnergy’s net pension and OPEB ~~expenses (benefits)~~expense for the three months ended ~~September~~June 30, 2010 and 2009 was $21 million and ~~2008 were $36 million (including $9 million attributable to the VERO-related charge mentioned above), and $(15)~~$38 million, respectively. ~~For the nine months ended September 30, 2009 and 2008,~~ FirstEnergy’s net pension and OPEB ~~expenses (benefits) were $117~~expense for the six months ended June 30, 2010 and 2009 was $45 million and ~~$(44)~~$80 million, respectively. The components of ~~FirstEnergy's~~FirstEnergy’s net pension and other postretirement benefit costs (including amounts capitalized) for the three ~~months~~ and ~~nine~~six months ended ~~September 30,~~June, 2010 and 2009, ~~and 2008,~~ consisted of the following:


	Three Months Ended						Six Months Ended
	June 30						June 30
Pension Benefits	2010			2009			2010			2009
				*(In millions)*
Service cost	$	25		$	22		$	49		$	43
Interest cost		79			80			157			159
Expected return on plan assets		(90	)		(81	)		(181	)		(162	)
Amortization of prior service cost		3			3			6			7
Recognized net actuarial loss		47			42			94			85

Net periodic cost	$	64		$	66		$	125		$	132


	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefits	2010			2009			2010			2009
				*(In millions)*
Service cost	$	3		$	4		$	5		$	8
Interest cost		11			18			22			38
Expected return on plan assets		(9	)		(9	)		(18	)		(18	)
Amortization of prior service cost		(48	)		(41	)		(96	)		(79	)
Recognized net actuarial loss		15			15			30			31

Net periodic cost	$	(28	)	$	(13	)	$	(57	)	$	(20	)

Three Months Ended Nine Months Ended
September 30 September 30
Pension Benefits 2009 2008 2009 2008
(In millions)
Service cost $ 23 $ 22 $ 66 $ 65
Interest cost 79 75 239 224
Expected return on plan assets (86 ) (116 ) (248 ) (347 )
Amortization of prior service cost 3 3 10 10
Recognized net actuarial loss 45 2 129 6
Net periodic cost (credit) $ 64 $ (14 ) $ 196 $ (42 )

Three Months Ended Nine Months Ended
September 30 September 30
Other Postretirement Benefits 2009 2008 2009 2008
(In millions)
Service cost $ 15 $ 5 $ 23 $ 14
Interest cost 13 18 51 55
Expected return on plan assets (9 ) (13 ) (27 ) (38 )
Amortization of prior service cost (48 ) (37 ) (127 ) (111 )
Recognized net actuarial loss 15 12 46 35
Net periodic cost (credit) $ (14 ) $ (15 ) $ (34 ) $ (45 )

Pension and other postretirement benefit obligations are allocated to ~~FirstEnergy's~~FirstEnergy’s subsidiaries employing the plan participants. ~~FES and the Utilities capitalize employee benefits related to construction projects.~~ The net periodic pension costs and net periodic other postretirement benefit costs (including amounts capitalized) recognized by ~~FES and each of the Utilities~~FirstEnergy’s subsidiaries for the three ~~months~~ and ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 and ~~2008~~2009 were as follows:


	Three Months Ended				Six Months Ended
	June 30				June 30
Pension Benefit Cost (Credit)	2010		2009		2010		2009
			*(In millions)*
FES	$	22	$	18	$	44	$	36
OE		6		7		11		14
CEI		5		5		11		10
TE		2		2		4		3
JCP&L		6		9		12		18
Met-Ed		3		6		5		11
Penelec		5		4		9		9
Other FirstEnergy Subsidiaries		15		15		29		31

	$	64	$	66	$	125	$	132

	Three Months Ended					Nine Months Ended
	September 30					September 30					Three Months Ended						Six Months Ended
Pension Benefit Cost (Credit)	2009		2008			2009		2008
											June 30						June 30
Other Postretirement Benefit Cost (Credit)											2010			2009			2010			2009
	(In millions)													*(In millions)*
FES	$	19	$	5		$	56	$	16		$	(7	)	$	(3	)	$	(13	)	$	(4	)
OE		6		(6	)		20		(18	)		(6	)		(3	)		(12	)		(5	)
CEI		5		(1	)		14		(3	)		(1	)		—			(3	)		1
TE		2		(1	)		5		(2	)		—			—			(1	)		1
JCP&L		8		(3	)		26		(10	)		(2	)		(1	)		(4	)		(2	)
Met-Ed		5		(2	)		16		(7	)		(2	)		(1	)		(4	)		(2	)
Penelec		4		(3	)		13		(9	)		(2	)		(1	)		(4	)		(2	)
Other FirstEnergy subsidiaries		15		(3	)		46		(9	)
Other FirstEnergy Subsidiaries												(8	)		(4	)		(16	)		(7	)
	$	64	$	(14	)	$	196	$	(42	)
											$	(28	)	$	(13	)	$	(57	)	$	(20	)

Three Months Ended Nine Months Ended
September 30 September 30
Other Postretirement Benefit Cost (Credit) 2009 2008 2009 2008
(In millions)
FES $ (4 ) $ (2 ) $ (8 ) $ (5 )
OE (3 ) (2 ) (8 ) (5 )
CEI - 1 1 2
TE 1 1 2 3
JCP&L (2 ) (4 ) (4 ) (12 )
Met-Ed (1 ) (3 ) (3 ) (8 )
Penelec (1 ) (3 ) (2 ) (10 )
Other FirstEnergy subsidiaries (4 ) (3 ) (12 ) (10 )
$ (14 ) $ (15 ) $ (34 ) $ (45 )

7.6. 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 ~~consolidate VIEs when they are determined~~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's~~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 ($1415 million)~~, the acquisition of additional interest in certain joint ventures ($13 million),~~ and distributions to owners ($4 million). for the six months ended June 30, 2010.

~~Mining Operations~~

~~On July 16, 2008, FEV entered into a~~FirstEnergy consolidates certain VIEs in which it has financial control through disproportionate economics in its equity and debt investments in the entities. These VIEs include: FEV’s joint venture ~~with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake~~ in the Signal Peak mining and coal transportation ~~operations near Roundup, Montana. FEV made a $125 million equity investment in~~operations; the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was completed in July 2009. Effective August 21, 2009, the joint venture acquired the remaining 20% stake in the mining operations by issuing a five-year note for $47.5 million. FEV consolidates the mining and transportation operations of this joint venture in its financial statements.

~~Trusts~~

~~FirstEnergy's consolidated financial statements include~~ PNBV and Shippingport ~~VIEs~~bond trusts that were created ~~in 1996 and 1997, respectively,~~ to refinance debt originally issued in connection with sale and leaseback ~~transactions. PNBV~~transactions; and ~~Shippingport financial data are included~~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 $326 million was outstanding as of June 30, 2010.

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 21 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 ~~consolidated financial statements~~creation of, OE and ~~CEI, respectively.~~has no equity or debt invested in, these entities.

~~PNBV was established to purchase a portion~~FirstEnergy has determined that for all but two of ~~the lease obligation bonds issued in connection with OE's 1987 sale and leaseback of its~~these entities, neither JCP&L, nor Met-Ed nor Penelec have variable interests in the ~~Perry Plant~~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 $53 million and ~~Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV~~$48 million for the ~~purchase~~three months ended June 30, 2010, and 2009, respectively and $117 million and $115 million for the six months ended June 30, 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 lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE. Shippingport was established to purchase allthese interests as it does not have control over the significant activities affecting the economics of the lease obligation bonds issued in connection with CEI's and TE's Bruce Mansfield Plant sale and leaseback transaction in 1987. CEI and TE used debt and available funds to purchase the notes issued by Shippingport.

~~Loss Contingencies~~

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~~company’s net exposure to loss based upon the casualty value provisions mentioned above:


	Maximum		Discounted Lease		Net
	Exposure		Payments, net⁽¹⁾		Exposure
	*(In millions)*
FES	$	1,352	$	1,165	$	187
OE		693		499		194
CEI⁽²⁾		662		70		592
TE⁽²⁾		662		339		323

Maximum Exposure
Discounted Lease Payments, net(1)
Net Exposure
(In millions)
FES $ 1,371 $ 1,193 $ 178
OE 729 561 168
CEI(2)
670 74 596
TE(2)
670 383 287

	~~(1)~~
⁽¹⁾		The net present value of ~~FirstEnergy's~~FirstEnergy’s consolidated sale and leaseback operating lease commitments is ~~$1.7 billion~~ $1.6 billion.


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

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

During the second quarter of 2008, NGC purchased 56.8 MW of lessor equity interests in the OE 1987 sale and leaseback of the Perry Plant and approximately 43.5 MW of lessor equity interests in the OE 1987 sale and leaseback of Beaver Valley Unit 2. In addition, NGC purchased 158.5 MW of lessor equity interests in the TE and CEI 1987 sale and leaseback of Beaver Valley Unit 2. The Ohio Companies continue to lease these MW under their respective sale and leaseback arrangements and the related lease debt remains outstanding.

~~Power Purchase Agreements~~

FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent they own a plant that sells substantially all of its output to the Utilities and the contract price for power is correlated with the plant's variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed and Penelec, maintains 25 long-term power purchase agreements with NUG entities. The agreements were entered into pursuant to the Public Utility Regulatory Policies Act of 1978. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, these entities.

FirstEnergy has determined that for all but eight of these entities, neither JCP&L, Met-Ed nor Penelec have variable interests in the entities or the entities are governmental or not-for-profit organizations not within the scope of consolidation consideration for VIEs. JCP&L, Met-Ed or Penelec may hold variable interests in the remaining eight entities, which sell their output at variable prices that correlate to some extent with the operating costs of the plants. FirstEnergy periodically requests from these eight entities the information necessary to determine whether they are VIEs or whether JCP&L, Met-Ed or Penelec is the primary beneficiary. FirstEnergy has been unable to obtain the requested information, which in most cases was deemed by the requested entity to be proprietary. As such, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Since FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs it may incur for power. FirstEnergy expects any above-market costs it incurs from those contracts to be recovered from customers. Purchased power costs from these entities during the three months and nine months ended September 30, 2009 and 2008 are shown in the following table:

Three Months Ended Nine Months Ended
September 30 September 30
2009 2008 2009 2008
(In millions)
JCP&L $ 20 $ 26 $ 57 $ 67
Met-Ed 11 12 39 44
Penelec 9 8 26 25
Total $ 40 $ 46 $ 122 $ 136

~~Transition Bonds~~

The consolidated financial statements of FirstEnergy and JCP&L include the results of JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. In June 2002, JCP&L Transition Funding sold $320 million of transition bonds to securitize the recovery of JCP&L's bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold $182 million of transition bonds to securitize the recovery of deferred costs associated with JCP&L's supply of BGS.

JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy's and JCP&L's Consolidated Balance Sheets. As of September 30, 2009, $349 million of the transition bonds were outstanding. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II, and are collateralized by each company's equity and assets, which consists primarily of bondable transition property.

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

8.7. 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~~company’s tax return. After reaching a settlement at appeals related primarily to the capitalization of certain costs for the tax years 2005-2008, as well as reaching a settlement on an unrelated state tax matter in the second quarter of 2010, FirstEnergy recognized approximately $70 million of net tax benefits, including $13 million that favorably affected FirstEnergy’s effective tax rate for the second quarter of 2010. The remaining portion of the tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item. 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. Material changes to FirstEnergy's unrecognized tax benefits during the third quarter of 2009 are described further below. Upon completion of the federal tax examinations for tax years 2004 to 2006 in the third quarter of 2008, FirstEnergy recognized approximately $45 million in tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate. ~~A majority~~There were no material changes to FirstEnergy’s unrecognized tax benefits in the second quarter of 2009.

As of June 30, 2010, it is reasonably possible that approximately $11 million of the tax benefits recognized in the third quarter of 2008 adjusted goodwill as a purchase accounting adjustment ($20 million) and accumulated deferred income taxes for temporary tax items ($15 million). As of September 30, 2009, FirstEnergy expects that $197 million of unrecognized benefits ~~will~~may be resolved within the next twelve months, of which approximately ~~$148~~$11 million, if recognized, would affect ~~FirstEnergy's~~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.

~~The Company~~FirstEnergy 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 ~~$45 million in~~ recognized tax benefits ~~in 2008~~noted above favorably affected FirstEnergy’s effective tax rate by ~~$12~~$11 million in the ~~third quarter and~~ first ~~nine~~six months of ~~2008.~~2010. During the first ~~nine~~six months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of ~~September~~June 30, ~~2009~~2010 was ~~$67million,~~$6 million, as compared to ~~$59~~$21 million as of December 31, ~~2008.~~2009.

~~In 2008,~~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 ~~on behalf of FGCO and NGC, filed a change in accounting method related~~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 ~~repair and maintain electric generation stations. During~~FirstEnergy’s earnings in the ~~second~~first quarter of ~~2009,~~2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. This change reflects the ~~IRS approved~~anticipated increase in income taxes that will occur as a result of the change in ~~accounting method and $281 million of costs were included as a repair deduction in FirstEnergy’s 2008 consolidated~~ tax return. Since the IRS did not complete its review over this change in accounting method by the extended filing date of FirstEnergy’s federal tax return, FirstEnergy increased the amount of unrecognized tax benefits by $34 million in the third quarter of 2009, 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 the quarter.

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 ~~are~~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 ~~the~~ years 2004-2006 were completed in the third quarter of 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. In the second quarter of 2010, the items under appeal for tax years 2006 and 2007 were settled and sent to Joint Committee on Taxation for final review. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year ~~2009~~audit began in February 2009 ~~under its Compliance Assurance Process program.~~and the 2010 tax year began in February 2010. Neither audit is expected to close before December ~~2009.~~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~~FirstEnergy’s financial condition or results of operations.

9.8. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A) GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of ~~September~~June 30, ~~2009,~~2010, outstanding guarantees and other assurances aggregated approximately ~~$4.1~~$3.9 billion, consisting primarily of parental guarantees ($10.9 billion), subsidiaries’ guarantees ($~~2.6~~2.5 billion), surety bonds ~~($0.1 billion)~~ and LOCs ($~~0.4~~0.5 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements 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'~~counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, ~~FirstEnergy's~~FirstEnergy’s guarantee enables the ~~counterparty's~~counterparty’s legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of ~~$0.4~~$0.3 billion (included in the $1$0.9 billion ~~shown~~discussed above) as of ~~September~~June 30, ~~2009~~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 ana LOC or accelerated payments may be required of the subsidiary. As of ~~September~~June 30, ~~2009, FirstEnergy's~~2010, FirstEnergy’s maximum exposure under these collateral provisions was ~~$616~~$451 million, consisting of ~~$53~~$37 million due to “material adverse event” contractual clauses, $83 million due to an acceleration of payment or funding obligation, and ~~$563~~$331 million due to a below investment grade credit rating. Additionally, stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase this amount to ~~$699~~$609 million, consisting of ~~$60~~$56 million due to “material adverse event” contractual clauses, $83 million related to an acceleration of payment or funding obligation, and ~~$639~~$470 million due to a below investment grade credit rating.

Most of ~~FirstEnergy's~~FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of ~~$103~~$90 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ ~~contracts~~power portfolio as of ~~September~~June 30, ~~2009,~~2010, and forward prices as of that date, FES ~~had $183 million~~has posted collateral of ~~outstanding collateral payments of which $134 million is included in other assets on the Consolidated Balance Sheet as of September 30, 2009.~~$245 million. Under a hypothetical adverse change in forward prices ~~(15% decrease~~(95% confidence level change in ~~the first 12 months and 20% decrease in~~forward prices ~~thereafter)~~over a one year time horizon), FES would be required to post an additional ~~$45~~$107 million. Depending on the volume of forward contracts and future price movements, FES could be required to post ~~significantly~~ higher amounts for margining.

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

In July 2007, FGCO completed a sale and leaseback transaction for its 93.825% undivided interest in Bruce Mansfield Unit 1. FES has fully and irrevocably guaranteed all of FGCO’s obligations under each of the leases (see Note 13). 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.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, ~~pursuant to~~and FES 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~~Compliance with ~~regard to~~ environmental ~~matters~~regulations could have a material adverse effect on ~~FirstEnergy's~~FirstEnergy’s earnings and competitive position to the extent that itFirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. ~~FirstEnergy estimates capital expenditures for environmental compliance of approximately $800 million for the period 2009-2013.~~

CAA Compliance

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 and NO_X emissions ~~regulations.~~regulations under the CAA. FirstEnergy complies with SO₂ and NOx reduction requirements under the CAA and State Implementation Plan(s) under the CAA (SIPs) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants, and/or using emission allowances. 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 SO~~2 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.penalties.

~~FirstEnergy complies with SO~~2 ~~reduction requirements under the Clean Air Act Amendments of 1990 by burning lower-sulfur fuel, generating more electricity from lower-emitting plants, and/or using emission allowances. NO~~X reductions required by the 1990 Amendments are being achieved through combustion controls, the generation of more electricity at lower-emitting plants, and/or using emission allowances. In September 1998, the EPA finalized regulations requiring additional NOX ~~reductions at FirstEnergy's facilities.~~ The ~~EPA's NO~~X ~~Transport Rule imposes uniform reductions of NO~~X ~~emissions (an approximate 85% reduction in utility plant NO~~X ~~emissions from projected 2007 emissions) across a region of nineteen states (including Michigan, New Jersey, Ohio and Pennsylvania) and the District of Columbia based on a conclusion that such NO~~X ~~emissions are contributing significantly to ozone levels in the eastern United States. FirstEnergy believes its facilities are also complying with the NO~~X ~~budgets established under SIPs through combustion controls and post-combustion controls, including Selective Catalytic Reduction and SNCR systems, and/or using emission allowances.~~

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX ~~and SO~~2 ~~emissions at the~~ Sammis, Burger, Eastlake and Mansfield coal-fired plants are operated under a consent decree with the EPA and DOJ that requires reductions of NO_X and SO₂ emissions through the installation of pollution control devices or ~~repowering~~repowering. OE and ~~provides for~~Penn are subject to 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,~~combustion, are currently estimated to be ~~$706~~approximately $399 million for ~~2009-2012 (with $414 million expected to be spent in 2009).~~2010-2012.

~~On May 22,~~In 2007, ~~FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of~~PennFuture filed a citizen suit under the ~~federal~~ CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members,limitations, in the ~~United States~~U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the ~~United States~~U.S. District Court for the Western District of Pennsylvania also seeking damages based on Bruce Mansfield Plant air emissions. ~~In addition to seeking damages, two~~Two of ~~the three~~these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. ~~On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. On August 17, 2009, a~~A settlement ~~of the PennFuture complaint~~ was reached with ~~PennFuture and one of the three individual complainants. On October 16, 2009, the Court approved the settlement and dismissed~~PennFuture. FGCO believes the claims of ~~PennFuture and of~~ the ~~settling individual complainant. The other two non-settling complainants are now represented by counsel handling the three cases filed in July 2008. FGCO believes those claims~~remaining plaintiffs 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.

~~On December 18, 2007, the state~~states of New Jersey and Connecticut filed a CAA citizen ~~suit~~suits in 2007 alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU ~~Inc.~~ and Met-Ed. ~~On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009.~~ Specifically, ~~Connecticut and New Jersey~~these suits allege that ~~"modifications"~~“modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the ~~CAA's prevention of significant deterioration~~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. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale ofIn September 2009, the ~~plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009, and on September 30, 2009, respectively. The~~ Court granted ~~Met-Ed's~~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~~penalties. The parties dispute the scope of ~~limitations grounds in order~~Met-Ed’s indemnity obligation 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.~~and from Sithe Energy.

OnIn January ~~14,~~ 2009, the EPA issued a NOV to Reliant alleging ~~new source review~~NSR violations at the Portland Generation Station based on “modifications” dating back to ~~1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV~~1986 and also alleged ~~new source review~~NSR violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. Met-Ed, 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.

OnIn June ~~11,~~ 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that ~~"modifications"~~“modifications” at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the ~~CAA's prevention~~CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station containing in all material respects identical allegations as the June 2008 NOV. On July 20, 2010, the states of ~~significant deterioration program.~~New York and Pennsylvania provided Mission Energy Westside, Inc., Penelec, NYSEG and others that have had an ownership interest in the Homer City Power Station a notification required 60 days prior to filing a citizen suit under the CAA. 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.~~under dispute and Penelec is unable to predict the outcome of this matter.

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. OnIn August ~~12,~~ 2009, the EPA issued a Finding of Violation and NOV alleging violations of the ~~Clean Air Act~~CAA and Ohio regulations, including the ~~prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”),~~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. ~~On September 15, 2009,~~ FGCO received ~~an additional information~~a request ~~pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit~~for certain operating and maintenance information and planning information ~~regarding the Eastlake, Lake Shore, Bay Shore~~for these same generating plants 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. Later in 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. ~~A June 15, 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.~~

On August 18, 2008, FirstEnergy received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding its formerly-owned Avon Lake and Niles generating plants, as well as a copy of a nearly identical request directed to the current owner, Reliant Energy, to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. FirstEnergy intends to fully comply with the EPA’s information request, but, at this time, is unable to predict the outcome of this matter.

National Ambient Air Quality Standards

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.The EPA’s CAIR requires reductions of NO_X and SO₂ emissions in two phases ~~(Phase I in 2009 for NO~~X, (2009/2010 ~~for SO~~2and ~~Phase II in 2015 for both NO~~X ~~and SO~~2)2015), ultimately capping SO₂ emissions in affected states to 2.5 million tons annually and NO_X emissions to 1.3 million tons annually. ~~CAIR was challenged in~~In 2008, the ~~United States~~U.S. Court of Appeals for the District of Columbia ~~and on July 11, 2008, the Court~~ vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” ~~On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On~~In December ~~23,~~ 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s ~~July 11, 2008~~ opinion. ~~On July 10, 2009, the United States~~The Court ~~of Appeals for the District of Columbia~~ ruled in a different case that a cap-and-trade program similar to CAIR, called the “NO_X SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the ~~"8-hour"~~“8-hour” ozone NAAQS. ~~FGCO's~~In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NO_X and SO₂ emissions in two phases (2012 and 2014), ultimately capping SO₂ emissions in affected states to 2.6 million tons annually and NO_X emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NO_X and SO₂ emission allowances between power plants located in the same state with severe limits on interstate trading and two alternative approaches—the first eliminates interstate trading of NO_X and SO₂ emission allowances and the second eliminates trading of NO_X and SO₂ emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below, and any future regulations that are ultimately implemented, FGCO’s future cost of compliance ~~with these regulations~~ may be ~~substantial~~substantial. Management is currently assessing the impact of these environmental proposals and ~~will depend, in part,~~other factors on FGCO’s facilities, particularly on the ~~action taken by the EPA in response~~operation of its smaller, non-supercritical units. For example, management may decide to ~~the Court’s ruling.~~idle certain of these units or operate them on a seasonal basis until developments clarify.

Hazardous Air Pollutant Emissions

~~Mercury Emissions~~

In December 2000, the EPA announced it would proceed with the development of regulations regarding hazardous air pollutants from electric power plants, identifying mercury as the hazardous air pollutant of greatest concern. In March 2005, the EPA finalized theThe EPA’s CAMR ~~which~~ provides for a cap-and-trade program to reduce mercury emissions from coal-fired power plants in two phases; initially, capping ~~national~~nationwide emissions of mercury ~~emissions~~ at 38 tons by 2010 (as a ~~"co-benefit"~~“co-benefit” from implementation of SO₂ and NO_X emission caps under the ~~EPA's~~EPA’s CAIR program) and 15 tons per year by 2018. ~~Several states and environmental groups appealed the CAMR to the United States~~The U.S. Court of Appeals for the District of ~~Columbia. On February 8, 2008,~~Columbia, at the ~~Court~~urging of several states and environmental groups vacated the CAMR, ruling that the EPA failed to take the necessary steps to “de-list” coal-fired power plants from its hazardous air pollutant program and, therefore, could not promulgate a cap-and-trade program. The EPA petitioned for rehearing by the entire Court, which denied the petition on May 20, 2008. On October 17, 2008, the EPA (and an industry group) petitioned the United States Supreme Court for review of the Court’s ruling vacating CAMR. On February 6, 2009, the EPA moved to dismiss its petition for certiorari. On February 23, 2009, the Supreme Court dismissed the EPA’s petition and denied the industry group’s petition. On October 21, 2009, the EPA openedentered into a ~~30-day comment period on a proposed~~ consent decree ~~that would obligate the EPA~~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. ~~FGCO’s future cost of compliance with~~On April 29, 2010, the EPA issued proposed MACT regulations ~~may be substantial~~requiring emissions reductions of mercury and ~~will depend~~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.~~

implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On ~~January 30,~~December 23, 2009, the Supreme Court of Pennsylvania affirmed the Commonwealth Court of Pennsylvania ~~declared~~ruling that Pennsylvania’s mercury rule is “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at the Bruce Mansfield Plant (FirstEnergy’s only Pennsylvania coal-fired power plant) until 2015, if at all.

Climate Change

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

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

~~On April 2, 2007, the United States Supreme Court found that the~~The EPA has ~~the authority to regulate CO~~2 ~~emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO~~2 ~~emissions from electric generating plants, the EPA has similar~~ authority under the CAA to regulate “air pollutants” from ~~those~~electric generating plants and other facilities. ~~On April 17,~~In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released ~~a “Proposed Endangerment~~its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s ~~proposed~~ finding concludes that ~~the atmospheric~~ concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence toGHG increase the threat of climate change. ~~Although~~In April 2010, the ~~EPA’s proposed finding, if~~EPA finalized ~~does~~new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA will not ~~establish emission requirements~~be triggered for ~~motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including~~ electric generating plants ~~those findings, if finalized, would be expected to support~~and other stationary sources until January 2, 2011, at the ~~establishment of future emission requirements by~~earliest. In May 2010, the EPA ~~for stationary sources. On September 23, 2009, the EPA~~ finalized a GHG reporting rule establishing a national GHG emissions collection and reporting program. The EPA rules will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, EPA proposed new thresholds for GHG emissions that define when ~~Clean Air Act~~ permits under the ~~New Source Review and Title V operating permits programs~~CAA program would be required. The EPA ~~is proposing a major source~~established an emissions applicability threshold of ~~25,000~~75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the ~~Title V operating permits program and the~~CAA’s Prevention of Significant Determination (PSD) ~~portion~~program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.

At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of ~~NSR. EPA is also proposing~~man-made GHG, including CO₂, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a ~~significance level between 10,000~~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 ~~25,000 tpy CO2e~~established the “Copenhagen Green Climate Fund” to ~~determine if existing major sources making modifications that result~~support mitigation, adaptation, and other climate-related activities in ~~an increase of~~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 ~~above the significance level~~targets from 2020, while developing countries, including Brazil, China, and India, would ~~be required~~agree to ~~obtain a PSD permit.~~take mitigation actions, subject to their domestic measurement, reporting, and verification.

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.~~grounds; however, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. 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. ~~Connecticut v. AEP, No. 05-5105-cv (2d Cir. 2009)(seeking injunctive relief only);~~ ~~Comer v. Murphy Oil USA, No. 07-6-756 (5~~th ~~Cir. 2009)(seeking damages only), respectively.~~ While FirstEnergy is not a party to ~~either~~this litigation, should the ~~courts~~court of appeals ~~decisions~~decision 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~~FirstEnergy’s plants. In addition, Ohio, New Jersey and Pennsylvania have water quality standards applicable to ~~FirstEnergy's~~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.

cooling water intake structures. On April 1, 2009, the U.S. Supreme Court ~~of the United States~~ reversed one significant aspect of the Second ~~Circuit Court’s~~Circuit’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.~~effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15, 2010, the EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

~~The~~In June 2008, the U.S. ~~Attorney'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

AsFederal and state hazardous waste regulations have been promulgated 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.~~1976. Certain fossil-fuel combustion ~~waste products,~~residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the ~~EPA's~~EPA’s evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion ~~wastes,~~residuals, including whether they should be regulated as hazardous or non-hazardous waste.

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 proposed two options for additional regulation ~~as non-hazardous waste or~~of coal combustion residuals, including the option of regulation as a ~~hazardous waste. In March and June 2009,~~special waste under the ~~EPA requested information from FGCO’s Bruce Mansfield Plant regarding the management of coal combustion wastes.~~ ~~The EPA is reviewing its previous determination that Federal regulation of coal ash as a~~EPA’s hazardous waste ~~is not appropriate. The EPA has indicated an intent to propose regulations regarding this issue by the end of the year. Additional regulations of fossil-fuel combustion waste products~~management program which could have a significant impact on ~~our~~the management, beneficial use and disposal of coal ~~ash.~~ ~~FGCO's~~combustion residuals. FGCO’s future cost of compliance with any coal combustion ~~waste~~residuals regulations which may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

The Utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the Comprehensive Environmental Response, Compensation, and Liability Act of 1980. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the consolidated balance sheet as of ~~September~~June 30, ~~2009,~~2010, based on estimates of the total costs of cleanup, the ~~Utilities'~~Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$104~~$105 million (JCP&L ~~- - $77~~— $76 million, TE - $1 million, CEI -— $1 million, FGCO -— $1 million and FirstEnergy ~~- $24~~— $26 million) have been accrued through ~~September~~June 30, ~~2009.~~2010. Included in the total are accrued liabilities of approximately ~~$68~~$67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(C) OTHER LEGAL PROCEEDINGS

~~Other Legal Proceedings~~

Power Outages and Related Litigation

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~~&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'~~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)~~Early in 2010, the Appellate Division ~~limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based~~heard oral argument 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 theirplaintiff’s appeal of the trial ~~court's~~court’s decision decertifying the ~~class. The~~class, and on July 29, 2010, the Appellate Division upheld the trial court’s decision.

Litigation Relating to the Proposed Allegheny Energy Merger

agreement, and that Allegheny Energy, FirstEnergy and Merger Sub aided and abetted in these alleged breaches of fiduciary duty. The complaints seek, among other things, jury trials, money damages and injunctive relief. Additional details about the actions are provided below. While FirstEnergy believes the lawsuits are without merit and has ~~scheduled~~defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendants reached an agreement with counsel for all of the plaintiffs concerning fee applications, but a formal stipulation of settlement has not yet been filed with any court. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and 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. 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.

Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland. One was withdrawn. The court consolidated the three cases under the captionOakmont Capital Management, LLC v. Evanson, et al., C.A. No. 24-C-10-1301, and appointed Lewis M. Lynn as Lead Plaintiff. Plaintiff Lynn filed a Consolidated Amended Complaint on April 12, 2010. On April 21, 2010, defendants filed Motions to Dismiss the Consolidated Amended Complaint for failure to state a claim. The court has stayed all discovery pending resolution of those motions. The court also has entered a stipulated order certifying a class with no opt-out rights. On May 27, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement and requested that the court cancel the oral argument on the motions to dismiss that had been scheduled for ~~January~~June 3, 2010. On May 28, 2010, the court removed the hearing from its calendar.

Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania, raising putative class action and derivative claims against the Allegheny Energy directors and officers, FirstEnergy and Allegheny Energy. The court has consolidated these actions under the caption,In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010, and appointed lead counsel. On April 5, ~~2010..~~2010, the Allegheny Energy defendants filed a Motion to Stay the Proceedings. Shortly thereafter, FirstEnergy similarly filed a Motion to Stay. Plaintiffs filed a Motion for Expedited Discovery. The court scheduled a hearing on the motions for May 27, 2010. On May 21, 2010, plaintiffs filed a Verified Consolidated Shareholder Derivative and Class Complaint. On May 26, 2010, the parties filed a Motion for a Continuance of the May 27 hearing, which the court granted. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.

A putative shareholder lawsuit styled as a class action was filed in the U.S. District Court for the Western District of Pennsylvania and is captionedLouisiana Municipal Police Employees’ Retirement System v. Evanson, et al., C.A. No. 10-319 NBF. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.

Nuclear Plant Matters

During a planned refueling outage that began on February 28, 2010, FENOC conducted a non destructive examination and testing of the Control Rod Drive Mechanism (CRDM) Nozzles of the Davis-Besse reactor pressure vessel head. FENOC identified flaws in CRDM nozzles that required modification. The NRC was notified of these findings, along with federal, state and local officials. On March 17, 2010, the NRC sent a special inspection team to Davis-Besse to assess the adequacy of FENOC’s identification, analyses and resolution of the CRDM nozzle flaws and to ensure acceptable modifications were made prior to placing the RPV head back in service. After successfully completing the modifications, FENOC committed to take a number of corrective actions including strengthening leakage monitoring procedures and shutting Davis-Besse down no later than October 1, 2011, to replace the reactor pressure vessel head with nozzles made of material less susceptible to primary water stress corrosion cracking further enhancing the safe and reliable operations of the plant. On June 29, 2010, FENOC returned Davis-Besse to service.

~~In August 2007, FENOC submitted an application~~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 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. By a letter dated July 13, 2010, the NRC denied UCS’s request for immediate action because “the NRC has conducted rigorous and independent assessments of returning the Davis-Besse reactor vessel head to service and its continued operation, and determined that it was safe for the plant to restart.” The UCS petition was referred to a petition manager for further review. What additional actions, if any that the NRC takes in response to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. On November 5, 2009, the NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities was extended until 2036 and 2047 for Units 1 and 2, respectively.

UCS request, have not been 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 ~~September~~obligations. As of June 30, ~~2009,~~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. ~~As required by~~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 ~~FirstEnergy annually recalculates and adjusts the amount of its~~reduce FirstEnergy’s parental guarantee ~~as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If~~to $15 million and notified the ~~value of~~staff that it no longer planned to make the ~~trusts decline by~~additional contributions into the trusts. By a ~~material amount, FirstEnergy’s obligations~~letter dated July 14, 2010, the NRC stated that it had no objection to ~~fund~~ the ~~trusts may increase. The recent disruption~~reduction in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. On October 20, 2009, FENOC received a request for additional information (RAI) from the NRC that questions FENOC's methodology for calculating the decommissioning obligations for Beaver Valley Unit 1. Renewal of the operating license for Beaver Valley Unit 1 is expected to mitigate the estimated shortfall in the unit’s nuclear decommissioning funding status. FENOC continues to communicate with the NRC regarding future actions to provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.guarantee.

Other Legal Matters

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

On April 14, 2010, JCP~~&L's~~&L reached an agreement on a settlement package with its bargaining unit employees ~~filed~~regarding a grievance challenging JCP~~&L's~~&L’s 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. ~~On May 20, 2004,~~The agreement included an ~~arbitration panel concluded that~~agreed-upon settlement amount and extension of the ~~call-out procedure violated the parties'~~ collective bargaining agreement. On ~~September 9, 2005,~~July 22, 2010, the ~~arbitration panel issued~~court signed an ~~opinion~~order approving and implementing the parties’ agreement. As of June 30, 2010, JCP&L reduced its reserve to ~~award approximately $16~~$9 million for the settlement which will be paid to the employees over the next thirty days beginning on July 25, 2010. The collective bargaining ~~unit employees. A final order identifying~~agreement extension is also effective as of July 25, 2010.

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 ~~individual damage amounts~~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 ~~issued on October 31, 2007 and~~approved by the ~~award appeal process was initiated. The union~~PUCO. On March 18, 2010, the named-defendant companies filed a motion ~~with~~to dismiss the ~~federal Court~~case due to ~~confirm~~ the ~~award and JCP&L filed its answer and counterclaim to vacate~~lack of jurisdiction of the ~~award~~court of common pleas. The court has not yet ruled 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~~that motion to ~~vacate the arbitration decision and granted the union’s motion~~dismiss. The named-defendant companies will continue to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. The parties are participating in the federal court's mediation programs and have held private settlement discussions. JCP&L recognized a liability for the potential $16 million award in 2005. Post-judgment interest began to accrue as of February 25, 2009, and the liability will be adjusted accordingly.

The bargaining unit employees at the Bruce Mansfield Plant have been working without a labor contract since February 15, 2008. On July 24, 2009, FirstEnergy declared that bargaining was at an impasse and portions of its last contract offer were implemented August 1, 2009, and a voluntary retirement program was implemented on August 19, 2009. A federal mediator is continuing to assist the parties in reaching a negotiated contract settlement. FirstEnergy has a strike mitigation plan ready in the event of a strike.

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~~FirstEnergy’s or its ~~subsidiaries'~~subsidiaries’ financial condition, results of operations and cash flows.

~~10.~~9. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

~~In 2005, Congress amended the Federal Power Act to provide for federally-enforceable mandatory reliability standards. The~~Federally-enforceable 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~~these reliability standards to eight regional entities, including ReliabilityFirstCorporation. All of FirstEnergy’s facilities are located within the ReliabilityFirstregion. FirstEnergy actively participates in the NERC and ReliabilityFirststakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability ~~standards.~~standards implemented and enforced by the ReliabilityFirstCorporation.

FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, ~~it is clear~~FirstEnergy also believes that the NERC, ReliabilityFirstand 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~~time; however, 2005 amendments to the ~~Federal Power Act~~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 ~~and thus~~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 MISO region and found it to be in full compliance with all audited reliability standards. Similarly, in October 2008, Reliability~~First~~ ~~performed a routine compliance audit of FirstEnergy’s bulk-power system within the PJM region and found it to be in full compliance with all audited reliability standards.~~

On December 9, 2008, a transformer at JCP&L’s Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations ~~with~~resulting in customers ~~in the affected area~~ losing ~~power. Power was restored~~power for up 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~~NERC has submitted first and second Requests for Information regarding this and another related matter. 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~~is complying 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.~~these requests. JCP&L is not able ~~at this time~~ to predict what actions, if any, that the NERC may take ~~based~~with respect to this matter.

(B) OHIO

The Ohio Companies operate under an Amended ESP, which expires on ~~the data submittals or interview results.~~

~~On June 5, 2009, FirstEnergy self-reported to ReliabilityFirst~~May 31, 2011, and provides for generation supplied through a potential violation of NERC Standard PRC-005 resulting from its inability to validate maintenance records for 20 protection system relays in JCP&L’s and Penelec’s transmission systems. These potential violations were discovered during a comprehensive field review of all FirstEnergy substations to verify equipment and maintenance database accuracy. FirstEnergy has completed all mitigation actions, including calibrations and maintenance records for the relays. Reliability~~First~~ ~~issued an Initial Notice of Alleged Violation on June 22, 2009.~~CBP. 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 Reliability~~First~~ ~~will propose for this self-report of violation.~~

~~(B) OHIO~~

~~On June 7, 2007,~~Amended ESP also allows the Ohio Companies ~~filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing~~ to support a distribution rate increase of $332 million. On December 4, 2007, the PUCO Staff issued its Staff Reports containing the results of its investigation into the distribution rate request. On January 21, 2009, the PUCO granted the Ohio Companies’ application to increase electric distribution rates by $136.6 million (OE - $68.9 million, CEI - $29.2 million and TE - $38.5 million). These increases went into effect for OE and TE on January 23, 2009, and for CEI on May 1, 2009. Applications for rehearing of this order were filed by the Ohio Companies and one other party on February 20, 2009. The PUCO granted these applications for rehearing on March 18, 2009 for the purpose of further consideration. The PUCO has not yet issued a substantive Entry on Rehearing.

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their 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. The average winning bid price was equivalent to a retail rate of 6.98 cents per KWH. The power supply obtained through this process provided generation service to the Ohio Companies’ retail customers who chose not to shop with alternative suppliers. On January 9, 2009, the Ohio Companies requested the implementation of a new fuel rider to recover the costs resulting from the December 31, 2008 CBP. The PUCO ultimately approved the Ohio Companies’ request for a new fuel rider to recover increased costs resulting from the CBP but denied OE’s and TE’s request to continue collecting RTC and denied the request to allow the Ohio Companies to continue collections pursuant to the two existing fuel riders. The new fuel rider recovered the increased purchased power costs for OE and TE, and recovered a portion of those costs for CEI, with the remainder being deferred for future recovery.

On January 29, 2009, the PUCO ordered its Staff to develop a proposal to establish an ESP for the Ohio Companies. On February 19, 2009, the Ohio Companies filed an Amended ESP application, including an attached Stipulation and Recommendation that was signed by the Ohio Companies, the Staff of the PUCO, and many of the intervening parties. Specifically, the Amended ESP provided that generation would be provided by FES at the average wholesale rate of the CBP process described above for April and May 2009 to the Ohio Companies for their non-shopping customers; for the period of June 1, 2009 through May 31, 2011, retail generation prices would be based upon the outcome of a descending clock CBP on a slice-of-system basis. The Amended ESP further provided that the Ohio Companies will not seek a base distribution rate increase, subject to certain exceptions, with an effective date of such increase before January 1, 2012, that CEI would agree to write-off approximately $216 million of its Extended RTC balance, and that the Ohio Companies would collect a delivery service improvement rider (Rider DSI) at an overall average rate of ~~$.002~~$0.002 per KWH for the period of April 1, 2009 through December 31, 2011. The ~~Amended ESP also addressed~~Ohio Companies currently purchase generation at the average wholesale rate of a ~~number of other issues, including but not limited to, rate design for various customer classes, and resolution~~CBP conducted in May 2009. FES is one of the ~~prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009,~~suppliers to the Ohio Companies ~~filed a Supplemental Stipulation, which was signed or not opposed by virtually all of~~through 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.CBP. 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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~~On July 27, 2009,~~a $136.6 million distribution rate increase for the Ohio Companies ~~filed applications with~~in January 2009, which went into effect on January 23, 2009 for OE ($68.9 million) and TE ($38.5 million) and on May 1, 2009 for CEI ($29.2 million). As one element of the ~~PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies'~~ Amended ESP, the Ohio Companies agreed not to seek an additional base distribution rate increase, subject to certain exceptions, that would be effective before January 1, 2012. Applications for rehearing of the PUCO ~~approved~~order in the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applicationsdistribution case were ~~approved~~filed by the PUCO on August 19, 2009. Recovery of this amount, together with carrying charges calculated as approved in the Amended ESP, commenced on September 1, 2009, and will be collected in the 18 non-summer months from September 2009 through May 2011, subject to reconciliation until fully collected, with $165 million of the above amount being recovered from residential customers, and $140.1 million being recovered from non-residential customers.

The CBP auction occurred on May 13-14, 2009, and resulted in a weighted average wholesale price for generation and transmission of 6.15 cents per KWH. The bid was for a single, two-year product for the service period from June 1, 2009 through May 31, 2011. FES participated in the auction, winning 51% of the tranches (one tranche equals one percent of the load supply). Subsequent to the signing of the wholesale contracts, three winning bidders reached separate agreements with FES to assign a total of 21 tranches to FES for various periods. The results of the CBP were accepted by the PUCO on May 14, 2009. In addition, FES has separately contracted with numerous communities to provide retail generation service through governmental aggregation programs.

SB221 also requires electric distribution utilities to implement energy efficiency programs. 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 seventy-five hundredths of one percent reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances. Additionally, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they serve in 2009. The Ohio Companies are presently involved in collaborative efforts related to energy efficiency, including filing applications for approval with the PUCO, as well as other implementation efforts arising out of the Supplemental Stipulation. We expect that all costs associated with compliance will be recoverable from customers.

On June 17, 2009, the PUCO modified rules that implement the alternative energy portfolio standards created by SB221, including the incorporation of energy efficiency requirements, long-term forecast and greenhouse gas reporting and CO2 control planning. The PUCO filed the rules with the Joint Committee on Agency Rule Review (JCARR) on July 7, 2009, after which began a 65-day review period. On August 6, 2009, the PUCO withdrew alternative energy and energy efficiency/peak demand reduction rules from JCARR. On August 24, 2009, the integrated resource planning rules were also withdrawn from JCARR. The Ohio Companies and one other party filed applications for rehearing on the rules with the PUCO on July 17, 2009. On August 11, 2009, the PUCO issued an entry on rehearing granting the applications for rehearing only for purposes of further consideration of the issues raised.

On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 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. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio Companies' customers. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency applications submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO.party. The Ohio Companies ~~asked~~raised numerous issues in their application for rehearing related to rate recovery of certain expenses, recovery of line extension costs, the ~~Commission to issue~~level of rate of return and the amount of general plant balances. The PUCO has not yet issued a ~~ruling~~substantive Entry on ~~or before December 2, 2009.~~Rehearing.

In August and October 2009, the Ohio Companies conducted RFPs to secure Renewable Energy Credits (RECs). The RFPs includes solar and other renewable energy RECs, including those generated in Ohio. The RECs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010, and 2011.

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~~through a CBP, ~~to secure~~ generation supply for customers who do not shop with an alternative supplier ~~and~~for the period beginning June 1, 2011. The CBP 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 ~~reduce~~and supplier risk and encourage bidder participation. A technical conference ~~was~~and hearings were held ~~on October 29,~~in 2009 atand the ~~PUCO.~~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, therefore,~~requirements. Although the Ohio Companies ~~have~~ requested a PUCO determination by January 18, ~~2020.~~2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements ~~were~~are met, and to the extent the ESP described below has not been implemented, the Ohio Companies would ~~be able~~expect to implement the MRO.

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 substitutes for 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 would not issue a decision on May 5, 2010, and would take additional time to review the case record. FirstEnergy recorded approximately $39.5 million of regulatory asset impairments and expenses related to the ESP. On May 12, 2010 a supplemental stipulation was filed that added two additional parties to the Stipulation, namely the City of Akron, Ohio and Council for Smaller Enterprises, to provide additional energy efficiency benefits. Pursuant to a PUCO Entry, a hearing was held on June 21, 2010 to consider the estimated bill impacts arising from the proposed ESP, and testimony was provided in support of the supplemental stipulation. On July 22, 2010, a second supplemental stipulation was filed that, among other provisions and if approved, would provide a commitment that retail customers of the Ohio Companies will not pay certain costs related to the companies’ integration into PJM, a regional transmission organization, for the longer of the five year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals $360 million, and establishes a $12 million fund to assist low income customers over the term of the ESP. Additional parties signing or not opposing the second supplemental stipulation include Northeast Ohio Public Energy Council (NOPEC), Northwest Ohio Aggregation Coalition (NOAC), Environmental Law and Policy Center and a number of low income community agencies. A hearing was held on the second supplemental stipulation on July 29, 2010. The matter is awaiting decision from the PUCO.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will 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 0.75% reduction each year thereafter through 2018. The PUCO may amend these benchmarks in certain, limited circumstances, and the Ohio Companies filed an application with the PUCO seeking such amendments. On January 7, 2010, the PUCO amended the Ohio Companies’ 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 the Ohio Companies peak demand reduction programs complied with PUCO rules.

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. 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. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The Ohio Companies’ three year portfolio plan is still awaiting decision from the PUCO. The plan has yet to be approved by the PUCO, which is delaying the launch of the programs described in the plan. Without such approval, the Ohio Companies’ compliance with 2010 benchmarks is jeopardized and if not approved soon may require the Ohio Companies to seek an amendment to their annual benchmark requirements for 2010. Failure to comply with the benchmarks or to obtain such an amendment may subject the Companies to an assessment by the PUCO of a forfeiture.

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 March 10, 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market. 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 July 1, 2010, the Ohio Companies announced their intent to conduct an RFP in 2010 to secure RECs and solar RECs needed to meet the ~~CBP~~

Ohio Companies’ alternative energy requirements as set forth in SB221. RFP bids are due August 3, 2010 and contracts are expected to be signed the week of August 9, 2010.

On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010. The Ohio Companies also filed on May 14, 2010 an application for rehearing of the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. No hearing has been scheduled in this matter.

As noted above in Note 8, FirstEnergy, CEI and OE filed a motion to dismiss a class action lawsuit related to the PUCO approved reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The court has not yet ruled on that motion to dismiss.

(C) PENNSYLVANIA

Met-Ed and Penelec purchase a portion of their ~~PLR~~POLR 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~~POLR and default service obligations.

On May 22, 2008, the PPUC approved the Met-Ed and Penelec annual updates to the TSC rider for the period June 1, 2008, through May 31, 2009. 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 interveners 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 Companies are now awaiting a PPUC decision.

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

On October 15, 2008, the Governor of Pennsylvania signed House Bill 2200 into law which became effective on November 14, 2008 as Act 129 of 2008. Act 129 addresses issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Major provisions of the legislation include:

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

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

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

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

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

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

Act 129 requires utilities to file with the PPUC, an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On 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 an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved, in part, and rejected, in part, the Pennsylvania Companies' filing. The Companies must file revised EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC. These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies.

Act 129 also requires utilities to file with the PPUC a smart meter technology procurement and installation plan by August 14, 2009. On June 18, 2009, the PPUC issued its guidelines related to Smart Meter deployment. On August 14, 2009, Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan as required by Act 129. A litigation schedule has been adopted which includes a Technical Conference and evidentiary hearings this fall. The Pennsylvania Companies expect the PPUC to act on the plans early next year.

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

~~On February 20, 2009,~~ Met-Ed and Penelec filed with the PPUC a generation procurement plan covering the period January 1, 2011 through May 31, 2013. The ~~companies’~~ plan is designed to provide adequate and reliable service via a prudent mix of long-term, short-term and spot market generation supply, as required by Act ~~129. The plan proposes~~129, with a staggered procurement schedule, which varies by customer class, through the use of a descending clock auction. ~~Met-Ed and Penelec anticipate PPUC approval of their plan in November 2009.~~

On February 26, 2009, the PPUC approved a Voluntary Prepayment Plan requested by Met-Ed and Penelec that provides an opportunity for residential and small commercial customers to prepay an amount on their monthly electric bills during 2009 and 2010. Customer prepayments earn interest at 7.5% and will be used to reduce electricity charges in 2011 and 2012.

~~On March 31,~~August 12, 2009, Met-Ed and Penelec ~~submitted their 5-year NUG Statement Compliance filing to~~filed a settlement agreement with 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~~generation procurement plan, reflecting the ~~generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for~~settlement on 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.but two reserved issues. On ~~July 30,~~November 6, 2009, the PPUC entered an ~~order~~Order approving the ~~5-year NUG Statement, approving~~settlement and finding in favor of Met-Ed and Penelec on the ~~reduction~~two reserved issues. Generation procurement began in January 2010.

On February 8, 2010, Penn filed a Petition for Approval of its Default Service Plan for the ~~CTC,~~period June 1, 2011 through May 31, 2013. The parties to the proceeding have reached a settlement on all issues and ~~directing~~filed a joint petition to approve the settlement agreement in July 2010. The PPUC is required to issue an order on the plan no later than November 8, 2010. If approved, procurement under the plan is expected to begin January 2011.

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, and 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 ~~tariff supplement implementing this change.~~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 ~~July 31, 2009,~~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 ~~decreasing~~to end collection of marginal transmission loss costs. By Order entered March 25, 2010, the ~~CTC~~PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed the plan to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges and the plan for the use of these funds to mitigate future generation rate ~~in compliance~~increases commencing January 1, 2011. The PPUC approved this plan June 7, 2010. On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the ~~July 30, 2009 order,~~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 ~~increasing~~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 ~~in compliance~~increases commencing January 1, 2011, and the PPUC entered an Order on June 7, 2010, granting Met-Ed’s and Penelec’s request. On July 9 2010, Met-Ed and Penelec filed their briefs with the ~~companies’ Restructuring Orders~~Commonwealth Court of ~~1998.~~ Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. The PPUC’s brief is due to be filed in August 2010.

On ~~August 14, 2009,~~May 20, 2010, the PPUC ~~issued Secretarial Letters approving Met-Ed~~approved Met-Ed’s and Penelec’s ~~compliance filings.~~ annual updates to their TSC rider for the period June 1, 2010 through December 31, 2010 including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The TSC for Met-Ed’s customers increased to be fully recovered by December 31, 2010.

Act 129 was enacted in 2008 to address 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. The PPUC entered an Order on February 26, 2010 approving the Pennsylvania Companies’ EE&C Plans and the tariff rider with rates effective March 1, 2010.

Met-Ed, Penelec and Penn jointly filed a Smart Meter Technology Procurement and Installation Plan with the PPUC. 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. 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, and decided various issues regarding the Smart Meter Implementation Plan for the Pennsylvania Companies. The PPUC entered its Order on June 9, 2010, consistent with the Chairman’s Motion. On June 24, 2010, Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to roll smart meter costs into base rates.

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.

By Tentative Order entered September 17, 2009, the PPUC provided for an additional ~~30 day~~30-day comment period on whether ~~“the~~the 1998 Restructuring Settlement allows Met-Ed and Penelec to apply over-collection of NUG ~~over collection~~costs 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, ~~comments were~~various parties filed ~~by 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~~comments objecting to the above accounting method utilized by Met-Ed and Penelec. ~~The Companies filed reply comments on October 26, 2009,~~Met-Ed and ~~await~~Penelec are awaiting further action by the ~~decision of the PPUC~~.PPUC.

(D) NEW JERSEY

To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. If approved as filed, the change would not go into effect until January 1, 2011.

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.~~2009 estimated at $736 million (in 2003 dollars). 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. ~~Such utility specific plans are due~~On April 16, 2010, the NJBPU issued an order indefinitely suspending the requirement of New Jersey utilities to ~~be filed with~~submit Utility Master Plans until such time as the ~~BPU by July 1, 2010.~~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 ~~the~~former New Jersey ~~Governor's~~Governor Corzine’s Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. 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 ~~BPU~~NJBPU on August 19, 2009, and implementation ~~will begin~~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. On July 6, 2010, the January 30, 2009 petition directed to infrastructure investment which had been pending before the NJBPU was withdrawn by JCP&L. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

(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. Briefs addressing the initial decision were filed on September 11, 2006 and October 20, 2006. A final order is pending before the FERC, and in the meantime, FirstEnergy affiliates have been negotiating and entering into settlement agreements with other parties in the docket to mitigate the risk of lower transmission revenue collection associated with an adverse order. On September 26, 2008, the MISO and PJM transmission owners filed a motion requesting that the FERC approve the pending settlements and act on the initial decision. On November 20, 2008, FERC issued an order approving uncontested settlements, but did not rule on the initial decision. On December 19, 2008, an additional order was issued approving two contested settlements. On October 29, 2009, FirstEnergy and Exelon filed an additional settlement agreement with FERC to resolve their outstanding claims. FirstEnergy is actively pursuing settlement agreements with other parties to the case.

PJM Transmission Rate

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

~~On May 18, 2007, certain parties filed for rehearing~~ FERC ultimately issued an order approving use of the beneficiary pays method of cost allocation for transmission facilities included in the PJM regional plan that operate below 500 kV.

The FERC’s April 19, 2007 ~~order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP~~order was appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral arguments were held on April 13, 2009. The Seventh Circuit Court of Appeals issued a decision on August 6, 2009, that remanded the rate design to FERC and denied AEP’s appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion Electric Cooperative was denied by the Seventh Circuit on October 20, 2009. On October 28, 2009, the Seventh Circuit closed its case dockets and returned the case to FERC for further action on the remand order.

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 PJM-wide basis reduces the cost of future transmission to be recovered from the JCP&L, Met-Ed and Penelec zones. A partial settlement agreement addressing the “beneficiary pays” methodology for below 500 kV facilities, but excluding the issue of allocating new facilities costs to merchant transmission entities, was filed on September 14, 2007. The agreement was supported by the FERC’s Trial Staff, and was certified by the Presiding Judge to the FERC. On July 29, 2008, the FERC issued an order conditionally approving the settlement subject to the submission of a compliance filing. The compliance filing was submitted on August 29, 2008, and the FERC issued an order accepting the compliance filing on October 15, 2008. On November 14, 2008, PJM submitted revisions to its tariff to incorporate cost responsibility assignments for below 500 kV upgrades included in PJM’s Regional Transmission Expansion Planning process in accordance with the settlement. The FERC conditionally accepted the compliance filing on January 28, 2009. PJM submitted a further compliance filing on March 2, 2009, which was accepted by the FERC on April 10, 2009. The remaining merchant transmission cost allocation issues were the subject of a hearing at the FERC in May 2008. An initial decision was issued by the Presiding Judge on September 18, 2008. PJM and FERC trial staff each filed a Brief on Exceptions to the initial decision on October 20, 2008. Briefs Opposing Exceptions were filed on November 10, 2008.

~~Post Transition Period Rate Design~~

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

On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh ~~Circuit. FESC,~~Circuit, which issued a decision on ~~behalf of its affiliated operating utility companies, filed a motion to intervene on March 10,~~August 6, 2009. The ~~Seventh Circuit Court~~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 load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.

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 ~~Appeals has held this appeal~~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 ~~abeyance pending resolution~~response to the FERC order. PJM’s filing demonstrated that allocation of the ~~Opinion 494 appeal discussed above. Now that~~cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the ~~Seventh Circuit has ruled~~majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the ~~Opinion 494 case, AEP~~use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC ~~have until November 11, 2009,~~is not expected to ~~advise~~act before the ~~Seventh Circuit~~fourth quarter of ~~any changes to their litigation positions that result from or reflect the Seventh Circuit’s decision in the Opinion 494 case.~~2010.

RTO Consolidation

~~On August 17, 2009,~~FERC issued an order approving, subject to certain future compliance filings, ATSI’s move to PJM. This allows 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~~will 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. FERC approved FirstEnergy’s proposal to use a Fixed Resource Requirement Plan (FRR Plan) to obtain capacity to satisfy the PJM capacity requirements for the 2011-12 and 2012-13 delivery years.

~~To ensure a definitive ruling at~~In December 2009, ATSI executed the ~~same time FERC rules on its request~~PJM Consolidated Transmission Owners Agreement and 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 ~~integrate ATSI~~moving into PJM on ~~October~~the schedule described in the application and approved in the FERC Order.

FirstEnergy successfully conducted the FRR auctions on March 19, ~~2009, FirstEnergy filed a related complaint with FERC on~~and participated in the ~~issue of allocating transmission costs to~~PJM base residual auction for the 2013 delivery year, thereby obtaining the capacity necessary for its ATSI footprint ~~for high voltage transmission projects approved prior~~ to ~~FirstEnergy’s integration into PJM.~~

meet PJM’s capacity requirements. FirstEnergy ~~has requested that FERC rule on its application and the related complaint by December 17, 2009, to provide time to permit management to make a decision on whether~~expects to integrate ~~ATSI~~ into PJM ~~prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on~~effective June 1, ~~2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.~~

2011.

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. ~~The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.~~

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

On ~~May 30, 2008,~~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 Docket EL 10-46-000, the complaint alleges that PJM erroneously calculated charges to MISO for market-to-market settlements made from 2005 to 2009 pursuant to the congestion management provisions of the JOA. The MISO seeks approximately $130 million plus interest to correct for resultant net underpayments from PJM to MISO. In Docket No.EL10-45-000, MISO alleges that by failing to account for the market flows from 34 PJM generators over the period from 2007-2009, PJM underpaid MISO by a ~~group~~total of roughly $75 million including interest. For the period from 2005-2007, MISO claimed an underpayment by PJM ~~load-serving entities, state commissions, consumer advocates,~~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 ~~trade associations (referred~~is improperly demanding repayment of redispatch payments previously made to ~~collectively as~~MISO. PJM filed its answers to the ~~RPM Buyers)~~complaints on April 12, 2010, opposing the relief sought by MISO.

In addition, on April 12, 2010, PJM filed a complaint ~~at the~~with FERC ~~against PJM~~pursuant to Section 206, 306, and 309 alleging that ~~three of~~MISO is violating the ~~four transitional RPM auctions yielded prices that are unjust~~JOA with PJM by initiating market-to-market coordination and ~~unreasonable under the Federal Power Act. On September 19, 2008, the FERC denied the RPM Buyers’ complaint. The FERC also ordered~~financial settlements for substitute (proxy) reciprocal coordinated flowgates between MISO and PJM. PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requestedclaims 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~~JOA does not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order terminating settlement discussions. On February 9, 2009, PJM and a group of stakeholders submitted an offer of settlement, which used the PJM December 12, 2008 filing as its starting point, and stated that unless otherwise specified, provisions filed by PJM on December 12, 2008, apply.

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

PJM has reconvened the Capacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes were approved by the FERC in an order issued on October 30, 2009, and are effective November 1, 2009. The CMEC continues to work to address additional compliance items directed by the March 26, 2009 Order. Another compliance filing is due December 1, 2009.

~~MISO Resource Adequacy Proposal~~

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn and FES. This requirement was proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to ~~establish~~initiate market-to-market settlements using proxy flowgates in lieu of designated reciprocal coordinated flowgates. This complaint addresses substantially the ~~reserve margin requirement for load-serving entities based upon~~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 ~~one day loss of load~~complaint in ~~ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities~~order to ensure their right to claim refunds, if any, if successful in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. their arguments at FERC.

On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009,29, 2010, FERC issued an order ~~approving~~consolidating the cases and establishing settlement judge procedures. If the settlement process is unsuccessful, the cases will proceed to evidentiary hearings. FirstEnergy is unable to predict the outcome of this matter.

MISO Multi-Value Project Rule Proposal

On July 15, 2010, MISO and certain MISO transmission owners jointly filed with the FERC their proposed cost allocation methodology for new transmission projects. If approved, so-called Multi Value Projects (MVPs) — transmission projects that have a ~~MISO compliance filing that revised its tariff~~regional impact and are part of a regional plan — will have a 100% regional allocation of costs under the proposed methodology. If approved by FERC, MISO’s proposal is expected to ~~provide for netting of demand resources, but prohibiting~~permit the ~~netting of behind-the-meter generation.~~

~~FES Sales to Affiliates~~

~~FES supplied all~~allocation of the ~~power requirements for~~costs of large transmission projects designed to integrate wind from the ~~Ohio Companies pursuant~~upper Midwest across the entire MISO. MISO has requested a FERC response to ~~a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of~~ the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

~~On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted~~filing by the ~~PUCO on May 14, 2009. Twelve bidders qualified~~FERC’s December open meeting, but an effective date for its proposal of July 16, 2011. Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to ~~participate in~~ the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 21 additional tranches from other bidders. The auction resulted in an overall weighted average wholesale price of 6.15 cents per KWH for generation and transmission. The new prices for PLR service went into effect with usage beginning June 1, ~~2009, and continuing through May 31, 2011.~~

On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount2011 effective date of ~~capacity resources required~~FirstEnergy’s integration into PJM would continue to be ~~supplied by FES~~allocated to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010. Under the new agreement, Met-Ed, Penelec, and Waverly (Buyers) assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. ~~FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load.~~ FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.FirstEnergy.

~~11.~~10. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In December 2008, the FASB issued a standard on an employer’s disclosures about assets of a defined benefit pension or other postretirement plan. Requirements include disclosures about investment policies and strategies, categories of plan assets, fair value measurements of plan assets, and significant categories of risk. This standard is effective for fiscal years ending after December 15, 2009. FirstEnergy will expand its disclosures related to postretirement benefit plan assets.

~~In June 2009,~~2010, the FASB amended the ~~derecognition guidance in the Transfers~~Derivatives and ~~Servicing~~Hedging Topic of the FASB Accounting Standards Codification ~~and eliminated~~to clarify the ~~concept~~scope exception for embedded credit derivative features related to the transfer of ~~a QSPE.~~credit risk in the form of subordination of one financial instrument to another. The ~~amended guidance requires an evaluation of all existing QSPEs~~amendment addresses how to determine ~~whether they must~~which embedded credit derivative features, including those in collateralized debt obligations and synthetic collateralized debt obligations, are considered to be ~~consolidated. This standard~~embedded derivatives that should not be analyzed under the Derivatives and Hedging Topic for potential bifurcation and separate accounting. The amendment is effective for ~~financial asset transfers that occur in~~the first fiscal ~~years~~quarter beginning after ~~November~~June 15, ~~2009.~~2010. FirstEnergy does not expect this standard to have a material effect ~~upon its financial statements.~~

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

11. SEGMENT INFORMATION

~~In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance~~Financial information for each of FirstEnergy’s reportable segments is presented in ~~determining fair value when a quoted price in an active market for an identical liability is not available. In such instances, an entity should measure fair value using one of~~ the following approaches; (i) the quoted price of an identical liability when traded as an asset; (ii) the quoted price of a similar liability or a similar liability traded as an asset; (iii) a technique based on the amount an entity would pay to transfer the identical liability; or (iv) a technique based on the amount an entity would receive to enter into an identical liability. This standard is effective for the first reporting period, including interim periods, beginning after issuance, or October 1, 2009, for FirstEnergy. FirstEnergy does not expect this standard to have a material effect upon its financial statements.

~~12. SEGMENT INFORMATION~~

FirstEnergy has three reportable operating segments: energy delivery services, competitive energy services and Ohio transitional generation services. The assets and revenues for all other business operations are below the quantifiable threshold for operating segments for separate disclosure as "reportable operating segments."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~~Energy Delivery Services segment ~~designs, constructs, operates~~transmits and ~~maintains FirstEnergy's regulated transmission and distribution systems and is responsible for the regulated generation commodity operations~~distributes electricity through FirstEnergy’s eight utility operating companies, serving 4.5 million customers within 36,100 square miles of ~~FirstEnergy's~~Ohio, Pennsylvania and New Jersey ~~electric utility subsidiaries.~~and purchases power for its POLR 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 ~~default service~~the sale of electric generation ~~sales~~service to ~~non-shopping~~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 ~~under Met-Ed's and Penelec's partial requirements purchased power agreements~~ and from non-affiliated power suppliers, ~~as well as~~ the net PJM and MISO transmission expenses related to the delivery of ~~that~~the respective generation ~~load.~~

loads, and the deferral and amortization of certain fuel costs.

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

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


	Energy		Competitive
	Delivery		Energy						Reconciling
Segment Financial Information	Services		Services			Other			Adjustments			Consolidated
	(In millions)

Three Months Ended

June 30, 2010
External revenues	$	2,373	$	778		$	6		$	(29	)	$	3,128
Internal revenues		19		539			—			(558	)		—

Total revenues		2,392		1,317			6			(587	)		3,128
Depreciation and amortization		276		66			6			3			351
Investment income (loss), net		27		13			—			(9	)		31
Net interest charges		123		31			3			10			167
Income taxes		89		76			(22	)		(9	)		134
Net income (loss)		143		125			16			(28	)		256
Total assets		22,450		11,100			591			325			34,466
Total goodwill		5,551		24			—			—			5,575
Property additions		172		282			7			28			489

June 30, 2009
External revenues	$	2,792	$	504		$	5		$	(30	)	$	3,271
Internal revenues		—		839			—			(839	)		—

Total revenues		2,792		1,343			5			(869	)		3,271
Depreciation and amortization		298		68			3			4			373
Investment income (loss), net		35		6			—			(14	)		27
Net interest charges		113		18			2			40			173
Income taxes		103		185			(20	)		(20	)		248
Net income		154		276			18			(40	)		408
Total assets		23,215		10,144			684			263			34,306
Total goodwill		5,551		24			—			—			5,575
Property additions		178		248			70			(7	)		489

Six Months Ended

June 30, 2010
External revenues	$	4,916	$	1,494		$	10		$	(60	)	$	6,360
Internal revenues*		19		1,213			—			(1,165	)		67

Total revenues		4,935		2,707			10			(1,225	)		6,427
Depreciation and amortization		601		132			19			4			756
Investment income (loss), net		52		14			—			(19	)		47
Net interest charges		246		64			2			27			339
Income taxes		158		123			(18	)		(18	)		245
Net income (loss)		257		201			1			(54	)		405
Total assets		22,450		11,100			591			325			34,466
Total goodwill		5,551		24			—			—			5,575
Property additions		338		605			10			44			997

June 30, 2009
External revenues	$	5,813	$	839	��	$	12		$	(59	)	$	6,605
Internal revenues		—		1,732			—			(1,732	)		—

Total revenues		5,813		2,571			12			(1,791	)		6,605
Depreciation and amortization		725		132			4			7			868
Investment income (loss), net		65		(23	)		—			(26	)		16
Net interest charges		222		36			3			78			339
Income taxes		91		288			(37	)		(40	)		302
Net income		136		431			35			(79	)		523
Total assets		23,215		10,144			684			263			34,306
Total goodwill		5,551		24			—			—			5,575
Property additions		343		669			119			12			1,143

Segment Financial Information
Ohio
Energy Competitive Transitional
Delivery Energy Generation Reconciling
Three Months Ended Services Services Services Other Adjustments Consolidated
(In millions)
September 30, 2009
External revenues $ 2,203 $ 490 $ 739 $ 6 $ (30 ) $ 3,408
Internal revenues - 617 - - (617 ) -
Total revenues 2,203 1,107 739 6 (647 ) 3,408
Depreciation and amortization 356 69 17 3 4 449
Investment income 46 159 - - (14 ) 191
Net interest charges 117 28 - 2 173 320
Income taxes 93 121 6 (19 ) (73 ) 128
Net income (loss) 139 183 9 17 (118 ) 230
Total assets 22,753 10,691 270 674 286 34,674
Total goodwill 5,551 24 - - - 5,575
Property additions 182 224 - 14 12 432

September 30, 2008
External revenues $ 2,657 $ 460 $ 813 $ 5 $ (31 ) $ 3,904
Internal revenues - 786 - - (786 ) -
Total revenues 2,657 1,246 813 5 (817 ) 3,904
Depreciation and amortization 286 67 46 1 1 401
Investment income 48 13 1 - (22 ) 40
Net interest charges 101 31 1 - 44 177
Income taxes 188 109 14 (46 ) (27 ) 238
Net income 283 164 19 48 (43 ) 471
Total assets 23,088 9,360 270 457 387 33,562
Total goodwill 5,559 24 - - - 5,583
Property additions 170 285 - 85 20 560

Nine Months Ended

September 30, 2009
External revenues $ 6,236 $ 1,329 $ 2,519 $ 18 $ (89 ) $ 10,013
Internal revenues - 2,349 - - (2,349 ) -
Total revenues 6,236 3,678 2,519 18 (2,438 ) 10,013
Depreciation and amortization 1,122 201 (24 ) 7 11 1,317
Investment income 110 136 1 - (40 ) 207
Net interest charges 340 64 - 5 250 659
Income taxes 154 409 36 (56 ) (113 ) 430
Net income (loss) 230 614 55 52 (197 ) 754
Total assets 22,753 10,691 270 674 286 34,674
Total goodwill 5,551 24 - - - 5,575
Property additions 524 893 - 133 25 1,575

September 30, 2008
External revenues $ 7,051 $ 1,164 $ 2,203 $ 65 $ (57 ) $ 10,426
Internal revenues - 2,266 - - (2,266 ) -
Total revenues 7,051 3,430 2,203 65 (2,323 ) 10,426
Depreciation and amortization 782 179 61 2 10 1,034
Investment income 133 (1 ) 1 6 (66 ) 73
Net interest charges 303 86 1 - 133 523
Income taxes 436 212 42 (33 ) (72 ) 585
Net income 655 317 62 96 (119 ) 1,011
Total assets 23,088 9,360 270 457 387 33,562
Total goodwill 5,559 24 - - - 5,583
Property additions 621 1,430 - 106 20 2,177


*		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.

~~13.~~12. SUPPLEMENTAL GUARANTOR INFORMATION

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

The condensed consolidating statements of income for the ~~three-month~~three month and ~~nine-month~~six month periods ended ~~September~~June 30, ~~2009~~2010 and ~~2008,~~2009, consolidating balance sheets as of ~~September~~June 30, ~~2009~~2010 and December 31, ~~2008~~2009 and consolidating statements of cash flows for the ~~nine~~six months ended ~~September~~June 30, ~~2009~~2010 and ~~2008~~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'~~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.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)


For the Three Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	*(In thousands)*

REVENUES	$	1,295,700		$	580,621		$	338,933		$	(900,580	)	$	1,314,674


EXPENSES:
Fuel		7,268			300,867			34,276			—			342,411
Purchased power from affiliates		912,858			7,163			49,457			(900,580	)		68,898
Purchased power from non-affiliates		298,820			—			—			—			298,820
Other operating expenses		80,983			94,373			116,350			12,189			303,895
Provision for depreciation		711			27,466			36,449			(1,307	)		63,319
General taxes		5,718			9,227			7,327			—			22,272

Total expenses		1,306,358			439,096			243,859			(889,698	)		1,099,615


OPERATING INCOME (LOSS)		(10,658	)		141,525			95,074			(10,882	)		215,059


OTHER INCOME (EXPENSE):
Investment income		1,811			81			11,474			—			13,366
Miscellaneous income (expense), including net income from equity investees		151,291			709			102			(147,709	)		4,393
Interest expense to affiliates		(61	)		(2,084	)		(415	)		—			(2,560	)
Interest expense — other		(24,262	)		(27,799	)		(15,361	)		16,050			(51,372	)
Capitalized interest		98			19,573			4,234			—			23,905

Total other income (expense)		128,877			(9,520	)		34			(131,659	)		(12,268	)


INCOME BEFORE INCOME TAXES		118,219			132,005			95,108			(142,541	)		202,791

INCOME TAXES (BENEFITS)		(15,706	)		48,465			33,550			2,557			68,866


NET INCOME	$	133,925		$	83,540		$	61,558		$	(145,098	)	$	133,925

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)


For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	*(In thousands)*

REVENUES	$	2,662,725		$	1,148,985		$	765,253		$	(1,874,196	)	$	2,702,767


EXPENSES:
Fuel		12,365			581,730			76,537			—			670,632
Purchased power from affiliates		1,881,395			12,242			110,410			(1,874,196	)		129,851
Purchased power from non-affiliates		749,035			—			—			—			749,035
Other operating expenses		134,109			194,149			255,770			24,378			608,406
Provision for depreciation		1,501			53,993			73,359			(2,616	)		126,237
General taxes		11,216			23,827			13,975			—			49,018

Total expenses		2,789,621			865,941			530,051			(1,852,434	)		2,333,179


OPERATING INCOME (LOSS)		(126,896	)		283,044			235,202			(21,762	)		369,588


OTHER INCOME (EXPENSE):
Investment income		3,708			135			10,240			—			14,083
Miscellaneous income (expense), including net income from equity investees		317,664			(924	)		1			(311,038	)		5,703
Interest expense to affiliates		(119	)		(3,896	)		(850	)		—			(4,865	)
Interest expense — other		(47,635	)		(54,305	)		(31,124	)		32,048			(101,016	)
Capitalized interest		198			35,906			7,491			—			43,595

Total other income (expense)		273,816			(23,084	)		(14,242	)		(278,990	)		(42,500	)


INCOME BEFORE INCOME TAXES		146,920			259,960			220,960			(300,752	)		327,088

INCOME TAXES (BENEFITS)		(66,931	)		96,508			78,563			5,097			113,237


NET INCOME	$	213,851		$	163,452		$	142,397		$	(305,849	)	$	213,851

FIRSTENERGY SOLUTIONS CORP.

57CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)


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

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


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

Total expenses		1,045,819			384,518			250,696			(808,765	)		872,268


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


OTHER INCOME (EXPENSE):
Investment income		(518	)		131			6,030			—			5,643
Miscellaneous income (expense), including net income from equity investees		289,312			820			—			(282,510	)		7,622
Interest expense to affiliates		(34	)		(1,623	)		(1,658	)		—			(3,315	)
Interest expense — other		(2,900	)		(24,967	)		(14,677	)		16,273			(26,271	)
Capitalized interest		46			11,126			2,856			—			14,028

Total other income (expense)		285,906			(14,513	)		(7,449	)		(266,237	)		(2,293	)


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

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


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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

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


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

Total expenses		2,167,509			808,536			533,268			(1,715,233	)		1,794,080


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


OTHER INCOME (EXPENSE):
Investment income		214			162			(23,607	)		—			(23,231	)
Miscellaneous income (expense), including net income from equity investees		409,093			742			—			(399,702	)		10,133
Interest expense to affiliates		(68	)		(3,381	)		(2,845	)		—			(6,294	)
Interest expense — other		(5,420	)		(46,025	)		(29,845	)		32,492			(48,798	)
Capitalized interest		97			18,876			5,133			—			24,106

Total other income (expense)		403,916			(29,626	)		(51,164	)		(367,210	)		(44,084	)


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

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


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

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES $ 1,087,991 $ 477,679 $ 170,129 $ (631,227 ) $ 1,104,572

EXPENSES:
Fuel 9,278 241,953 43,462 - 294,693
Purchased power from non-affiliates 205,200 - - - 205,200
Purchased power from affiliates 621,996 9,233 35,290 (631,229 ) 35,290
Other operating expenses 70,246 109,828 113,669 12,192 305,935
Provision for depreciation 1,051 30,469 35,832 (1,311 ) 66,041
General taxes 4,351 11,331 6,018 - 21,700
Total expenses 912,122 402,814 234,271 (620,348 ) 928,859

OPERATING INCOME 175,869 74,865 (64,142 ) (10,879 ) 175,713

OTHER INCOME (EXPENSE):
Investment income 35 319 158,503 - 158,857
Miscellaneous income, including net income
from equity investees 100,668 744 1 (98,609 ) 2,804
Interest expense - affiliates (35 ) (1,267 ) (907 ) - (2,209 )
Interest expense - other (15,358 ) (26,737 ) (16,205 ) 16,113 (42,187 )
Capitalized interest 49 15,381 2,439 - 17,869
Total other income (expense) 85,359 (11,560 ) 143,831 (82,496 ) 135,134

INCOME BEFORE INCOME TAXES 261,228 63,305 79,689 (93,375 ) 310,847

INCOME TAXES 61,545 19,646 27,801 2,172 111,164

NET INCOME $ 199,683 $ 43,659 $ 51,888 $ (95,547 ) $ 199,683


As of June 30, 2010	FES		FGCO		NGC		Eliminations			Consolidated
	*(In thousands)*

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	9	$	—		$	11
Receivables—
Customers		315,178		—		—		—			315,178
Associated companies		327,070		257,268		89,725		(319,936	)		354,127
Other		24,815		6,946		4,631		—			36,392
Notes receivable from associated companies		84,337		—		89,594		—			173,931
Materials and supplies, at average cost		23,804		333,709		221,008		—			578,521
Prepayments and other		162,845		5,600		4,069		—			172,514

		938,049		603,525		409,036		(319,936	)		1,630,674


PROPERTY, PLANT AND EQUIPMENT:
In service		93,403		5,588,112		5,203,976		(385,086	)		10,500,405
Less — Accumulated provision for depreciation		15,742		2,824,150		2,028,479		(173,191	)		4,695,180

		77,661		2,763,962		3,175,497		(211,895	)		5,805,225
Construction work in progress		7,412		2,149,132		466,321		—			2,622,865

		85,073		4,913,094		3,641,818		(211,895	)		8,428,090


INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,107,594		—			1,107,594
Investment in associated companies		4,790,066		—		—		(4,790,066	)		—
Other		759		7,003		203		—			7,965

		4,790,825		7,003		1,107,797		(4,790,066	)		1,115,559


DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		78,986		340,072		—		(419,058	)		—
Customer intangibles		118,219		—		—		—			118,219
Goodwill		24,248		—		—		—			24,248
Property taxes		—		27,811		22,314		—			50,125
Unamortized sale and leaseback costs		—		14,168		—		63,478			77,646
Other		102,829		76,609		9,655		(60,778	)		128,315

		324,282		458,660		31,969		(416,358	)		398,553

	$	6,138,229	$	5,982,282	$	5,190,620	$	(5,738,255	)	$	11,572,876


LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
Currently payable long-term debt	$	755	$	472,357	$	927,772	$	(19,101	)	$	1,381,783
Short-term borrowings—
Associated companies		—		85,128		—		—			85,128
Other		100,000		—		—		—			100,000
Accounts payable—
Associated companies		311,959		257,889		154,508		(311,849	)		412,507
Other		101,776		134,944		—		—			236,720
Accrued taxes		1,717		74,125		54,576		(21,336	)		109,082
Other		216,207		102,780		15,377		34,722			369,086

		732,414		1,127,223		1,152,233		(317,564	)		2,694,306


CAPITALIZATION:
Common stockholder’s equity		3,731,382		2,504,419		2,268,860		(4,773,279	)		3,731,382
Long-term debt and other long-term obligations		1,518,968		1,820,112		506,533		(1,259,694	)		2,585,919

		5,250,350		4,324,531		2,775,393		(6,032,973	)		6,317,301


NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		976,012			976,012
Accumulated deferred income taxes		—		—		373,725		(363,730	)		9,995
Accumulated deferred investment tax credits		—		34,820		21,490		—			56,310
Asset retirement obligations		—		26,196		837,213		—			863,409
Retirement benefits		35,830		188,023		—		—			223,853
Property taxes		—		27,811		22,314		—			50,125
Lease market valuation liability		—		239,447		—		—			239,447
Other		119,635		14,231		8,252		—			142,118

		155,465		530,528		1,262,994		612,282			2,561,269

	$	6,138,229	$	5,982,282	$	5,190,620	$	(5,738,255	)	$	11,572,876

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
Customer intangibles		16,566		—		—			—			16,566
Goodwill		24,248		—		—			—			24,248
Property taxes		—		27,811		22,314			—			50,125
Unamortized sale and leaseback costs		—		16,454		—			56,099			72,553
Other		82,845		71,179		18,755			(51,114	)		121,665

		217,038		497,293		41,069			(383,617	)		371,783

	$	5,821,127	$	6,020,488	$	5,282,211		$	(5,373,038	)	$	11,750,788


LIABILITIES AND CAPITALIZATION

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

		631,474		1,213,095		1,256,985			(287,734	)		2,813,820


CAPITALIZATION:
Common stockholder’s equity		3,514,571		2,346,515		2,119,488			(4,466,003	)		3,514,571
Long-term debt and other long-term obligations		1,519,339		1,906,818		554,825			(1,269,330	)		2,711,652

		5,033,910		4,253,333		2,674,313			(5,735,333	)		6,226,223


NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—			992,869			992,869
Accumulated deferred income taxes		—		—		342,840			(342,840	)		—
Accumulated deferred investment tax credits		—		36,359		22,037			—			58,396
Asset retirement obligations		—		25,714		895,734			—			921,448
Retirement benefits		33,144		170,891		—			—			204,035
Property taxes		—		27,811		22,314			—			50,125
Lease market valuation liability		—		262,200		—			—			262,200
Other		122,599		31,085		67,988			—			221,672

		155,743		554,060		1,350,913			650,029			2,710,745

	$	5,821,127	$	6,020,488	$	5,282,211		$	(5,373,038	)	$	11,750,788

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)


For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	*(In thousands)*

NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(223,072	)	$	163,325		$	287,376		$	(9,174	)	$	218,455


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing—
Short-term borrowings, net		—			75,891			—			—			75,891
Redemptions and Repayments—
Long-term debt		(397	)		(260,865	)		(42,949	)		9,174			(295,037	)
Short-term borrowings, net		—			—			—			—			—
Other		(457	)		(128	)		(101	)		—			(686	)

Net cash used for financing activities		(854	)		(185,102	)		(43,050	)		9,174			(219,832	)


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(3,716	)		(333,063	)		(229,408	)		—			(566,187	)
Proceeds from asset sales		—			115,657			—			—			115,657
Sales of investment securities held in trusts		—			—			956,813			—			956,813
Purchases of investment securities held in trusts		—			—			(978,785	)		—			(978,785	)
Loans from associated companies, net		332,067			240,836			58,270			—			631,173
Customer acquisition costs		(104,795	)		—			—			—			(104,795	)
Leasehold improvement payments to associated companies		—			—			(51,204	)		—			(51,204	)
Other		370			(1,654	)		(12	)		—			(1,296	)

Net cash provided from (used for) investing activities		223,926			21,776			(244,326	)		—			1,376


Net change in cash and cash equivalents		—			(1	)		—			—			(1	)
Cash and cash equivalents at beginning of period		—			3			9			—			12

Cash and cash equivalents at end of period	$	—		$	2		$	9		$	—		$	11

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)


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

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


CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing—
Long-term debt		—			347,710			333,965			—			681,675
Short-term borrowings, net		98,880			—			128,716			(82,587	)		145,009
Redemptions and Repayments—														—
Long-term debt		(1,696	)		(260,372	)		(369,519	)		8,734			(622,853	)
Short-term borrowings, net		—			(82,587	)		—			82,587			—

Net cash provided from financing activities		97,184			4,751			93,162			8,734			203,831


CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(694	)		(332,789	)		(301,484	)		—			(634,967	)
Proceeds from asset sales		—			15,771			—			—			15,771
Sales of investment securities held in trusts		—			—			537,078			—			537,078
Purchases of investment securities held in trusts		—			—			(550,730	)		—			(550,730	)
Loans to associated companies, net		(261,839	)		20,669			—			—			(241,170	)
Other		65			(22,448	)		349			—			(22,034	)

Net cash used for investing activities		(262,468	)		(318,797	)		(314,787	)		—			(896,052	)


Net change in cash and cash equivalents		120,000			(5	)		—			—			119,995
Cash and cash equivalents at beginning of period		—			39			—			—			39

Cash and cash equivalents at end of period	$	120,000		$	34		$	—		$	—		$	120,034

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 the recorded value is being amortized ratably over the term of the related contracts. Net intangible assets of $118 million are included in other assets on FirstEnergy’s Consolidated Balance Sheet as of June 30, 2010.

For the three and six months ended June 30, 2010, amortization expense was approximately $3 million and $5 million, respectively.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended September 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 1,222,783 $ 574,394 $ 267,017 $ (822,590 ) $ 1,241,604

EXPENSES:
Fuel 8,177 307,646 34,123 - 349,946
Purchased power from non-affiliates 221,493 - - - 221,493
Purchased power from affiliates 815,243 7,347 15,821 (822,590 ) 15,821
Other operating expenses 35,596 110,701 120,697 12,190 279,184
Provision for depreciation 1,978 33,432 30,559 (1,336 ) 64,633
General taxes 4,829 10,768 6,139 - 21,736
Total expenses 1,087,316 469,894 207,339 (811,736 ) 952,813

OPERATING INCOME 135,467 104,500 59,678 (10,854 ) 288,791

OTHER INCOME (EXPENSE):
Investment income (loss) (122 ) (1,204 ) 13,287 - 11,961
Miscellaneous income, including net income
from equity investees 102,899 689 - (97,122 ) 6,466
Interest expense - affiliates (120 ) (4,963 ) (2,932 ) - (8,015 )
Interest expense - other (8,464 ) (23,447 ) (17,183 ) 16,325 (32,769 )
Capitalized interest 41 11,376 978 - 12,395
Total other income (expense) 94,234 (17,549 ) (5,850 ) (80,797 ) (9,962 )

INCOME BEFORE INCOME TAXES 229,701 86,951 53,828 (91,651 ) 278,829

INCOME TAXES 44,046 31,863 14,995 2,270 93,174

NET INCOME $ 185,655 $ 55,088 $ 38,833 $ (93,921 ) $ 185,655
14. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of a sludge disposal pond and closure of two coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).

The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for their leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES and the Utilities use an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

During the second quarter of 2010, studies were completed to reassess the estimated cost of decommissioning the Beaver Valley nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES, OE and TE and reduced the liability for each subsidiary in the amounts of $88 million, $7 million, and $5 million, respectively, as of June 30, 2010.

The revision to the estimated cash flows had no significant impact on accretion expense during the second quarter of 2010 when compared to the second quarter of 2009.

15. PROPOSED MERGER WITH ALLEGHENY ENERGY, INC.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES $ 3,357,873 $ 1,726,715 $ 955,452 $ (2,368,210 ) $ 3,671,830

EXPENSES:
Fuel 16,400 755,632 99,128 - 871,160
Purchased power from non-affiliates 551,155 - - - 551,155
Purchased power from affiliates 2,351,879 16,333 149,746 (2,368,212 ) 149,746
Other operating expenses 144,284 313,416 397,284 36,571 891,555
Provision for depreciation 3,087 90,680 103,135 (3,940 ) 192,962
General taxes 12,826 35,289 18,246 - 66,361
Total expenses 3,079,631 1,211,350 767,539 (2,335,581 ) 2,722,939

OPERATING INCOME 278,242 515,365 187,913 (32,629 ) 948,891

OTHER INCOME (EXPENSE):
Investment income 83 758 134,882 - 135,723
Miscellaneous income, including net income
from equity investees 509,927 1,209 15 (498,311 ) 12,840
Interest expense - affiliates (103 ) (4,648 ) (3,752 ) - (8,503 )
Interest expense - other (20,778 ) (72,762 ) (46,050 ) 48,605 (90,985 )
Capitalized interest 146 34,257 7,572 - 41,975
Total other income (expense) 489,275 (41,186 ) 92,667 (449,706 ) 91,050

INCOME BEFORE INCOME TAXES 767,517 474,179 280,580 (482,335 ) 1,039,941

INCOME TAXES 99,751 166,902 98,893 6,629 372,175

NET INCOME $ 667,766 $ 307,277 $ 181,687 $ (488,964 ) $ 667,766

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Nine Months Ended September 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

REVENUES $ 3,387,258 $ 1,707,320 $ 879,729 $ (2,562,309 ) $ 3,411,998

EXPENSES:
Fuel 13,920 876,077 92,188 - 982,185
Purchased power from non-affiliates 648,556 - - - 648,556
Purchased power from affiliates 2,549,892 12,417 75,834 (2,562,309 ) 75,834
Other operating expenses 103,034 342,041 381,826 36,567 863,468
Provision for depreciation 3,885 90,058 80,646 (4,054 ) 170,535
General taxes 14,971 33,842 15,915 - 64,728
Total expenses 3,334,258 1,354,435 646,409 (2,529,796 ) 2,805,306

OPERATING INCOME 53,000 352,885 233,320 (32,513 ) 606,692

OTHER INCOME (EXPENSE):
Investment loss (333 ) (3,300 ) (2,699 ) - (6,332 )
Miscellaneous income, including net income
from equity investees 323,425 2,066 - (305,710 ) 19,781
Interest expense - affiliates (252 ) (18,172 ) (7,529 ) - (25,953 )
Interest expense - other (19,105 ) (73,112 ) (38,833 ) 49,241 (81,809 )
Capitalized interest 90 27,460 2,049 - 29,599
Total other income (expense) 303,825 (65,058 ) (47,012 ) (256,469 ) (64,714 )

INCOME BEFORE INCOME TAXES 356,825 287,827 186,308 (288,982 ) 541,978

INCOME TAXES 13,092 109,615 68,597 6,941 198,245

NET INCOME $ 343,733 $ 178,212 $ 117,711 $ (295,923 ) $ 343,733

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of September 30, 2009 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ 266,859 $ 99 $ - $ - $ 266,958
Receivables-
Customers 155,489 - - - 155,489
Associated companies 278,670 186,263 106,551 (227,097 ) 344,387
Other 15,310 12,858 19,411 - 47,579
Notes receivable from associated companies 134,283 200,692 93,041 - 428,016
Materials and supplies, at average cost 9,925 304,358 213,995 - 528,278
Prepayments and other 90,377 19,064 10,921 - 120,362
950,913 723,334 443,919 (227,097 ) 1,891,069

PROPERTY, PLANT AND EQUIPMENT:
In service 90,179 5,508,790 5,041,783 (386,054 ) 10,254,698
Less - Accumulated provision for depreciation 12,590 2,785,417 1,860,060 (170,235 ) 4,487,832
77,589 2,723,373 3,181,723 (215,819 ) 5,766,866
Construction work in progress 4,179 1,830,141 361,679 - 2,195,999
81,768 4,553,514 3,543,402 (215,819 ) 7,962,865

INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,101,884 - 1,101,884
Investment in associated companies 4,327,059 - - (4,327,059 ) -
Long-term notes receivable from associated companies - - 8,817 - 8,817
Other 1,320 25,121 201 - 26,642
4,328,379 25,121 1,110,902 (4,327,059 ) 1,137,343
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes 12,331 391,899 - (366,131 ) 38,099
Lease assignment receivable from associated companies - 71,356 - - 71,356
Goodwill 24,248 - - - 24,248
Property taxes - 27,494 22,610 - 50,104
Unamortized sale and leaseback costs - 2,938 - 55,412 58,350
Other 194,916 68,278 16,619 (53,679 ) 226,134
231,495 561,965 39,229 (364,398 ) 468,291
$ 5,592,555 $ 5,863,934 $ 5,137,452 $ (5,134,373 ) $ 11,459,568

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 726 $ 697,986 $ 951,240 $ (18,186 ) $ 1,631,766
Short-term borrowings-
Associated companies - - - - -
Other 100,000 - - - 100,000
Accounts payable-
Associated companies 130,669 212,778 234,626 (190,891 ) 387,182
Other 30,890 125,163 - - 156,053
Accrued taxes 114,043 29,489 16,791 (54,749 ) 105,574
Other 41,828 120,107 27,772 38,081 227,788
418,156 1,185,523 1,230,429 (225,745 ) 2,608,363

CAPITALIZATION:
Common stockholder's equity 3,607,283 2,252,002 2,054,817 (4,306,819 ) 3,607,283
Long-term debt and other long-term obligations 1,519,585 1,865,313 533,990 (1,278,796 ) 2,640,092
5,126,868 4,117,315 2,588,807 (5,585,615 ) 6,247,375

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,001,298 1,001,298
Accumulated deferred income taxes - - 324,311 (324,311 ) -
Accumulated deferred investment tax credits - 37,129 22,350 - 59,479
Asset retirement obligations - 25,011 881,188 - 906,199
Retirement benefits 32,043 168,054 - - 200,097
Property taxes - 27,494 22,610 - 50,104
Lease market valuation liability - 273,624 - - 273,624
Other 15,488 29,784 67,757 - 113,029
47,531 561,096 1,318,216 676,987 2,603,830
$ 5,592,555 $ 5,863,934 $ 5,137,452 $ (5,134,373 ) $ 11,459,568

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of December 31, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents $ - $ 39 $ - $ - $ 39
Receivables-
Customers 86,123 - - - 86,123
Associated companies 363,226 225,622 113,067 (323,815 ) 378,100
Other 991 11,379 12,256 - 24,626
Notes receivable from associated companies 107,229 21,946 - - 129,175
Materials and supplies, at average cost 5,750 303,474 212,537 - 521,761
Prepayments and other 76,773 35,102 660 - 112,535
640,092 597,562 338,520 (323,815 ) 1,252,359

PROPERTY, PLANT AND EQUIPMENT:
In service 134,905 5,420,789 4,705,735 (389,525 ) 9,871,904
Less - Accumulated provision for depreciation 13,090 2,702,110 1,709,286 (169,765 ) 4,254,721
121,815 2,718,679 2,996,449 (219,760 ) 5,617,183
Construction work in progress 4,470 1,441,403 301,562 - 1,747,435
126,285 4,160,082 3,298,011 (219,760 ) 7,364,618

INVESTMENTS:
Nuclear plant decommissioning trusts - - 1,033,717 - 1,033,717
Long-term notes receivable from associated companies - - 62,900 - 62,900
Investment in associated companies 3,596,152 - - (3,596,152 ) -
Other 1,913 59,476 202 - 61,591
3,598,065 59,476 1,096,819 (3,596,152 ) 1,158,208

DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits 24,703 476,611 - (233,552 ) 267,762
Lease assignment receivable from associated companies - 71,356 - - 71,356
Goodwill 24,248 - - - 24,248
Property taxes - 27,494 22,610 - 50,104
Unamortized sale and leaseback costs - 20,286 - 49,646 69,932
Other 59,642 59,674 21,743 (44,625 ) 96,434
108,593 655,421 44,353 (228,531 ) 579,836
$ 4,473,035 $ 5,472,541 $ 4,777,703 $ (4,368,258 ) $ 10,355,021

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt $ 5,377 $ 925,234 $ 1,111,183 $ (16,896 ) $ 2,024,898
Short-term borrowings-
Associated companies 1,119 �� 257,357 6,347 - 264,823
Other 1,000,000 - - - 1,000,000
Accounts payable-
Associated companies 314,887 221,266 250,318 (314,133 ) 472,338
Other 35,367 119,226 - - 154,593
Accrued taxes 8,272 60,385 30,790 (19,681 ) 79,766
Other 61,034 136,867 13,685 36,853 248,439
1,426,056 1,720,335 1,412,323 (313,857 ) 4,244,857

CAPITALIZATION:
Common stockholder's equity 2,944,423 1,832,678 1,752,580 (3,585,258 ) 2,944,423
Long-term debt and other long-term obligations 61,508 1,328,921 469,839 (1,288,820 ) 571,448
3,005,931 3,161,599 2,222,419 (4,874,078 ) 3,515,871

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction - - - 1,026,584 1,026,584
Accumulated deferred income taxes - - 206,907 (206,907 ) -
Accumulated deferred investment tax credits - 39,439 23,289 - 62,728
Asset retirement obligations - 24,134 838,951 - 863,085
Retirement benefits 22,558 171,619 - - 194,177
Property taxes - 27,494 22,610 - 50,104
Lease market valuation liability - 307,705 - - 307,705
Other 18,490 20,216 51,204 - 89,910
41,048 590,607 1,142,961 819,677 2,594,293
$ 4,473,035 $ 5,472,541 $ 4,777,703 $ (4,368,258 ) $ 10,355,021

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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

NET CASH PROVIDED FROM OPERATING ACTIVITIES $ (37,990 ) $ 520,169 $ 408,364 $ (8,732 ) $ 881,811

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt 1,498,087 524,710 333,965 - 2,356,762
Equity contributions from parent - 100,000 150,000 (250,000 ) -
Redemptions and Repayments-
Long-term debt (1,507 ) (258,583 ) (366,857 ) 8,734 (618,213 )
Short-term borrowings, net (901,119 ) (257,357 ) (6,347 ) - (1,164,823 )
Other (11,583 ) (5,261 ) (3,160 ) (2 ) (20,006 )
Net cash provided from financing activities 583,878 103,509 107,601 (241,268 ) 553,720

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (2,224 ) (439,531 ) (400,845 ) - (842,600 )
Proceeds from asset sales - 16,129 - - 16,129
Sales of investment securities held in trusts - - 2,152,717 - 2,152,717
Purchases of investment securities held in trusts - - (2,175,135 ) - (2,175,135 )
Loan to associated companies, net (27,054 ) (178,746 ) (93,041 ) - (298,841 )
Investment in subsidiary (250,000 ) - - 250,000 -
Other 249 (21,470 ) 339 - (20,882 )
Net cash used for investing activities (279,029 ) (623,618 ) (515,965 ) 250,000 (1,168,612 )

Net change in cash and cash equivalents 266,859 60 - - 266,919
Cash and cash equivalents at beginning of period - 39 - - 39
Cash and cash equivalents at end of period $ 266,859 $ 99 $ - $ - $ 266,958

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Nine Months Ended September 30, 2008 FES FGCO NGC Eliminations Consolidated
(In thousands)

NET CASH PROVIDED FROM OPERATING ACTIVITIES: $ 47,463 $ 267,933 $ 247,054 $ (8,317 ) $ 554,133

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt - 328,325 209,050 - 537,375
Equity contribution from parent 280,000 675,000 175,000 (850,000 ) 280,000
Short-term borrowings, net 700,000 - 139,363 (91,677 ) 747,686
Redemptions and Repayments-
Long-term debt (1,777 ) (286,776 ) (180,666 ) 8,317 (460,902 )
Short-term borrowings, net - (91,677 ) - 91,677 -
Common stock dividend payment (43,000 ) - - - (43,000 )
Net cash provided from financing activities 935,223 624,872 342,747 (841,683 ) 1,061,159

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions (38,481 ) (778,329 ) (600,395 ) - (1,417,205 )
Proceeds from asset sales - 15,218 - - 15,218
Sales of investment securities held in trusts - - 596,291 - 596,291
Purchases of investment securities held in trusts - - (624,899 ) - (624,899 )
Loan repayments from (loans to) associated companies, net (94,755 ) (38,399 ) 69,012 - (64,142 )
Investment in subsidiary (850,000 ) - - 850,000 -
Restricted funds for debt redemption - (52,090 ) (29,550 ) - (81,640 )
Other 550 (39,205 ) (260 ) - (38,915 )
Net cash used for investing activities (982,686 ) (892,805 ) (589,801 ) 850,000 (1,615,292 )

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

~~Report~~As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of ~~Independent Registered Public Accounting Firm~~

~~To the Stockholders and Board of~~

~~Directors of FirstEnergy Corp.:~~

~~We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp.~~Merger, subsequently amended on June 4, 2010 (Merger Agreement) with Element Merger Sub, Inc., a Maryland corporation and its ~~subsidiaries as of September 30, 2009~~wholly-owned subsidiary (Merger Sub) and Allegheny Energy, Inc., a Maryland corporation (Allegheny Energy). Upon the ~~related consolidated statements of income~~terms and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

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

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of FirstEnergy Solutions Corp.:~~

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Solutions Corp. and its subsidiaries as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the informationconditions set forth in the ~~accompanying consolidated balance sheet information~~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 ~~December 31, 2008, is fairly stated in all material respects in relation~~FirstEnergy. Pursuant to the ~~consolidated balance sheet from~~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. 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. On July 15, 2010 the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.

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 MDPSC, the PPUC, the VSCC and the PSCWV. 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.

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 ~~it has been derived.~~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.

In connection with the proposed merger, FirstEnergy recorded approximately $7 million ($5 million after tax) of merger transaction costs in the second quarter and approximately $21 million ($15 million after tax) of merger transaction costs in the first six months of 2010. These costs are expensed as incurred.


Item 2.		~~PricewaterhouseCoopers LLP~~ ~~Cleveland, Ohio~~ ~~November 6, 2009~~Management’s Discussion and Analysis of Registrant and Subsidiaries

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Ohio Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of Ohio Edison Company and its subsidiaries as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of Directors of~~

~~The Cleveland Electric Illuminating Company:~~

We have reviewed the accompanying consolidated balance sheet of The Cleveland Electric Illuminating Company and its subsidiaries as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of The Toledo Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of The Toledo Edison Company and its subsidiary as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Jersey Central Power & Light Company:~~

We have reviewed the accompanying consolidated balance sheet of Jersey Central Power & Light Company and its subsidiaries as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Metropolitan Edison Company:~~

We have reviewed the accompanying consolidated balance sheet of Metropolitan Edison Company and its subsidiary as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

~~Report of Independent Registered Public Accounting Firm~~

~~To the Stockholder and Board of~~

~~Directors of Pennsylvania Electric Company:~~

We have reviewed the accompanying consolidated balance sheet of Pennsylvania Electric Company and its subsidiaries as of September 30, 2009 and the related consolidated statements of income and comprehensive income for each of the three-month and nine-month periods ended September 30, 2009 and 2008 and the consolidated statement of cash flows for the nine-month periods ended September 30, 2009 and 2008. These interim financial statements are the responsibility of the Company’s management.

~~PricewaterhouseCoopers LLP~~

~~Cleveland, Ohio~~

~~November 6, 2009~~

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

FIRSTENERGY CORP.

~~MANAGEMENT'S~~MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

~~Net income~~Earnings available to FirstEnergy in the ~~third~~second quarter of ~~2009 was $234~~2010 were $265 million, or basic and diluted earnings of ~~$0.77~~$0.87 per share of common stock, compared with ~~net income~~$414 million, or basic and diluted earnings of ~~$471~~$1.36 per share of common stock in the second quarter of 2009. Results in the second quarter of 2010 were adversely affected by the absence of a 2009 gain from the sale of a 9% participation interest in OVEC. Earnings available to FirstEnergy in the first six months of 2010 were $420 million or basic earnings of ~~$1.55~~$1.38 ($1.37 diluted) per share of common stock, ($1.54 diluted) in the third quarter of 2008. Results in the third quarter of 2009 include a loss of $0.30 per share resulting from the redemption of $1.2 billion of our 6.45% notes, partially offset by $0.25 per share of investment income resulting primarily from the sale of securities held in our nuclear decommissioning trust. Net income in the first nine months of 2009 was $768compared with $533 million, or basic and diluted earnings of ~~$2.52~~$1.75 per share of common stock ~~($2.51 diluted)~~in the first six months of 2009.


	Three Months			Six Months
Change in Basic Earnings Per Share From Prior Year	Ended June 30			Ended June 30

Basic Earnings Per Share — 2009	$	1.36		$	1.75
Non-core asset sales/impairments		(0.52	)		(0.54	)
Trust securities impairments		(0.01	)		0.04
Regulatory charges — 2009		—			0.55
Regulatory charges — 2010		—			(0.08	)
Derivative mark-to-market adjustment — 2010		0.07			(0.04	)
Organizational restructuring — 2009		0.01			0.06
Merger transaction costs — 2010		(0.02	)		(0.05	)
Litigation settlements		0.04			0.04
Debt call premium — 2009		0.01			0.01
Income tax resolution — 2009		—			(0.04	)
Income tax charge from healthcare legislation — 2010		—			(0.04	)
Revenues		0.23			0.16
Fuel and purchased power		(0.28	)		(0.41	)
Transmission expense		(0.08	)		0.02
Amortization of regulatory assets, net		0.06			(0.11	)
Investment income		0.02			0.03
Other expenses		(0.02	)		0.03

Basic Earnings Per Share — 2010	$	0.87		$	1.38

Pending Merger

As previously disclosed, on February 10, 2010, FirstEnergy entered into an Agreement and Plan of Merger, subsequently amended on June 4, 2010, (Merger Agreement) with Element Merger Sub. Inc., ~~compared~~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 ~~net income~~and into Allegheny Energy with Allegheny Energy continuing as the surviving corporation and a wholly-owned subsidiary of ~~$1.01 billion, or basic earnings~~FirstEnergy. Pursuant to the Merger Agreement, upon the closing of ~~$3.32 per~~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 ~~($3.29 diluted)~~of FirstEnergy and Allegheny Energy stockholders will own approximately 27% of the combined company. Based on the closing stock prices for both companies on February 10, 2010, Allegheny Energy shareholders would receive a value of $27.65 per share. On July 15, 2010, the most recent practicable date prior to the effectiveness of the Form S-4 registration statement, the exchange ratio represented approximately $25.06 in value for each share of Allegheny Energy common stock. FirstEnergy will also assume all outstanding Allegheny Energy debt.

FirstEnergy and Allegheny Energy currently anticipate completing the merger in the first ~~nine months~~half of ~~2008.~~

Change in Basic Earnings Per Share
From Prior Year Periods

Three Months
Ended
September 30

Nine Months
Ended
September 30

Basic Earnings Per Share – 2008 $ 1.55 $ 3.32
Gain on non-core asset sales - 0.46
Litigation settlement – 2008 - (0.03 )
Debt redemption premium - 2009 (0.30 ) (0.30 )
Organizational restructuring costs – 2009 (0.07 ) (0.14 )
Regulatory charges – 2009 - (0.55 )
Investment Income 0.17 0.12
Trust securities impairments 0.08 0.08
Income tax adjustments (0.12 ) (0.09 )
Revenues (excluding asset sales) (1.04 ) (1.29 )
Fuel and purchased power 0.10 0.03
Transmission costs 0.30 0.56
Amortization of regulatory assets, net (0.06 ) (0.03 )
Other expenses 0.16 0.38
Basic Earnings Per Share – 2009 $ 0.77 $ 2.52

~~Regulatory Matters~~

~~Ohio Regulatory Update~~

~~On August 6, 2009,~~2011. Although FirstEnergy and Allegheny Energy believe that they will receive the PUCO withdrew proposed rules it had forwarded to the Joint Committee on Agency Rules Review regarding implementation of the alternative energy portfolio standards created by SB221, incorporating energy efficiency requirements, long-term forecastingrequired authorizations, approvals and planning for greenhouse gas reporting and carbon dioxide control. The rules remain under consideration. On October 15, 2009, the PUCO issued a second Entry on Rehearing, modifying certain of its previous rules. Modified rules previously withdrawn from JCARR were refiled with JCARR on October 16 and October 19, 2009. The rules set out the manner in which the electric utilities, including the Ohio companies, will be required to comply with benchmarks contained in SB 221 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. The rules severely restrict the types of renewable energy resources and energy efficiency and peak reduction programs that may be included toward meeting the statutory goals, which is expected to significantly increase the cost of compliance for the Ohio companies' customers. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. On October 23, 2009, the rules were placed in a “to be re-filed” status by JCARR. It is currently unclear what form the final rules may take or their potential impact on the Ohio Companies. As a result of this uncertainty surrounding the rules, as well as the Commission’s failure to address certain energy efficiency application submitted by the Ohio Companies throughout the year and the Commission’s recent directive to postpone the launch of a Commission-approved energy efficiency program, the Ohio Companies, on October 27, 2009, submitted an application to amend their 2009 statutory energy efficiency benchmarks to zero. Absent this regulatory relief the Ohio Companies may not be able to meet their 2009 statutory energy efficiency benchmarks, which may result in the assessment of a forfeiture by the PUCO. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.

On August 19, 2009, the PUCO approved FirstEnergy’s proposal to accelerate the recovery of deferred costs. The principal amount plus carrying charges through August 31, 2009, for these deferrals was $305.1 million. Accelerated recovery began September 1, 2009, and will be collected in the 18 non-summer months through May 31, 2011.

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, reduce supplier risk and encourage bidder participation. A technical conference was held on October 29, 2009, at the PUCO. Pursuant to SB221, the PUCO has 90 days to determine whether the MRO meets certain statutory requirements, therefore, the Ohio Companies have requested a PUCO determination by January 18, 2010. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP

In August and October 2009, the Ohio Companies conducted RFPs to Secure Renewable Energy Credits (RECs). The RFPs include solar and other renewable energy RECs, including those generated in Ohio. The RFCs from these two RFPs will be used to help meet the renewable energy requirements established under Senate Bill 221 for 2009, 2010 and 2011.

~~Pennsylvania Regulatory Update~~

~~Met-Ed and Penelec Default Service Plan Settlements~~

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 is designed to provide adequate and reliable service as required by Pennsylvania law through a prudent mix of long-term, short-term and spot-market generation supply as required by Act 129. The settlement plan proposes a staggered procurement schedule, which varies by customer class. If approved, generation procurement would begin in January 2010.

On September 2, 2009, the ALJ issued a Recommended Decision (RD) and adopted the Companies’ positions on two reserved issues. Exceptions to the ALJ RD were filed on September 22, 2009, with reply exceptions being filed on October 2, 2009. The PPUC's final decision is expected in November 2009.

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 comments were filed by 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 objecting to the above accounting method utilized by Met-Ed and Penelec. The Companies will file reply comments on October 26, 2009.

~~Pennsylvania Smart Meter Plan~~

On August 14, 2009, Penn, Met-Ed and Penelec (the Companies) filed a Smart Meter Technology Procurement and Installation Plan with the PPUC as required by Act 129. The plan includes proposed tariff riders to recover the costs of implementation of the plan and an assessment period of twenty-four months to evaluate needs, select technology, secure vendors, train personnel, install and support test equipment and establish a detailed meter deployment schedule consistent with the requirements of Act 129. At the end of the assessment period, the Companies will submit to the PPUC a supplement to the plan to set forth in detail the Companies’ proposal for the full scale deployment of smart meters. The Companies are asking the PPUC to approve, as part the plan, both the proposed recovery mechanism and the recovery of costs of the assessment period, currently estimated at $29.5 million, through such mechanism.

~~New Jersey Solar Renewable Energy Certificates~~

JCP&L, in collaboration with another New Jersey electric utility, Atlantic City Electric Company (ACE), announced a RFP to secure Solar Renewable Energy Certificates (SREC) as part of the NJBPU's effort to support new solar energy projects. The RFP process was established to help create long-term agreements to purchase and sell SRECs to provide a stable basis for financing new solar generation projects in the companies' service areas. A total of 61 MW of solar generating capacity - 19 for ACE and 42 for JCP&L - will be solicited to help meet New Jersey Renewable Portfolio Standards. The first solicitation was conducted in August; subsequent solicitations will occur over the next three years. The costs of this program are expected to be fully recoverable through a per KWH rate approved by the NJBPU and applied to all customers.

~~Operational Matters~~

~~Fremont Energy Center~~

On September 22, 2009, FirstEnergy announced it expects to complete construction of the Fremont Energy Center by the end of 2010. Originally acquired by FGCO in January 2008, the Fremont Energy Center includes two natural gas combined-cycle combustion turbines and a steam turbine capable of producing 544 MW of load-following capacity and 163 MW of peaking capacity. With the accelerated construction schedule, FES estimates the remaining costconsents to complete the ~~project~~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 ~~$180 million.~~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.

~~Nuclear Outage~~

FERC

On ~~October 12, 2009, NGC's Beaver Valley Nuclear Power Station Unit 2, located in Shippingport, Pennsylvania began a scheduled refueling~~May 11, 2010, FirstEnergy and maintenance outage. During the outage, 60 of the 157 fuel assemblies will be exchanged and safety inspections conducted. In addition, numerous improvement projects will be completed to ensure continued safe and reliable operations.

~~PJM Regional Transmission Organization (RTO) Integration~~

~~As described in the “FERC Matters” section of this document, on August 17, 2009, FirstEnergy~~Allegheny Energy filed an application with the FERC for approval of their proposed merger. Under the Federal Power Act, FERC has 180 days to ~~consolidate its transmission assets~~rule on the merger application. FirstEnergy and ~~operations into PJM. Currently FirstEnergy's transmission assets~~Allegheny Energy submitted additional information regarding the merger application on June 21, 2010 in response to a request by FERC. Interventions and operations are divided between PJM and MISO. The consolidation would move the transmission assets that are part of FirstEnergy's ATSI subsidiary and are located within the footprint of FirstEnergy's Ohio utilities and Pennsylvania Power - into PJM. If approved, the consolidation would provide customersprotests were filed with the ~~benefits~~FERC on July 12, 2010.

State Regulatory Merger Filings

On May 14 and May 18, 2010, FirstEnergy and Allegheny Energy filed applications with the PPUC and the PSCWV, respectively, for approval of their proposed merger. Pennsylvania and West Virginia laws impose no statutory timeframe for their commissions’ consideration of a ~~more fully developed retail choice market,~~merger application, but procedural schedules have been established, and final decisions are anticipated early in 2011. On May 27, 2010, FirstEnergy and its Utilities with the operating efficiencies of a single RTO - with one set of rules, procedures and protocols. To ensure a definitive ruling at the same time FERC rules on its request to integrate ATSI into PJM, on October 19, 2009, FirstEnergy filed a related complaint with FERC on the issue of allocating transmission costs to the ATSI footprint for high voltage transmission projects approved prior to FirstEnergy’s integration into PJM.

FirstEnergy has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whether to integrate ATSI into PJM prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, 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 FirstEnergy's Ohio companies.

On September 4, 2009, the PUCO opened a case to take comments from Ohio 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 hearing on September 15, 2009, to respond to questions regarding the RTO consolidation.

Several parties have intervened in the regulatory dockets at the FERC and 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. The result of these comments and protests could delay or otherwise have a material financial effect on the proposed RTO consolidation.

~~Voluntary Enhanced Retirement Option~~

~~FirstEnergy’s VERO enrollment period concluded September 16, 2009. The VERO was accepted by a total 397 non-represented employees and 318 union employees.~~

~~FirstEnergy Solutions Offers Economic Support Program~~

In September 2009, FES introduced Powering Our Communities, an innovative program that offers economic support to communities in the OE, CEI and TE service areas that purchase discounted electric generation supply from FES through government aggregation programs. The program will provide up-front grants to local Ohio communities and long-term electric generation price savings.

~~Smart Grid Proposal~~

~~On August 6, 2009, FirstEnergy~~Allegheny Energy filed an application for ~~economic stimulus funding~~approval of the proposed merger with the ~~U.S. Department~~MDPSC. The MDPSC is required to issue an order no later than 180 days after an application is filed, but under good cause MDPSC may give itself a 45-day extension, which it did when it issued its initial order in the matter. An order from the MDPSC is therefore expected by January 7, 2011. On June 14, 2010, FirstEnergy and Allegheny Energy completed their application with the VSCC. The VSCC is required to rule on the merger application in 60 days, subject to up to a 120-day extension. In its order issued June 25, 2010, the VSCC extended the period for its review by 30 days; therefore the companies expect a decision by September 13, 2010.

Hart-Scott-Rodino (HSR) Act Filings

On May 25, 2010, FirstEnergy and Allegheny Energy made HSR filings with the DOJ and Federal Trade Commission. On June 24, 2010, FirstEnergy and Allegheny Energy each received a request for additional information from the DOJ, which extends the HSR Act waiting period for an additional 30 days from the date that the requested information is supplied to the DOJ.

Form S-4 Registration Statement

On July 16, 2010, FirstEnergy’s registration statement on Form S-4 containing a joint proxy statement/prospectus relating to the proposed merger (Registration Statement) was declared effective by the SEC. The joint proxy statement/prospectus contained in the Registration Statement was first mailed to FirstEnergy and Allegheny Energy shareholders on or about July 23, 2010. FirstEnergy and Allegheny Energy will each hold a special meeting of ~~Energy under~~shareholders on September 14, 2010 in connection with the proposed merger.

Financial Matters

Financing Activities

On June 1, 2010, FGCO purchased $15 million fixed rate of PCRBs originally issued on its behalf. Subject to market conditions, FGCO plans to remarket the $15 million of PCRBs, as well as $235 million of PCRBs purchased in April, in the near future.

Penn redeemed $1 million of PCRBs due October 1, 2013 on June 1, 2010 and $6.5 million of 7.65% FMBs due in 2023 on July 30, 2010.

During the second quarter of 2010, FirstEnergy executed 13 interest rate swap contracts totaling $3.2 billion. These contacts were subsequently terminated to take advantage of favorable market conditions, and resulted in cash proceeds of $126.7 million. These proceeds will generally be amortized to earnings over the life of the underlying debt.

Operational Matters

Davis-Besse Refueling

On June 3, 2010, modifications of 24 of the 69 control rod drive mechanism (CRDM) nozzles on the reactor head were completed at the Davis-Besse Nuclear Power Station. These nozzles were identified during Davis-Besse’s refueling outage and reactor head inspection that began February 28, 2010. The extended outage at Davis-Besse resulted in a $5 million impact on O&M this quarter, while approximately $40 million of the costs related to the modifications to the CRDM were capitalized. The plant was originally scheduled to have a new reactor head installed in 2014. This timeline was voluntarily accelerated, and FirstEnergy announced that a new reactor head will be installed in the fall of 2011. The new head was manufactured in France and is expected to arrive at the plant in the fall of 2010 to undergo a series of pre-service inspections. Davis-Besse returned to service on June 29, 2010.

Legacy Power Contracts

In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked to market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.

Regulatory Matters — General

DOE Smart Grid Grants

On June 3, 2010, FirstEnergy and the DOE signed grants totaling $57.4 million that were awarded as part of the American Recovery and Reinvestment Act ~~that proposed investing $114 million on~~to introduce smart grid technologies ~~to improve the reliability~~in targeted areas in Pennsylvania, Ohio, and ~~interactivity of its electric distribution infrastructure in its three-state service area.~~New Jersey. The ~~application requested $57 million, which represents half~~DOE grants represent 50% of the funding ~~needed~~ for ~~targeted projects~~the $114.9 million FirstEnergy investment in ~~communities served by~~smart grid technologies; the ~~Utilities. On October 27, 2009,~~PPUC and the NJBPU have already approved recovery for the remaining portion of smart grid costs. The PUCO issued an order on June 30, 2010, approving FirstEnergy’s smart grid program, but FirstEnergy ~~received notice from the Department of Energy that its application was selected for award negotiations. However, no assurance can be given that we will receive any such award.~~

~~Financial Matters~~

~~Rating Agency Update~~

On August 3, 2009, Moody's Investor Service upgraded the senior secured debt ratings of FirstEnergy’s seven regulated utilities as follows: CEI and TE were each upgraded to Baa1 from Baa2, and JCP&L, Met-Ed, OE, Penelec and Penn were each upgraded to A3 from Baa1.

~~Financing Activities~~

On August 7, 2009, FES issued 5, 12 and 30-year unsecured senior notes totaling $1.5 billion. The notes bear interest at an annual rate of 4.80%, 6.05% and 6.80%, respectively. Proceeds received from the issuancehas delayed implementation of the notes were used to pay down borrowings under the $2.75 billion revolving credit facility that FES shares with FirstEnergy and certain other subsidiaries, which made borrowing capacity available to FirstEnergy under the facility to fund a cash tender offer for $1.2 billion of its 6.45% notes, Series B, due 2011. FirstEnergy announced the tender offer on August 4, 2009 and completed it on September 1, 2009. $250 million of the 2011 notes remain outstanding.

On August 14, 2009, $177 million of PCRBs were issued and sold on behalf of FGCO relating to air quality compliance expenditures at the Sammis Plant. The PCRBs bear interest at an annual rate of 5.7% and mature on August 1, 2020.

~~On August 18, 2009, CEI issued $300 million of FMB that bear interest at an annual rate of 5.5% and mature on August 15, 2024. A~~Ohio portion of the ~~proceeds~~program until there is more certainty regarding cost recovery for the portion of the costs not covered by the grant.

Regulatory Matters — Ohio

Electric Security Plan Filing

The Ohio Companies filed a second Supplemental Stipulation with the PUCO on July 22, 2010, to supplement the ESP Stipulation filed on March 23, 2010, and the Supplemental Stipulation filed on May 13, 2010. An additional four signatories were included in the Supplemental Stipulations, joining the Ohio Companies and 17 original signatory parties that support the ESP. A final PUCO order is pending.

Regulatory Matters — Pennsylvania

Met-Ed and Penelec TSC

On May 20, 2010, the PPUC approved the revised TSC for Met-Ed and Penelec. The revised TSC rates were slightly increased for Met-Ed and slightly decreased for Penelec, and are effective for the period of June 1, 2010 to December 31, 2010. The PPUC’s Order of March 3, 2010, which denies the recovery of marginal transmission losses through the TSC for the period of June 1, 2007 through March 31, 2008, remains subject to an appeal that is currently pending in the Commonwealth Court of Pennsylvania.

Met-Ed and Penelec Default Service Plan

On May 27, 2010, the third of four auctions held to procure the default service requirements for Met-Ed and Penelec customers who choose not to shop with an alternative supplier. For the five-month period of January 1, 2011 to May 31, 2011, the tranche-weighted average prices ($/MWh) for Met-Ed’s residential and commercial classes were $72.81 and $72.29, respectively; Penelec’s tranche-weighted average prices were $62.04 and $63.35 for its residential and commercial classes, respectively. There will be ~~used~~another auction in October 2010 to ~~replace $150 million~~procure the remaining supply for this period. The May 2010 auction was also the first of ~~CEI’s 7.43% Series D Secured Notes that mature on November~~four auctions to procure commercial default service requirements for the 12-month period of June 1, ~~2009.~~2011, to May 31, 2012 and residential requirements for the 24-month period of June 1, 2011, to May 31, 2013. For Met-Ed and Penelec commercial customers the tranche-weighted average price ($/MWh) was $66.32 and $57.60, respectively. The remaining ~~proceeds were used to repay a portion of CEI’s short-term borrowings.~~three auctions for these products will be conducted in October 2010, January 2011 and March 2011.

RPM Base Residual Auction

On ~~September 2, 2009,~~May 14, 2010, PJM released the ~~Utilities and ATSI voluntarily contributed $500 million to~~results of the ~~pension plan. On September 30, 2009, Penelec issued $500 million~~2013/2014 RPM Base Residual Auction. The auction cleared 152,743 MW of ~~unsecured notes, of which $250 million mature in 2020 and $250 million mature in 2038. The 2020 notes and 2038 notes bear interest at an annual rate of 5.20% and 6.15%, respectively.~~

~~On October 1, 2009, FGCO and NGC purchased $52.1 million and $29.6 million of PCRBs subject to mandatory purchase. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs~~unforced capacity in the ~~near future.~~RTO Zone, which includes the ATSI zone, at the Resource Clearing Price of $27.73/MW-day. The Clearing Price in MAAC, which includes Met-Ed and Penelec zones and EMAAC which includes the Jersey Central zone, were $226.15/MW-day and $245.00/MW-day, respectively.

~~FIRSTENERGY'S~~FIRSTENERGY’S BUSINESS

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

Energy Delivery Servicestransmits 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 POLR 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.

~~Energy Delivery Services~~ 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. This business segment derives its revenues principally from the delivery of electricity within FirstEnergy's service areas and the sale of electric generation service to retail customers who have not selected an alternative supplier (default service).

Competitive Energy Servicessupplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet all or a portion of the POLR 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 controls approximately 14,000 MW of capacity 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.

~~Competitive Energy Services~~ supplies the electric power needs of end-use customers through retail and wholesale arrangements, including associated company power sales to meet 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, Michigan and Illinois. 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 derived primarily from affiliated company power sales and non-affiliated electric generation sales revenues less the related costs of electricity generation, including purchased power and net transmission and ancillary costs charged by PJM and MISO to deliver energy to the segment's customers.

~~Ohio Transitional Generation Services~~ supplies the electric power needs of non-shopping customers under the default service requirements of FirstEnergy's Ohio Companies. The segment's net income is derived primarily from electric generation sales revenues (including transmission) less the cost of power purchased through the Ohio Companies' CBP and transmission and ancillary costs charged by MISO to deliver energy to retail customers.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among ~~FirstEnergy's~~FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 1211 to the consolidated financial statements. Earnings available to FirstEnergy by major business segment were as follows:


	Three Months Ended									Six Months Ended
	June 30									June 30
							Increase									Increase
	2010			2009			(Decrease)			2010			2009			(Decrease)
	*(In millions, except per share data)*
Earnings By Business Segment:
Energy delivery services	$	143		$	154		$	(11	)	$	257		$	136		$	121
Competitive energy services		125			276			(151	)		201			431			(230	)
Other and reconciling adjustments*		(3	)		(16	)		13			(38	)		(34	)		(4	)

Total	$	265		$	414		$	(149	)	$	420		$	533		$	(113	)


Basic Earnings Per Share	$	0.87		$	1.36		$	(0.49	)	$	1.38		$	1.75		$	(0.37	)
Diluted Earnings Per Share	$	0.87		$	1.36		$	(0.49	)	$	1.37		$	1.75		$	(0.38	)


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

Three Months Ended September 30

Nine Months Ended September 30

Increase Increase
2009 2008 (Decrease) 2009 2008 (Decrease)
(In millions, except per share data)
Earnings By Business Segment:
Energy delivery services $ 139 $ 283 $ (144 ) $ 230 $ 655 $ (425 )
Competitive energy services 183 164 19 614 317 297
Ohio transitional generation services 9 19 (10 ) 55 62 (7 )
Other and reconciling adjustments* (101 ) 5 (106 ) (145 ) (24 ) (121 )
Total $ 230 $ 471 $ (241 ) $ 754 $ 1,010 $ (256 )

Basic Earnings Per Share $ .77 $ 1.55 $ (.78 ) $ 2.52 $ 3.32 $ (.80 )
Diluted Earnings Per Share $ .77 $ 1.54 $ (.77 ) $ 2.51 $ 3.29 $ (.78 )

* 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 ~~– Third~~— Second Quarter ~~2009~~2010 Compared with ~~Third~~Second Quarter ~~2008~~

2009

Financial results for ~~FirstEnergy's~~FirstEnergy’s major business segments in the ~~third~~second quarter of ~~2009~~2010 and ~~2008~~2009 were as follows:


	Energy			Competitive			Other and
	Delivery			Energy			Reconciling			FirstEnergy
Second Quarter 2010 Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,243		$	728		$	—		$	2,971
Other		130			50			(23	)		157
Internal		19			539			(558	)		—

Total Revenues		2,392			1,317			(581	)		3,128


Expenses:
Fuel		—			351			(1	)		350
Purchased power		1,291			319			(558	)		1,052
Other operating expenses		352			337			(16	)		673
Provision for depreciation		115			66			9			190
Amortization of regulatory assets		161			—			—			161
Deferral of new regulatory assets		—			—			—			—
General taxes		145			25			6			176

Total Expenses		2,064			1,098			(560	)		2,602


Operating Income		328			219			(21	)		526

Other Income (Expense):
Investment income		27			13			(9	)		31
Interest expense		(124	)		(55	)		(28	)		(207	)
Capitalized interest		1			24			15			40

Total Other Expense		(96	)		(18	)		(22	)		(136	)


Income Before Income Taxes		232			201			(43	)		390
Income taxes		89			76			(31	)		134

Net Income (Loss)		143			125			(12	)		256
Noncontrolling interest loss		—			—			(9	)		(9	)

Earnings available to FirstEnergy Corp.	$	143		$	125		$	(3	)	$	265


	Energy			Competitive			Other and
	Delivery			Energy			Reconciling			FirstEnergy
Second Quarter 2009 Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)

Revenues:
External
Electric	$	2,657		$	205		$	—		$	2,862
Other		135			299			(25	)		409
Internal		—			839			(839	)		—

Total Revenues		2,792			1,343			(864	)		3,271


Expenses:
Fuel		—			276			—			276
Purchased power		1,677			186			(839	)		1,024
Other operating expenses		328			315			(31	)		612
Provision for depreciation		110			68			7			185
Amortization of regulatory assets		233			—			—			233
Deferral of new regulatory assets		(45	)		—			—			(45	)
General taxes		154			25			5			184

Total Expenses		2,457			870			(858	)		2,469


Operating Income		335			473			(6	)		802

Other Income (Expense):
Investment income		35			6			(14	)		27
Interest expense		(114	)		(32	)		(60	)		(206	)
Capitalized interest		1			14			18			33

Total Other Expense		(78	)		(12	)		(56	)		(146	)


Income Before Income Taxes		257			461			(62	)		656
Income taxes		103			185			(40	)		248

Net Income (Loss)		154			276			(22	)		408
Noncontrolling interest loss		—			—			(6	)		(6	)

Earnings available to FirstEnergy Corp.	$	154		$	276		$	(16	)	$	414

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Third Quarter 2009 Financial Results	Services			Services			Services			Adjustments			Consolidated
Changes Between Second Quarter 2010 and
Second Quarter 2009 Financial Results
Increase (Decrease)
	(In millions)
Revenues:
External
Electric	$	2,067		$	444		$	737		$	-		$	3,248		$	(414	)	$	523		$	—		$	109
Other		136			46			2			(24	)		160			(5	)		(249	)		2			(252	)
Internal		-			617			-			(617	)		-			19			(300	)		281			—

Total Revenues		2,203			1,107			739			(641	)		3,408			(400	)		(26	)		283			(143	)


Expenses:
Fuel		-			302			-			-			302			—			75			(1	)		74
Purchased power		1,011			205			714			(617	)		1,313			(386	)		133			281			28
Other operating expenses		373			331			(9	)		(30	)		665			24			22			15			61
Provision for depreciation		112			69			-			7			188			5			(2	)		2			5
Amortization of regulatory assets		244			-			17			-			261			(72	)		—			—			(72	)
Deferral of new regulatory assets		-			-			-			-			-			45			—			—			45
General taxes		160			27			2			3			192			(9	)		—			1			(8	)

Total Expenses		1,900			934			724			(637	)		2,921			(393	)		228			298			133


Operating Income		303			173			15			(4	)		487			(7	)		(254	)		(15	)		(276	)

Other Income (Expense):
Investment income		46			159			-			(14	)		191			(8	)		7			5			4
Interest expense		(118	)		(46	)		-			(191	)		(355	)		(10	)		(23	)		32			(1	)
Capitalized interest		1			18			-			16			35			—			10			(3	)		7

Total Other Expense		(71	)		131			-			(189	)		(129	)		(18	)		(6	)		34			10


Income Before Income Taxes		232			304			15			(193	)		358			(25	)		(260	)		19			(266	)
Income taxes		93			121			6			(92	)		128			(14	)		(109	)		9			(114	)
Net Income		139			183			9			(101	)		230
Less: Noncontrolling interest income (loss)		-			-			-			(4	)		(4	)

Net Income (Loss)																	(11	)		(151	)		10			(152	)
Noncontrolling interest loss																	—			—			(3	)		(3	)

Earnings available to FirstEnergy Corp.	$	139		$	183		$	9		$	(97	)	$	234		$	(11	)	$	(151	)	$	13		$	(149	)

Ohio
Energy Competitive Transitional Other and
Delivery Energy Generation Reconciling FirstEnergy
Third Quarter 2008 Financial Results Services Services Services Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 2,487 $ 381 $ 781 $ - $ 3,649
Other 170 79 32 (26 ) 255
Internal - 786 - (786 ) -
Total Revenues 2,657 1,246 813 (812 ) 3,904

Expenses:
Fuel - 356 - - 356
Purchased power 1,248 221 623 (786 ) 1,306
Other operating expenses 430 285 110 (31 ) 794
Provision for depreciation 99 67 - 2 168
Amortization of regulatory assets, net 263 - 28 - 291
Deferral of new regulatory assets (76 ) - 18 - (58 )
General taxes 169 26 1 5 201
Total Expenses 2,133 955 780 (810 ) 3,058

Operating Income 524 291 33 (2 ) 846
Other Income (Expense):
Investment income 48 13 1 (22 ) 40
Interest expense (102 ) (44 ) (1 ) (45 ) (192 )
Capitalized interest 1 13 - 1 15
Total Other Expense (53 ) (18 ) - (66 ) (137 )

Income Before Income Taxes 471 273 33 (68 ) 709
Income taxes 188 109 14 (73 ) 238
Net Income 283 164 19 5 471
Less: Noncontrolling interest income - - - - -
Earnings available to FirstEnergy Corp. $ 283 $ 164 $ 19 $ 5 $ 471

Changes Between Third Quarter 2009 and
Third Quarter 2008 Financial Results
Increase (Decrease)

Revenues:
External
Electric $ (420 ) $ 63 $ (44 ) $ - $ (401 )
Other (34 ) (33 ) (30 ) 2 (95 )
Internal - (169 ) - 169 -
Total Revenues (454 ) (139 ) (74 ) 171 (496 )

Expenses:
Fuel - (54 ) - - (54 )
Purchased power (237 ) (16 ) 91 169 7
Other operating expenses (57 ) 46 (119 ) 1 (129 )
Provision for depreciation 13 2 - 5 20
Amortization of regulatory assets (19 ) - (11 ) - (30 )
Deferral of new regulatory assets 76 - (18 ) - 58
General taxes (9 ) 1 1 (2 ) (9 )
Total Expenses (233 ) (21 ) (56 ) 173 (137 )

Operating Income (221 ) (118 ) (18 ) (2 ) (359 )
Other Income (Expense):
Investment income (2 ) 146 (1 ) 8 151
Interest expense (16 ) (2 ) 1 (146 ) (163 )
Capitalized interest - 5 - 15 20
Total Other Expense (18 ) 149 - (123 ) 8

Income Before Income Taxes (239 ) 31 (18 ) (125 ) (351 )
Income taxes (95 ) 12 (8 ) (19 ) (110 )
Net Income (144 ) 19 (10 ) (106 ) (241 )
Less: Noncontrolling interest income - - - (4 ) (4 )
Earnings available to FirstEnergy Corp. $ (144 ) $ 19 $ (10 ) $ (102 ) $ (237 )

Energy Delivery Services ~~– Third~~— Second Quarter ~~2009~~2010 Compared with ~~Third~~Second Quarter ~~2008~~2009

Net income decreased ~~$144 million to $139~~by $11 million in the ~~third~~second quarter of ~~2009~~2010, compared to ~~$283 million in~~ the ~~third~~second quarter of ~~2008,~~2009, primarily due to lower generation-related revenues and ~~decreased~~the absence of deferrals of new regulatory assets, partially offset by lower amortization of regulatory assets and purchased power ~~and other operating expenses~~.costs.

Revenues –

—

The decrease in total revenues resulted from the following sources:


	Three Months							Three Months
	Ended September 30				Increase			Ended June 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)			2010		2009		(Decrease)
	(In millions)							*(In millions)*

Distribution services	$	915	$	1,100	$	(185	)	$	851	$	813	$	38

Generation sales:
Retail		825		986		(161	)		1,097		1,514		(417	)
Wholesale		195		286		(91	)		180		162		18

Total generation sales		1,020		1,272		(252	)		1,277		1,676		(399	)

Transmission		221		241		(20	)		200		259		(59	)
Other		47		44		3			64		44		20

Total Revenues	$	2,203	$	2,657	$	(454	)	$	2,392	$	2,792	$	(400	)

The ~~decrease~~increase in distribution deliveries by customer class is summarized in the following table:


Electric Distribution KWH Deliveries
Residential	~~(8.1)~~7	%
Commercial	~~(6.2)~~5	%
Industrial	~~(15.7)~~13	%
~~Total Distribution KWH Deliveries~~		~~(9.8)~~
Total Distribution KWH Deliveries	8	%

~~Lower~~Higher deliveries to residential and commercial customers reflected ~~decreased~~increased weather-related usage in the ~~third~~second quarter of ~~2009,~~2010, as cooling degree days ~~decreased~~increased by ~~14%~~94% from the same period in ~~2008.~~2009. The ~~decrease~~increase in distribution deliveries to ~~commercial and~~ industrial customers was primarily due to recovering economic conditions in ~~FirstEnergy's~~FirstEnergy’s service ~~territory.~~territory compared to the second quarter of 2009. In the industrial sector, KWH deliveries ~~declined due~~increased to major automotive customers ~~(10.1%~~(39%) and steel customers ~~(42.3%~~(60%). ~~Transition charges for OE and TE that ceased effective January 1, 2009 with~~Distribution service revenues increased primarily due to the ~~full~~ recovery of ~~related costs,~~the PA Energy Efficiency and Conservation charges as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, partially offset by a reduction in the transition rate ~~reduction~~ for CEI effective June 1, ~~2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).~~

2009.

The following table summarizes the price and volume factors contributing to the ~~$252~~$399 million decrease in generation revenues in the ~~third~~second quarter of ~~2009~~2010 compared to the ~~third~~second quarter of ~~2008:~~2009:

~~Sources of Change in Generation Revenues~~	~~(Decrease)~~
	~~(In millions)~~
~~Retail:~~
~~Effect of 12% decrease in sales volumes~~	$	~~(113)~~
~~Change in prices~~		~~(48)~~
		~~(161)~~
~~Wholesale:~~
~~Effect of 18% decrease in sales volumes~~		~~(51)~~
~~Change in prices~~		~~(40)~~
		~~(91)~~
~~Decrease in Generation Revenues~~	$	~~(252)~~


	Increase
Source of Change in Generation Revenues	(Decrease)
	*(In millions)*

Retail:
Effect of 29.4% decrease in sales volumes	$	(444	)
Change in prices		27

		(417	)


Wholesale:
Effect of 10.1% decrease in sales volumes		(16	)
Change in prices		34

		18

Decrease in Generation Revenues	$	(399	)

The decrease in retail generation sales volumes was primarily due to ~~weakened economic conditions and~~an increase in customer shopping in the ~~lower weather-related usage described above. The decrease~~Ohio Companies’ service territories in the second quarter of 2010, which is expected to continue to impact retail generation ~~prices during~~sales, partially offset by higher generation revenues related to the ~~third~~recovery of transmission costs now provided for in the generation rate established under the CBP. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 61% in the second quarter of ~~2009~~2010, as there was no shopping in the second quarter 2009.

The increase in wholesale generation revenues reflected ~~lower composite generation rates~~higher prices for ~~JCP&L resulting from~~Met-Ed’s and Penelec’s sales of NUG power to the ~~New Jersey BGS auction and for Penn under its RFP process. Wholesale generation sales~~PJM market.

Transmission revenues decreased ~~principally as a result of JCP&L selling less available power from NUGs~~$59 million primarily due to the termination of ~~a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot prices for PJM market participants.~~

~~Transmission revenues decreased $20 million primarily due to lower PJM~~the Ohio Companies’ transmission ~~revenues partially offset by higher transmission rates for Met-Ed resulting from the annual update to its TSC rider in~~tariff effective June ~~2009. Met-Ed and Penelec defer the difference between transmission revenues and~~1, 2009; recovery of transmission costs ~~incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).~~is now through the generation rate established under the CBP.

Expenses –

—

Total expenses decreased by ~~$233~~$393 million due to the ~~net impact of the~~ following:

	·•		Purchased power costs were ~~$237~~$386 million lower in the ~~third~~second quarter of ~~2009~~2010 due to lower volume requirements, ~~and~~partially offset by an increase in unit costs from non-affiliates. The decrease in purchased power volumes from non-affiliates resulted principally from the ~~amount~~termination of ~~NUG costs deferred. JCP&L,~~a third-party supply contract for Met-Ed and Penelec ~~are permitted~~in January 2010 and from the above described increase in customer shopping in the Ohio Companies’ service territories. The decrease in volumes from FES principally resulted 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 second quarter of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to ~~defer~~the second quarter of 2009. The decrease in unit costs from FES was principally due to the lower weighted average unit price per KWH for ~~future collection from customers~~ the ~~amounts~~Ohio Companies established under the CBP auction effective June 1, 2009.


	Increase
Source of Change in Purchased Power	(Decrease)
	*(In millions)*

Purchases from non-affiliates:
Change due to increased unit costs	$	156
Change due to decreased volumes		(280	)

		(124	)


Purchases from FES:
Change due to decreased unit costs		(67	)
Change due to decreased volumes		(191	)

		(258	)


Increase in NUG costs deferred		(4	)

Net Decrease in Purchased Power Costs	$	(386	)

	•		Administrative and general costs, including labor and employee benefit expenses, increased $9 million primarily due to a higher level of incentive compensation earned this year, partially offset by ~~which~~lower payroll expenses due to staffing reductions implemented in 2009.

	•		Energy Efficiency program costs ~~incurred~~increased $14 million in the second quarter of 2010 compared to the second quarter of 2009.

	•		Forestry contractor costs decreased by $3 million in the second quarter of 2010 compared to the second quarter of 2009, as more resources were dedicated to capital projects in 2010.

	•		A favorable JCP&L labor settlement reduced expenses by $7 million in the second quarter of 2010.

	•		Transmission costs, net of regulatory asset amortization expense, decreased by $61 million primarily due to the transfer of transmission cost responsibility to generation providers under ~~NUG agreements exceed amounts collected through rates.~~ the CBP.

	•		The ~~following table summarizes~~deferral of new regulatory assets decreased $45 million in the ~~sources~~second quarter of ~~changes in~~2010 principally due to reduced CEI purchased power ~~costs:~~cost deferrals in the second quarter of 2009.

	•		Depreciation expense increased $5 million due to property additions since the second quarter of 2009.

	•		General taxes decreased $9 million primarily due to a favorable Ohio property tax settlement in 2010.

Source of Change in Purchased Power
Increase
(Decrease)

(In millions)
Purchases from non-affiliates:
Change due to increased unit costs
$ 38
Change due to decreased volumes
(209 )
(171 )
Purchases from FES:
Change due to decreased unit costs
(7 )
Change due to increased volumes
19
12

Increase in NUG costs deferred (78 )
Net Decrease in Purchased Power Costs $ (237 )

· ~~PJM transmission expenses were lower by $83 million resulting from reduced volumes and congestion costs.~~

· ~~Contractor and material costs decreased $9 million due primarily to reduced maintenance activities as more work was devoted to capital projects.~~

· ~~Organizational restructuring charges of $15 million were partially offset by lower labor expenses of $11 million.~~

· ~~Employee benefits increased $37 million as a result of higher pension costs.~~

· ~~Storm-related costs were $6 million lower than in the third quarter of 2008.~~

·~~Amortization of regulatory assets decreased $19 million due primarily to the cessation of transition cost amortization for OE and TE, partially offset by higher PJM~~

~~transmission cost amortization in the third quarter of 2009.~~

· ~~The deferral of new regulatory assets decreased by $76 million in the third quarter of 2009 principally due to the absence of PJM transmission cost deferrals in~~

~~Pennsylvania and RCP distribution cost deferrals by the Ohio Companies.~~

· ~~Depreciation expense increased $13 million due to property additions since the third quarter of 2008.~~

· ~~General taxes decreased $9 million primarily due to lower gross receipts and excise taxes.~~

Other Expense –—

Other expense increased $18 million in the ~~third~~second quarter of ~~2009~~2010 compared to the third quarter of 2008 due to higher interest expense of $16 million, reflecting $300 million of senior notes issuances by each of JCP&L and Met-Ed in January 2009, $300 million of senior notes by TE in April 2009, and $300 million of FMBs by CEI in August 2009, partially offset by lower investment income of $2 million (reduced loan balances to the regulated money pool).

~~Competitive Energy Services – Third Quarter 2009 Compared with Third Quarter 2008~~

Net income for this segment was $183 million in the third quarter of 2009 compared to $164 million in the same period of 2008. The $19 million increase in net income principally reflects an increase in investment income offset by a decrease in gross sales margins.

~~Revenues –~~

~~Total revenues decreased $139 million in the third~~second quarter of 2009 primarily due to ~~lower generation~~higher interest expense associated with debt issuances by the Utilities since the second quarter of 2009.

Competitive Energy Services — Second Quarter 2010 Compared with Second Quarter 2009

Net income decreased by $151 million in the second quarter of 2010, compared to the second quarter of 2009, primarily due to the absence of a $252 million gain ($158 million after tax) in 2009 from the sale of a 9% participation interest in OVEC.

Revenues —

Total revenues, excluding the OVEC sale, increased $226 million in the second quarter of 2010 primarily due to an increase in direct and government aggregation sales volumes, partially offset by decreases in POLR sales to the Ohio Companies ~~partially offset by higher non-affiliated retail generation sales volumes.~~

and wholesale sales.

The decrease in total revenues resulted from the following sources:

Three Months
Ended September 30 Increase
Revenues By Type of Service 2009 2008 (Decrease)
(In millions)
Non-Affiliated Generation Sales:

Retail

$
232
$
171
$
61
Wholesale
212 210 2
Total Non-Affiliated Generation Sales
444 381 63
Affiliated Generation Sales
616 786 (170
)
Transmission
17 47 (30
)
Other
30 32 (2 )
Total Revenues

$
1,107
$
1,246
$
(139
)


	Three Months
	Ended June 30				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	*(In millions)*

Direct and Government Aggregation	$	586	$	83	$	503
POLR		586		839		(253	)
Wholesale		95		122		(27	)
Transmission		19		16		3
Sale of OVEC participation interest		—		252		(252	)
Other		31		31		—

Total Revenues	$	1,317	$	1,343	$	(26	)

The ~~higher retail revenues reflect the acquisition of~~increase in direct and government aggregation ~~programs~~revenues of $503 million resulted from increased revenue in ~~Ohio~~both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new ~~retail customer contracts in the MISO~~commercial and ~~PJM markets in the third quarter of 2009. FES has signed~~industrial customers as well as new government aggregation contracts with 50 communities in Ohio that provide ~~discounted~~ generation ~~prices~~ to ~~approximately 600,000~~1.1 million residential and small commercial ~~customers. Higher non-affiliated wholesale revenues resulted from lower sales volumes and higher prices in~~customers at the ~~PJM market offset by lower prices in~~end of June 2010 compared to 21,000 at the ~~MISO market.~~

end of June 2009.

The ~~lower affiliated company generation~~decrease in POLR revenues ~~were~~of $253 million was due ~~primarily~~ to ~~a decrease in~~lower sales volumes to the Ohio Companies and lower unit prices, partially offset by increased sales volumes and higher unit prices ~~for~~to the Pennsylvania Companies. The lower sales volumes and unit prices to the Ohio Companies ~~and higher sales volumes~~in the second quarter 2010 reflected the results of the May 2009 power procurement process. The increased revenues to the Pennsylvania ~~Companies. While unit~~Companies resulted from FES supplying Met-Ed and Penelec with volumes previously supplied through a third-party contract and at prices ~~for each~~that were slightly higher than in the second quarter of ~~the Pennsylvania Companies did not change, the mix of~~2009.

Wholesale revenues decreased $27 million due to reduced volumes, reflecting increased retail sales ~~among the companies caused the composite price to decline. Subsequent to the~~in Ohio ~~Companies’ CBP, FES purchased additional tranches from other winning bidders~~ and ~~effective September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements. Prior to the CBP, FES supplied 100% of the Ohio Companies' PLR generation requirements.~~

lower prices.

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


	Increase
Source of Change in Direct and Government Aggregation	(Decrease)
	*(In millions)*

Direct Sales:
Effect of increase in sales volumes	$	345
Change in prices		(16	)

		329


Government Aggregation:
Effect of increase in sales volumes		174
Change in prices		—

		174

Net Increase in Direct and Gov’t Aggregation Revenues	$	503


Source of Change in Wholesale Revenues	Decrease
	*(In millions)*

POLR:
Effect of 20.4% decrease in sales volumes	$	(171	)
Change in prices		(82	)

		(253	)


Wholesale:
Effect of 21.9% decrease in sales volumes		(15	)
Change in prices		(12	)

		(27	)


Decrease in Wholesale Revenues	$	(280	)

Source of Change in Non-Affiliated Generation Revenues

Increase (Decrease)

(In millions)
Retail:
Effect of 10.7% increase in sales volumes
$ 19
Change in prices
42
61
Wholesale:
Effect of 2.8% decrease in sales volumes
(6 )
Change in prices
8
2
Net Increase in Non-Affiliated Generation Revenues $ 63

Source of Change in Affiliated Generation Revenues

Increase (Decrease)

(In millions)
Ohio Companies:
Effect of 47.8% decrease in sales volumes
$ (297 )
Change in prices
115
(182 )
Pennsylvania Companies:
Effect of 12.2% increase in sales volumes
19
Change in prices
(7 )
12
Net Decrease in Affiliated Generation Revenues $ (170 )

Transmission revenues ~~decreased $30~~increased $3 million duedue primarily to ~~reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008.~~higher MISO congestion revenue.

Expenses -

—

Total expenses ~~decreased $21~~increased $228 million in the ~~third~~second quarter of ~~2009~~2010 due to the ~~following factors:~~

following:

·	•	Fuel costs ~~decreased $54~~increased $75 million due to ~~decreased~~increased generation volumes primarily at the fossil units ($~~109~~73 million) and higher unit prices ($2 million). The increase in unit prices was due primarily to higher nuclear fuel unit prices following the refueling outages that occurred in 2009.

	•	Purchased power costs increased $133 million due primarily to higher volumes purchased ($162 million) and higher unit costs ($6 million), partially offset by ~~higher unit prices~~power contract mark-to-market adjustments ($5535 million). In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked-to-market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.

·
~~Purchased power~~	•		Fossil operating costs decreased ~~$16~~$3 million due primarily to lower ~~volume requirements ($71 million),~~professional and contractor costs, partially offset by ~~higher unit costs ($55 million) resulting from higher capacity costs.~~reduced gains on the sale of emission allowances.

·	~~Fossil operating costs decreased $14 million due to a reduction in contractor and material costs, resulting from FirstEnergy’s cost control initiatives.~~

•

Nuclear operating costs decreased ~~$12~~$17 million due primarily to lower labor and ~~employee benefit expenses of $6 million~~professional and ~~reductions in~~ contractor costs due to one less refueling outage in 2010 as compared to the same period of ~~$5 million.~~2009.

·
~~Other operating~~	•		Transmission expenses increased ~~$32~~$26 million due primarily to ~~increased intersegment billings for leasehold costs from the Ohio Companies and increased pension costs.~~

·	~~Transmission expense increased $41 million due primarily to increased transmission costs~~increases in MISO of ~~$24~~$63 million from higher network and ~~higher~~ancillary costs, partially offset by lower PJM transmission expenses of $37 million due to lower congestion and loss costs.

	•	Other expenses increased $14 million primarily due to increases in ~~PJM of $15 million.~~uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.

·	~~Higher depreciation expense of $2 million was due primarily to NGC's increased ownership interests in Perry and Beaver Valley Unit 2 following its purchase of lease equity interests.~~

Other Expense –—

Total other expense in the ~~third~~second quarter of ~~2009~~2010 was $149 million lower than the third quarter of 2008, primarily due to a $146 million increase in earnings from nuclear decommissioning trust investments and a $3 million decrease in interest expense (net of capitalized interest).

~~Ohio Transitional Generation Services – Third Quarter 2009 Compared with Third Quarter 2008~~

Net income for this segment decreased $10 million to $9 million in the third quarter of 2009 from $19 million in the same period of 2008. Higher purchased power costs were partially offset by higher generation revenues and lower operating expenses.

~~Revenues –~~

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

Three Months
Ended September 30 Increase
Revenues by Type of Service 2009 2008 (Decrease)
(In millions)
Generation sales:

Retail
$ 726 $ 675 $ 51
Wholesale
- 4 (4 )
Total generation sales
726 679 47
Transmission
11 134 (123 )
Other
2 - 2
Total Revenues
$ 739 $ 813 $ (74 )

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

Source of Change in Retail Generation Revenues

Increase
(Decrease)

(In millions)
Effect of 17% decrease in sales volumes $ (116 )
Change in prices
167
Total Increase in Retail Generation Revenues $ 51

The decrease in generation sales volumes was primarily due to increased customer shopping resulting from certain government aggregation programs in Ohio, lower weather-related usage and economic conditions in the Ohio Companies’ service territory. Average prices increased primarily due to the result of the Ohio Companies' CBP. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs was included in the generation rate established under the CBP.

Decreased transmission revenue of $123 million resulted from the termination of the transmission tariff (as discussed above), reduced MISO revenues and lower sales volumes. Prior to June 1, 2009, the difference between transmission revenues and transmission costs incurred was deferred, resulting in no material impact to current period earnings.

~~Expenses -~~

~~Purchased power costs were $91~~$6 million higher ~~due primarily to higher unit costs, partially offset by a decrease in volumes. The factors contributing to the higher costs are summarized in the following table:~~

Source of Change in Purchased Power
Increase
(Decrease)

(In millions)

Change due to increased unit costs
$ 194
Change due to decreased volumes
(103 )
$ 91

The decrease in purchased volumes was due to the lower retail generation sales requirements described above. The higher unit costs reflect the results of the Ohio Companies' CBP for retail customers during the third quarter of 2009 (see Regulatory Matters – Ohio).

Other operating expenses decreased $119 million due to lower MISO transmission-related expenses (effective June 1, 2009 transmission costs are paid by the generation suppliers) and increased intersegment credits related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets decreased by $29 million in the third quarter of 2009 due primarily to lower MISO transmission cost amortization.

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

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

Ohio
Energy Competitive Transitional Other and
Delivery Energy Generation Reconciling FirstEnergy
First Nine Months 2009 Financial Results Services Services Services Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 5,823 $ 929 $ 2,499 $ - $ 9,251
Other 413 400 20 (71 ) 762
Internal - 2,349 - (2,349 ) -
Total Revenues 6,236 3,678 2,519 (2,420 ) 10,013

Expenses:
Fuel - 890 - - 890
Purchased power 2,853 551 2,425 (2,349 ) 3,480
Other operating expenses 1,167 1,001 22 (87 ) 2,103
Provision for depreciation 331 201 - 18 550
Amortization of regulatory assets 791 - 112 - 903
Deferral of new regulatory assets - - (136 ) - (136 )
General taxes 480 84 6 17 587
Total Expenses 5,622 2,727 2,429 (2,401 ) 8,377

Operating Income 614 951 90 (19 ) 1,636
Other Income (Expense):
Investment income 110 136 1 (40 ) 207
Interest expense (343 ) (106 ) - (306 ) (755 )
Capitalized interest 3 42 - 51 96
Total Other Expense (230 ) 72 1 (295 ) (452 )

Income Before Income Taxes 384 1,023 91 (314 ) 1,184
Income taxes 154 409 36 (169 ) 430
Net Income 230 614 55 (145 ) 754
Less: Noncontrolling interest income (loss) - - - (14 ) (14 )
Earnings available to FirstEnergy Corp. $ 230 $ 614 $ 55 $ (131 ) $ 768

Ohio
Energy Competitive Transitional Other and
Delivery Energy Generation Reconciling FirstEnergy
First Nine Months 2008 Financial Results Services Services Services Adjustments Consolidated
(In millions)
Revenues:
External
Electric $ 6,567 $ 994 $ 2,142 $ - $ 9,703
Other 484 170 61 8 723
Internal - 2,266 - (2,266 ) -
Total Revenues 7,051 3,430 2,203 (2,258 ) 10,426

Expenses:
Fuel 1 999 - - 1,000
Purchased power 3,228 648 1,766 (2,266 ) 3,376
Other operating expenses 1,288 906 268 (88 ) 2,374
Provision for depreciation 309 179 - 12 500
Amortization of regulatory assets 747 - 48 - 795
Deferral of new regulatory assets (274 ) - 13 - (261 )
General taxes 491 82 4 19 596
Total Expenses 5,790 2,814 2,099 (2,323 ) 8,380

Operating Income 1,261 616 104 65 2,046
Other Income (Expense):
Investment income 133 (1 ) 1 (60 ) 73
Interest expense (305 ) (116 ) (1 ) (137 ) (559 )
Capitalized interest 2 30 - 4 36
Total Other Expense (170 ) (87 ) - (193 ) (450 )

Income Before Income Taxes 1,091 529 104 (128 ) 1,596
Income taxes 436 212 42 (105 ) 585
Net Income 655 317 62 (23 ) 1,011
Less: Noncontrolling interest income - - - 1 1
Earnings available to FirstEnergy Corp. $ 655 $ 317 $ 62 $ (24 ) $ 1,010

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

Revenues:
External
Electric $ (744 ) $ (65 ) $ 357 $ - $ (452 )
Other (71 ) 230 (41 ) (79 ) 39
Internal - 83 - (83 ) -
Total Revenues (815 ) 248 316 (162 ) (413 )

Expenses:
Fuel (1 ) (109 ) - - (110 )
Purchased power (375 ) (97 ) 659 (83 ) 104
Other operating expenses (121 ) 95 (246 ) 1 (271 )
Provision for depreciation 22 22 - 6 50
Amortization of regulatory assets 44 - 64 - 108
Deferral of new regulatory assets 274 - (149 ) - 125
General taxes (11 ) 2 2 (2 ) (9 )
Total Expenses (168 ) (87 ) 330 (78 ) (3 )

Operating Income (647 ) 335 (14 ) (84 ) (410 )
Other Income (Expense):
Investment income (23 ) 137 - 20 134
Interest expense (38 ) 10 1 (169 ) (196 )
Capitalized interest 1 12 - 47 60
Total Other Expense (60 ) 159 1 (102 ) (2 )

Income Before Income Taxes (707 ) 494 (13 ) (186 ) (412 )
Income taxes (282 ) 197 (6 ) (64 ) (155 )
Net Income (425 ) 297 (7 ) (122 ) (257 )
Less: Noncontrolling interest income - - - (15 ) (15 )
Earnings available to FirstEnergy Corp. $ (425 ) $ 297 $ (7 ) $ (107 ) $ (242 )

~~Energy Delivery Services – First Nine Months of 2009 Compared to First Nine Months of 2008~~

Net income decreased $425 million to $230 million in the first nine months of 2009 compared to $655 million in the first nine months of 2008, primarily due to lower revenues and decreased deferrals of new regulatory assets, partially offset by lower purchased power and other operating expenses.

~~Revenues –~~

~~The decrease in total revenues resulted from the following sources:~~

Nine Months
Ended September 30 Increase
Revenues by Type of Service 2009 2008 (Decrease)
(In millions)
Distribution services

$
2,578

$
2,974

$
(396
)
Generation sales:

Retail

2,355

2,548
(193 )
Wholesale

545

758
(213
)
Total generation sales

2,900

3,306
(406 )
Transmission

616

633
(17 )
Other

142

138
4
Total Revenues

$
6,236

$
7,051

$
(815 )

~~The decrease in distribution deliveries by customer class are summarized in the following table:~~

~~Electric Distribution KWH Deliveries~~
~~Residential~~	~~(3.7)~~	%
~~Commercial~~	~~(4.7)~~	%
~~Industrial~~	~~(18.0)~~	%
~~Total Distribution KWH Deliveries~~	~~(8.6)~~	%

The lower revenues from distribution deliveries were due to reductions in sales volume and lower unit prices. The decreases in distribution deliveries to commercial and industrial customers were primarily due to economic conditions in FirstEnergy's service territories. In the industrial sector, KWH deliveries declined due to major automotive customers (25.0%) and steel customers (44.4%). Transition charges for OE and TE that ceased effective January 1, 2009 with the full recovery of related costs and the transition rate reduction for CEI effective June 1, 2009, were partially offset by PUCO-approved distribution rate increases (see Regulatory Matters – Ohio).

~~The following table summarizes the price and volume factors contributing to the $406 million decrease in generation revenues in the first nine months of 2009 compared to the same period of 2008:~~

Increase
Sources of Change in Generation Revenues (Decrease)
(In millions)
Retail:
  Effect of 8% decrease in sales volumes $ (208 )
  Change in prices
15

(193
)
Wholesale:
  Effect of 14% decrease in sales volumes (108 )
  Change in prices
(105
)

(213
)
Net Decrease in Generation Revenues $ (406 )

The decrease in retail generation sales volumes was primarily due to weaker economic conditions and reduced weather-related usage. Cooling degree days decreased by 17% in the first nine months of 2009, while heating degree days increased by 3% compared to the same period last year. The increase in retail generation prices during the first nine months of 2009 was due to higher generation rates for JCP&L and Penn under their power procurement processes. Wholesale generation sales decreased principally as a result of JCP&L selling less available power from NUGs due to the termination of a NUG purchase contract in October 2008. The decrease in wholesale prices reflected lower spot market prices in PJM.

Transmission revenues decreased $17 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed and Penelec resulting from the annual updates to their TSC riders.

~~Expenses –~~

~~Total expenses decreased by $168 million due to the following:~~

Purchased power costs were $375 million lower in the first nine months of 2009 due to reduced volumes and an increase in the amount of NUG costs deferred, partially offset by higher unit costs. The increased unit costs primarily reflected the effect of higher JCP&L costs resulting from its BGS auction process. The following table summarizes the sources of changes in purchased power costs:

Source of Change in Purchased Power
Increase
(Decrease)

(In millions)
Purchases from non-affiliates:
Change due to increased unit costs
$ 196
Change due to decreased volumes
(471 )
(275 )
Purchases from FES:
Change due to decreased unit costs
(23 )
Change due to increased volumes
57
34

Increase in NUG costs deferred (134 )
Net Decrease in Purchased Power Costs $ (375 )

· ~~PJM transmission expenses were lower by $164 million, resulting primarily from reduced volumes and lower congestion costs.~~

· ~~Organizational restructuring charges of $32 million and increased pension costs of $102 million were partially offset by lower labor expenses of $50 million.~~

· ~~An increase in other operating expense of $32 million resulted from recognition of economic development and energy efficiency obligations in accordance with~~

~~the PUCO-approved ESP.~~

· ~~Contractor and material expenses decreased $48 million, reflecting more costs dedicated to capital projects compared to the prior year.~~

· ~~Storm related costs were $6 million lower in the first nine months of 2009.~~

· ~~Lower general business expenses of $18 million reflected FirstEnergy’s cost control initiatives.~~

· ~~A $44 million increase in the amortization of regulatory assets was due primarily to the ESP-related impairment of CEI’s regulatory assets and PJM transmission~~

~~cost amortization in the first nine months of 2009, partially offset by the cessation of transition cost amortization for OE and TE.~~

·~~A $274 million decrease in the deferral of new regulatory assets was principally due to the absence in 2009 of PJM transmission cost deferrals and RCP distribution~~

~~cost deferrals by the Ohio Companies.~~

· ~~Depreciation expense increased $22 million due to property additions since the third quarter of 2008.~~

· ~~General taxes decreased $11 million due to lower gross receipts taxes.~~

~~Other Expense –~~

Other expense increased $60 million in the first nine months of 2009 compared to 2008. Lower investment income of $23 million resulted primarily from repaid notes receivable from affiliates since the third quarter of 2008. Higher interest expense (net of capitalized interest) of $38 million resulted from debt issuances described above under Financing Activities.

~~Competitive Energy Services – First Nine Months of 2009 Compared to First Nine Months of 2008~~

Net income increased to $614 million in the first nine months of 2009 compared to $317 million in the same period of 2008. The increase in net income includes FGCO's $252 million gain from the sale of a 9% participation interest in OVEC ($158 million after tax), an increase in investment income, and an increase in gross sales margins.

~~Revenues –~~

Total revenues increased $248 million in the first nine months of 2009 compared to the same period in 2008. This increase primarily resulted from the OVEC sale and higher unit prices on affiliated generation sales to the Ohio Companies and non-affiliated customers, partially offset by lower sales volumes.

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

Nine Months
Ended September 30 Increase
Revenues by Type of Service 2009 2008 (Decrease)
(In millions)
Non-Affiliated Generation Sales:

Retail
$ 406 $ 485 $ (79 )
Wholesale
523 509 14
Total Non-Affiliated Generation Sales
929 994 (65 )
Affiliated Generation Sales
2,349 2,266 83
Transmission
57 113 (56 )
Sale of OVEC participation interest
252 - 252
Other
91 57 34
Total Revenues
$ 3,678 $ 3,430 $ 248

The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue in both the PJM and MISO markets. The increase in MISO retail revenue is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail revenue resulted from the acquisition of new customers, higher sales volumes and unit prices. FES has signed new government aggregation contracts with 50 communities in Ohio that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM offset by decreased spot market prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, offset by decreased sales volumes in PJM.

The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES versus other suppliers, partially offset by lower sales to Penn due to decreased default service requirements in the first nine months of 2009 compared to the first nine months of 2008.

~~In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In~~than the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders. Effective September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements. Prior to the CBP, FES supplied 100% of the Ohio Companies' PLR generation requirements.

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

Increase
Source of Change in Non-Affiliated Generation Revenues

(Decrease)

(In millions)
Retail:
Effect of 34.3% decrease in sales volumes
$ (166 )
Change in prices

87

(79
)
Wholesale:
Effect of 3.5% decrease in sales volumes
(18 )
Change in prices

32

14

Net Decrease in Non-Affiliated Generation Revenues
$
(65
)

Increase
Source of Change in Affiliated Generation Revenues

(Decrease)

(In millions)
Ohio Companies:
Effect of 28.9% decrease in sales volumes
$ (508)
Change in prices

557

49

Pennsylvania Companies:
Effect of 11.1% increase in sales volumes
57
Change in prices

(23)

34

Net Increase in Affiliated Generation Revenues
$
83

~~Transmission revenues decreased $56 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008.~~ ~~Other revenue increased $34 million primarily due to rental income associated with NGC's acquisition of equity interests in the Perry and Beaver Valley Unit 2 leases.~~

~~Expenses -~~

~~Total expenses decreased $87 million in the first nine months of 2009 due to the following factors:~~

· ~~Fuel costs decreased $109 million due to lower generation volumes ($227 million), partially offset by higher unit prices ($118 million).~~

· ~~Purchased power costs decreased $97 million due to lower volume ($170 million), partially offset by higher unit prices ($73 million) that resulted primarily from~~

~~higher capacity costs.~~

· ~~Fossil operating costs decreased $46 million due primarily to a reduction in contractor and material costs ($38 million) and more labor dedicated to capital projects~~

~~($6 million) compared to the prior year.~~

· ~~Nuclear operating costs decreased $4 million in the first nine months of 2009 as lower labor and employee benefits expense was partially offset by the cost of an~~

~~additional refueling outage during the 2009 period.~~

· ~~Other expense increased $83 million due primarily to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension costs.~~

· ~~Transmission expense increased $64 million due primarily to increased net congestion in PJM and higher loss expenses in MISO and PJM.~~

· ~~Higher depreciation expense of $22 million was due to NGC's increased ownership interest in Beaver Valley Unit 2 and Perry.~~

~~Other Expense –~~

~~Total other expense in the first nine months of 2009 was $159 million lower than the first nine months of 2008,~~ primarily due to a ~~$137~~$13 million increase in ~~earnings~~interest expense from new long-term debt issued combined with the restructuring of existing long-term debt, partially offset by a $7 million increase in investment income resulting from more favorable performance of the nuclear decommissioning trust investments ~~and a decline in interest expense (net~~($6 million).

Other — Second Quarter of ~~capitalized interest)~~2010 Compared with Second Quarter of ~~$22 million due to the repayment of notes payable to affiliates.~~

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

Net income for this segment decreased $7 million to $55 million in the first nine months of 2009 from $62 million in the same period of 2008. Higher purchased power expenses were partially offset by higher generation revenues and increased deferrals of regulatory assets.

~~Revenues –~~

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

Nine Months Ended
September 30
Revenues by Type of Service 2009 2008 Increase (Decrease)
(In millions)
Generation sales:

Retail

$
2,323

$
1,868

$
455
Wholesale

-

9
(9 )
Total generation sales

2,323

1,877
446
Transmission

192

319
(127
)
Other

4

7
(3 )
Total Revenues

$
2,519

$
2,203

$
316

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

Source of Change in Generation Revenues

Increase
(Decrease)

(In millions)
Retail:
Effect of 3% decrease in sales volumes
$ (52 )
Change in prices

507

Net Increase in Retail Generation Revenues
$
455

The decrease in generation sales volume in the first nine months of 2009 was primarily due to milder weather and economic conditions in the Ohio Companies' service territory. Average price increases reflect an increase in the Ohio Companies' fuel cost recovery riders that were in effect from January through May 2009. In addition, effective June 1, 2009, the transmission tariff ended with the recovery of transmission costs now included in the generation rate established under the Ohio Companies' CBP.

Decreased transmission revenue of $127 million resulted primarily from the termination of the transmission tariff effective June 1, 2009, lower MISO transmission related revenues and decreased sales volumes.

~~Expenses -~~

~~Purchased power costs were $659 million higher due primarily to higher unit costs for power. The factors contributing to the higher costs are summarized in the following table:~~

Source of Change in Purchased Power
Increase
(Decrease)

(In millions)

Change due to increased unit costs
$ 712
Change due to decreased volumes
(53 )
$ 659

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

Other operating expenses decreased $246 million due primarily to lower MISO transmission expenses and higher intersegment cost reimbursements related to the Ohio Companies' generation leasehold interests. The amortization of regulatory assets increased by $64 million in the first nine months of 2009 due primarily to increased MISO transmission cost amortization. The deferral of new regulatory assets increased by $149 million due to CEI’s deferral of purchased power costs as approved by the PUCO.

~~Other – First Nine Months of 2009 Compared to First Nine Months of 2008~~

Financial results from other operating segments and reconciling items, including interest expense on holding company debt and corporate support services revenues and expenses, resulted in a ~~$107~~$13 million ~~decrease~~increase in ~~FirstEnergy's net income~~earnings available to FirstEnergy in the first ~~nine months~~quarter of ~~2009~~2010 compared to the same period in ~~2008.~~2009. The increase resulted primarily from reduced interest expense on holding company debt resulting from the September 2009 tender offer ($20M), partially offset by increased operating expenses.

Summary of Results of Operations — First Six Months of 2010 Compared with the First Six Months of 2009

Financial results for FirstEnergy’s major business segments in the first six months of 2010 and 2009 were as follows:


	Energy			Competitive			Other and
	Delivery			Energy			Reconciling			FirstEnergy
First Six Months 2010 Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	4,641		$	1,397		$	—		$	6,038
Other		275			97			(50	)		322
Internal*		19			1,213			(1,165	)		67

Total Revenues		4,935			2,707			(1,215	)		6,427


Expenses:
Fuel		—			688			(4	)		684
Purchased power		2,686			769			(1,165	)		2,290
Other operating expenses		732			684			(42	)		1,374
Provision for depreciation		228			132			23			383
Amortization of regulatory assets		373			—			—			373
Deferral of new regulatory assets		—			—			—			—
General taxes		307			60			14			381

Total Expenses		4,326			2,333			(1,174	)		5,485


Operating Income		609			374			(41	)		942

Other Income (Expense):
Investment income		52			14			(19	)		47
Interest expense		(248	)		(108	)		(64	)		(420	)
Capitalized interest		2			44			35			81

Total Other Expense		(194	)		(50	)		(48	)		(292	)


Income Before Income Taxes		415			324			(89	)		650
Income taxes		158			123			(36	)		245

Net Income (Loss)		257			201			(53	)		405
Noncontrolling interest loss		—			—			(15	)		(15	)

Earnings available to FirstEnergy Corp.	$	257		$	201		$	(38	)	$	420


	Energy			Competitive			Other and
	Delivery			Energy			Reconciling			FirstEnergy
First Six Months 2009 Financial Results	Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	5,518		$	485		$	—		$	6,003
Other		295			354			(47	)		602
Internal		—			1,732			(1,732	)		—

Total Revenues		5,813			2,571			(1,779	)		6,605


Expenses:
Fuel		—			588			—			588
Purchased power		3,553			346			(1,732	)		2,167
Other operating expenses		827			670			(58	)		1,439
Provision for depreciation		219			132			11			362
Amortization of regulatory assets		642			—			—			642
Deferral of new regulatory assets		(136	)		—			—			(136	)
General taxes		324			57			14			395

Total Expenses		5,429			1,793			(1,765	)		5,457


Operating Income		384			778			(14	)		1,148

Other Income (Expense):
Investment income		65			(23	)		(26	)		16
Interest expense		(224	)		(60	)		(116	)		(400	)
Capitalized interest		2			24			35			61

Total Other Expense		(157	)		(59	)		(107	)		(323	)


Income Before Income Taxes		227			719			(121	)		825
Income taxes		91			288			(77	)		302

Net Income (Loss)		136			431			(44	)		523
Noncontrolling interest loss		—			—			(10	)		(10	)

Earnings available to FirstEnergy Corp.	$	136		$	431		$	(34	)	$	533


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

Revenues:
External
Electric	$	(877	)	$	912		$	—		$	35
Other		(20	)		(257	)		(3	)		(280	)
Internal*		19			(519	)		567			67

Total Revenues		(878	)		136			564			(178	)


Expenses:
Fuel		—			100			(4	)		96
Purchased power		(867	)		423			567			123
Other operating expenses		(95	)		14			16			(65	)
Provision for depreciation		9			—			12			21
Amortization of regulatory assets		(269	)		—			—			(269	)
Deferral of new regulatory assets		136			—			—			136
General taxes		(17	)		3			—			(14	)

Total Expenses		(1,103	)		540			591			28


Operating Income		225			(404	)		(27	)		(206	)

Other Income (Expense):
Investment income		(13	)		37			7			31
Interest expense		(24	)		(48	)		52			(20	)
Capitalized interest		—			20			—			20

Total Other Expense		(37	)		9			59			31


Income Before Income Taxes		188			(395	)		32			(175	)
Income taxes		67			(165	)		41			(57	)

Net Income (Loss)		121			(230	)		(9	)		(118	)
Noncontrolling interest loss		—			—			(5	)		(5	)

Earnings available to FirstEnergy Corp.	$	121		$	(230	)	$	(4	)	$	(113	)


*		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.

Energy Delivery Services — First Six Months of 2010 Compared to First Six Months of 2009

Net income increased by $121 million in the first six months of 2010, compared to the first six months 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 generation related revenues and decreased deferrals of new regulatory assets.

Revenues —

The decrease in total revenues resulted from the following sources:


	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	*(In millions)*
Distribution services	$	1,733	$	1,662	$	71

Generation sales:
Retail		2,274		3,128		(854	)
Wholesale		397		349		48

Total generation sales		2,671		3,477		(806	)

Transmission		415		577		(162	)
Other		116		97		19

Total Revenues	$	4,935	$	5,813	$	(878	)

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


Electric Distribution KWH Deliveries
Residential	1	%
Commercial	2	%
Industrial	10	%

Total Distribution KWH Deliveries	4	%

Higher deliveries to residential and commercial customers reflected increased weather-related usage in the first six months of 2010. Cooling degree days increased by 94%, partially offset by a 10% decrease in heating degree days from the same period in 2009. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in FirstEnergy’s service territory compared to the first six months of 2009. In the industrial sector, KWH deliveries increased to major automotive customers (26%) and steel customers (44%). Distribution service revenues increased primarily due to the recovery of the PA Energy Efficiency and Conservation charges as approved by the PPUC in March 2010 and the accelerated recovery of deferred distribution costs in Ohio, 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 $806 million decrease in generation revenues in the first six months of 2010 compared to the same period of 2009:


	Increase
Source of Change in Generation Revenues	(Decrease)
	*(In millions)*
Retail:
Effect of 30% decrease in sales volumes	$	(939	)
Change in prices		85

		(854	)


Wholesale:
Effect of 12.2% decrease in sales volumes		(42	)
Change in prices		90

		48

Net Decrease in Generation Revenues	$	(806	)

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 six months of 2010, which is expected to continue to impact retail generation sales, partially offset by higher generation revenues related to the recovery of transmission costs now provided for in the generation rate established under the CBP. Total generation KWH provided by alternative suppliers as a percentage of total KWH deliveries for the Ohio Companies increased to 57% in the first six months of 2010, as there was no shopping in the same period of 2009.

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

Transmission revenues decreased $162 million primarily due to the termination of the Ohio Companies’ transmission tariff effective June 1, 2009; recovery of transmission costs is now through the generation rate established under the CBP.

Expenses —

Total expenses decreased by $1,103 million due to the following:

Purchased power costs were $867 million lower in the first six months of 2010 due to lower volume requirements, partially offset by an increase in unit costs for purchased power from non-affiliates. The decrease in volumes from non-affiliates resulted principally from the termination of a third-party supply contract for Met-Ed and Penelec in January 2010 and from the above described increase in customer shopping in the Ohio Companies’ service territories. The decrease in volumes from FES principally resulted 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 six months of 2010 resulted from higher capacity prices in the PJM market for Met-Ed and Penelec compared to the first six months 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.


	Increase
Source of Change in Purchased Power	(Decrease)
	*(In millions)*
Purchases from non-affiliates:
Change due to increased unit costs	$	346
Change due to decreased volumes		(703	)

		(357	)


Purchases from FES:
Change due to decreased unit costs		(160	)
Change due to decreased volumes		(343	)

		(503	)


Increase in NUG costs deferred		(7	)

Net Decrease in Purchased Power Costs	$	(867	)

MISO/PJM transmission expenses decreased $43 million primarily due to the recovery of transmission costs now provided for in the generation rate established under the CBP, partially offset by higher PJM congestion charges.

Administrative and general costs, including labor and employee benefits expenses, decreased by $22 million in the first six month of 2010 compared to 2009 due to lower payroll expenses resulting from staffing reductions implemented in 2009.

Other operating expenses decreased $28 million due to higher economic development commitments recognized in the first quarter of 2009 relating to the amended ESP and a favorable labor settlement of $7 million for JCP&L recognized in the second quarter of 2010.

Amortization of regulatory assets decreased $269 million due primarily to the absence of the $216 million impairment of CEI’s regulatory assets in the second quarter of 2009, reduced transmission cost amortization and reduced CTC amortization for Met-Ed and Penelec, partially offset by a $35 million regulatory asset impairment associated with the filing of the Ohio Companies’ ESP on March 23, 2010.

The deferral of new regulatory assets decreased $136 million in the first six months of 2010 principally due to reduced CEI purchased power cost deferrals in the second quarter of 2009.

Depreciation expense increased $9 million due to property additions since the second quarter of 2009.

General taxes decreased $17 million due to favorable Ohio and Pennsylvania tax settlements in 2010.

Other Expense —

Other expense increased $37 million in the first six months of 2010 compared to the first six months of 2009 primarily due to higher interest expense associated with debt issuances by the Utilities since the second quarter of 2009.

Competitive Energy Services — First Six Months of 2010 Compared to First Six Months of 2009

Net income decreased by $230 million in the first six months of 2010, compared to the first six months of 2009, primarily due to the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation in OVEC and a decrease in sales margins.

Revenues —

Total revenues, excluding the OVEC sale, increased $388 million in the first six months of 2010 compared to the same period in 2009 primarily due to an increase in direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.

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


	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	*(In millions)*
Direct and Government Aggregation	$	1,097	$	174	$	923
POLR		1,260		1,732		(472	)
Wholesale		186		311		(125	)
Transmission		36		41		(5	)
RECs		67		—		67
Sale of OVEC participation interest		—		252		(252	)
Other		61		61		—

Total Revenues	$	2,707	$	2,571	$	136

The increase in direct and government aggregation revenues of $923 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to 1.1 million residential and small commercial customers at the end of June 2010 compared to 21,000 at the end of June 2009, partially offset by lower unit prices. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.

The decrease in POLR revenues of $472 million was 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 2010 reflected the results of the May 2009 power procurement process. 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 2009.

Wholesale revenues decreased $125 million due to reduced volumes reflecting market declines and lower prices.

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


	Increase
Source of Change in Direct and Government Aggregation	(Decrease)
	*(In millions)*
Direct Sales:
Effect of increase in sales volumes	$	633
Change in prices		(47	)

		586


Government Aggregation:
Effect of increase in sales volumes		337
Change in prices		—

		337

Net Increase in Direct and Gov’t Aggregation Revenues	$	923


Source of Change in Wholesale Revenues	Decrease
	*(In millions)*
POLR:
Effect of 15.1% decrease in sales volumes	$	(262	)
Change in prices		(210	)

		(472	)


Wholesale:
Effect of 56.7% decrease in sales volumes		(123	)
Change in prices		(2	)

		(125	)

Decrease in Wholesale Revenues	$	(597	)

Transmission revenues decreased $5 million due primarily to lower PJM congestion revenue.

Expenses —

Total expenses increased $540 million in the first six months of 2010 due to the following factors:

Fuel costs increased $100 million due to increased generation volumes ($44 million) and higher unit prices ($56 million). The increase in unit prices was due primarily to higher nuclear fuel unit prices following the refueling outages that occurred in 2009 and increased coal transportation costs.

Purchased power costs increased $423 million due primarily to higher volumes purchased ($484 million), and power contract mark-to-market adjustments ($17 million), partially offset by lower unit costs ($78 million). In July 2010, FES entered into financial transactions that offset the mark-to-market impact of legacy purchased power contracts totaling 500 MW entered into in 2008 for delivery in 2010 and 2011 and which were marked-to-market beginning in December 2009. These financial transactions eliminate the volatility associated with marking these contracts to market through the end of 2011.

Fossil operating costs decreased $2 million due primarily to lower labor costs which were partially offset by higher professional and contractor costs and reduced gains on the sale of emission allowances.

Nuclear operating costs decreased $37 million due primarily to lower labor and professional and contractor costs. The six months ended June 2010 had one less refueling outage and fewer extended outages than the same period of 2009.

Transmission expenses increased $33 million due primarily to increased costs in MISO of $106 million from higher network and ancillary costs, partially offset by lower PJM transmission expenses of $73 million due to lower congestion and loss costs.

	•		Other expenses increased $20 million primarily due to increases in uncollectible customer accounts and agent fees associated with the growth in direct and government aggregation sales.

	•		General taxes increased $3 million due to sales taxes on higher revenues.

Other Expense —

Total other expense in the six months ending June 2010 was $9 million lower than the same period in 2009, primarily due to a $37 million increase in investment income resulting from more favorable performance of the nuclear decommissioning trust investments, partially offset by a $28 million increase in interest expense. Interest expense increased because of new issuances of long-term debt combined with the restructuring of existing long-term debt.

Other — First Six Months of 2010 Compared to First Six Months of 2009

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 $4 million decrease in earnings available to FirstEnergy in the first six months of 2010 compared to the same period in 2009. The decrease resulted primarily from increased other operating expenses and depreciation ($28 million) and increased income tax expense ($41 million), partially offset by reduced interest expense on holding company debt ~~redemption costs~~ ($~~90 million, net~~52 million) which was primarily the result of ~~taxes) and the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes).~~

a September 2009 tender offer.

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~~FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During ~~2009~~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 ~~September~~June 30, ~~2009, FirstEnergy's~~2010, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($~~1.7~~1.5 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of ~~September~~June 30, ~~2009,~~2010, included the following (in millions):


Currently Payable Long-term Debt
PCRBs supported by bank LOCs⁽¹⁾	$	1,318
FGCO and NGC unsecured PCRBs⁽¹⁾		75
Penelec FMBs⁽²⁾		24
NGC collateralized lease obligation bonds		50
Sinking fund requirements		41
Other notes⁽²⁾		63

	$	1,571


⁽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.

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)
$ 1,553
FGCO and NGC unsecured PCRBs(1)
97
CEI secured notes(2)
150
Met-Ed unsecured notes(3)
100
Penelec unsecured notes(4)
35
NGC collateralized lease obligation bonds 44
Sinking fund requirements 41
$ 2,020

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

Short-Term Borrowings

FirstEnergy had approximately ~~$1.7~~$1.5 billion of short-term borrowings as of ~~September~~June 30, ~~2009~~2010 and ~~$2.4~~$1.2 billion as of December 31, 2008. FirstEnergy, along with certain of its subsidiaries, has access to $2.75 billion of short-term financing under a revolving credit facility that expires in August 2012. A total of 25 banks participate in the facility, with no one bank having more than 7.3% of the total commitment. As of October 30, 2009, FirstEnergy had $120 million of bank credit facilities in addition to the $2.75 billion revolving credit facility. Also, an aggregate of $550 million of accounts receivable financing facilities through the Ohio and Pennsylvania Companies may be accessed to meet working capital requirements and for other general corporate purposes. In August 2009, FGCO and FES cancelled an unused $300 million secured term loan facility with Credit Suisse. FirstEnergy's2009. FirstEnergy’s available liquidity as of ~~October 30, 2009,~~July 31, 2010, is summarized in the following table:


						Available
Company	Type	Maturity		Commitment		Liquidity
				(In millions)
FirstEnergy⁽¹⁾	Revolving	Aug. 2012		$	2,750	$	1,407
FirstEnergy Solutions	Bank line	Mar. 2011			100		—
Ohio and Pennsylvania Companies	Receivables financing	Various	⁽²⁾		395		267

		Subtotal		$	3,245	$	1,674
		Cash			—		127

		Total		$	3,245	$	1,801


⁽¹⁾		FirstEnergy Corp. and subsidiary borrowers.

⁽²⁾		Ohio — $250 million matures March 30, 2011; Pennsylvania — $145 million matures December 17, 2010

Company Type Maturity Commitment
Available
Liquidity as of
October 30, 2009

(In millions)
FirstEnergy(1)
Revolving Aug. 2012 $ 2,750 $ 1,334
FirstEnergy and FES Bank lines
Various(2)
120 20
Ohio and Pennsylvania Companies Receivables financing
Various(3)
550 306
Subtotal $ 3,420 $ 1,660
Cash - 748
Total $ 3,420 $ 2,408

(1) FirstEnergy Corp. and subsidiary borrowers.
(2) $100 million expires March 31, 2011; $20 million uncommitted line of credit has no expiration date.
(3) $180 million expires December 18, 2009; $370 million expires February 22, 2010.

Revolving Credit Facility

FirstEnergy has the capability to request an increase in the total commitments available under the $2.75 billion revolving credit facility (included in the borrowing capability table above) up to a maximum of $3.25 billion, subject to the discretion of each lender to provide additional commitments. 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.

The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of ~~September~~June 30, ~~2009:~~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			34	⁽²⁾
CEI		250	⁽³⁾		500
TE		250	⁽³⁾		500
JCP&L		425			405	⁽²⁾
Met-Ed		250			300	⁽²⁾
Penelec		250			300	⁽²⁾
ATSI		50	⁽⁴⁾		50

Revolving Regulatory and
Credit Facility Other Short-Term
Borrower

Sub-Limit

Debt Limitations
(In millions)
FirstEnergy $ 2,750 $ - (1)
FES 1,000 - (1)
OE 500 500
Penn 50 39 (2)
CEI 250 (3) 500
TE 250 (3) 500
JCP&L 425 428 (2)
Met-Ed 250 300 (2)
Penelec 250 300 (2)
ATSI - (4) 50

(1)No regulatory approvals, statutory or charter limitations applicable.
(2)Excluding amounts which may be borrowed under the regulated companies' money pool.
(3)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody's.
(4)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody's or (ii) FirstEnergy has guaranteed ATSI's obligations of such borrower under the facility.


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

⁽²⁾		Excluding amounts that 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~~borrower’s borrowing sub-limit.

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of ~~September~~June 30, ~~2009, FirstEnergy's~~2010, FirstEnergy’s and its ~~subsidiaries'~~subsidiaries’ debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:


Borrower
FirstEnergy⁽¹⁾	~~61.6~~	61.1	%
FES	~~54.2~~	52.1	%
OE	~~46.6~~	53.4	%
Penn	~~32.9~~	31.3	%
CEI		59.3	%
TE	~~53.9~~	59.1	%
JCP&L	~~34.9~~	36.5	%
Met-Ed	~~41.6~~	38.2	%
Penelec	~~54.1~~	53.4	%
ATSI		50.3	%

~~(1)~~
⁽¹⁾		As of ~~September~~June 30, ~~2009,~~2010, FirstEnergy could issue additional debt of approximately ~~$2.4~~$2.9 billion, or recognize a reduction in equity of approximately ~~$1.3~~$1.6 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.

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

FirstEnergy Money Pools

~~FirstEnergy's~~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~~FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first ~~nine~~six months of ~~2009~~2010 was ~~0.78%~~0.51% per annum for the regulated ~~companies'~~companies’ money pool and ~~0.96%~~0.59% per annum for the unregulated ~~companies'~~companies’ money pool.

Pollution Control Revenue Bonds

As of ~~September~~June 30, ~~2009, FirstEnergy's~~2010, FirstEnergy’s currently payable long-term debt included approximately ~~$1.6~~$1.3 billion (FES ~~- $1.5~~— $1.2 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:~~banks as of June 30, 2010:


	Aggregate LOC			Reimbursements of
LOC Bank	Amount⁽²⁾		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⁽³⁾
The Royal Bank of Scotland		131	June 2012	6 months
Wachovia Bank		153	March 2014	March 2014
Barclays Bank⁽¹⁾		528	Beginning December 2010	30 days
PNC Bank		70	Beginning November 2010	180 days

Total	$	1,332

Aggregate LOC Reimbursements of
LOC Bank
Amount(3)
LOC Termination Date LOC Draws Due
(In millions)
CitiBank N.A. $ 166 June 2014 June 2014
The Bank of Nova Scotia 255 Beginning June 2010
Shorter of 6 months or
LOC termination date
The Royal Bank of Scotland 131 June 2012 6 months
KeyBank(1)
266 June 2010 6 months
Wachovia Bank 153 March 2014 March 2014
Barclays Bank(2)
528 Beginning December 2010 30 days
PNC Bank 70 Beginning November 2010 180 days
Total $ 1,569
(1) Supported by four participating banks, with the LOC bank having 62% of the total commitment.
(2) Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.
(3) Includes approximately $16 million of applicable interest coverage.


⁽¹⁾		Supported by 18 participating banks, with no one bank having more than 14% of the total commitment.

⁽²⁾		Includes approximately $14 million of applicable interest coverage.

⁽³⁾		Shorter of 6 months or LOC termination date ($155 million) and shorter of one year or LOC termination date ($129 million).

In ~~February 2009, holders of approximately $434~~June 2010, FGCO purchased $15 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were also remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. Also, in June 2009, FGCO and NGC delivered FMBs to certain LOC banks listed above in connection with amendments to existing LOC and reimbursement agreements supporting twelve other series of PCRBs as described below and pledged FMBs to the applicable trustee under six separate series of PCRBs. On August 14, 2009, $177 million of non-LOC supported fixed rate PCRBs ~~were~~originally issued ~~and sold~~ on ~~behalf of~~its behalf. In April 2010, FGCO ~~to pay a portion of the cost of acquiring, constructing and installing air quality facilities at its W.H. Sammis Generating Station. On October 1, 2009, FGCO and NGC repurchased~~purchased approximately ~~$52.1~~$235 million ~~and $29.6 million of~~ variable rate PCRBs ~~respectively. These PCRBs are secured by a corresponding series of FMBs until December 31, 2009.~~and cancelled $237 million LOC held with KeyBank. Subject to market conditions, FGCO ~~and NGC plan~~plans to remarket the $15 million PCRBs, as well as the $235 million PCRBs purchased ~~PCRBs~~ in ~~fixed-rate mode~~April, in the near ~~future.~~future as market conditions permit.

Long-Term Debt Capacity

As of ~~September~~June 30, ~~2009,~~2010, the Ohio Companies and Penn had the aggregate capability to issue approximately ~~$1.5~~$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 ~~$164~~$107 million and ~~$32~~$21 million, respectively, as of ~~September~~June 30, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance, and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006.2010. As a result of the indenture provisions, ~~for~~ TE tocannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt ~~do not apply. In August 2009 CEI issued $300~~of approximately $377 million and $343 million, respectively, under provisions of ~~FMB. CEI restricted $150 million~~their senior note indentures as of ~~the proceeds to fund the redemption of $150 million of secured notes due in November 2009.~~

June 30, 2010.

Based upon ~~FGCO's~~FGCO’s FMB indenture, net earnings and available bondable property additions as of ~~September~~June 30, ~~2009,~~2010, FGCO had the capability to issue ~~$2.2~~$2.9 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million principal amount of FMBs, of which $247.7 million related to three new refunding series of PCRBs and approximately $148.2 million related to amendments to existing LOC and reimbursement agreements supporting two other series of PCRBs. On June 30, 2009, FGCO issued a total of approximately $52.1 million principal amount of FMBs related to three existing series of PCRBs (repurchased in October 2009, as described above).

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 ~~$264~~$294 million of additional FMBs as of September 30, 2009. On June 16, 2009, NGC issued a total of approximately $487.5 million principal amount of FMBs, of which $107.5 million related to one new refunding series of PCRBs and approximately $380 million related to amendments to existing LOC and reimbursement agreements supporting seven other series of PCRBs. In addition, on June 16, 2009, NGC issued an FMB in a principal amount of up to $500 million in connection with NGC's delivery of a Surplus Margin Guaranty of FES’ obligations to post and maintain collateral under the Power Supply Agreement entered into by FES with the Ohio Companies as a result of the May 13-14, 2009 CBP auction. On June 30, 2009, NGC issued a total of approximately $273.3 million principal amount of FMBs, of which approximately $92 million related to three existing series of PCRBs ($29.6 million repurchased in October 2009, as described above) and approximately $181.3 million related to amendments to existing LOC and reimbursement agreements supporting three other series of PCRBs.2010.

~~Met-Ed and Penelec had the capability to issue secured debt of approximately $376 million and $319 million, respectively, under provisions of their senior note indentures as of September 30, 2009.~~

~~FirstEnergy's~~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'~~FirstEnergy’s, FES’ and the ~~Utilities'~~Utilities’ securities ratings as of ~~September~~June 30, 2009. On August 3, 2009 Moody’s upgraded the majority of senior secured debt ratings of investment grade regulated utilities by one notch. S&P's and Moody's outlook for FirstEnergy and its subsidiaries remains "stable."2010.

~~Issuer~~

~~Securities~~

Senior Secured

Senior Unsecured

Issuer

S&P

Moody’s

~~Moody's~~

Fitch

S&P

Moody’s

Fitch

FirstEnergy Corp.

—

BB+

Baa3

BBB

FirstEnergy Solutions

~~Senior unsecured~~—

—

BBB-

~~Baa3~~Baa2

BBB

~~FES~~

~~Senior secured~~

Ohio Edison

BBB

~~Baa1~~

~~Senior unsecured~~BBB+

BBB-

Baa2

BBB

~~Baa2~~

~~Senior secured~~

Pennsylvania Power

BBB+

~~Senior unsecured~~—

~~BBB~~—

~~Baa2~~—

~~Penn~~

~~Senior secured~~

A-

Cleveland Electric Illuminating

A3BBB

Baa1

BBB

BBB-

Baa3

BBB-

~~CEI~~

~~Senior secured~~

~~BBB+~~

~~Baa1~~

~~Senior unsecured~~

Toledo Edison

BBB

~~Baa3~~Baa1

BBB

—

~~Senior secured~~

~~BBB+~~

~~Baa1~~

~~Senior unsecured~~

~~BBB~~

Jersey Central Power & Light

~~Baa3~~—

—

BBB-

Baa2

BBB+

~~JCP&L~~

~~Senior unsecured~~

Metropolitan Edison

BBB

BBB+

BBB-

Baa2

BBB

~~Met-Ed~~

~~Senior unsecured~~

Pennsylvania Electric

BBB

BBB+

BBB-

Baa2

BBB

~~Penelec~~

~~Senior unsecured~~

~~BBB~~

ATSI

~~Baa2~~—

—

BBB-

Baa1

—

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

Changes in Cash Position

As of ~~September~~June 30, ~~2009,~~2010, FirstEnergy had ~~$838~~$281 million in cash and cash equivalents compared to ~~$545~~$874 million as of December 31, ~~2008. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less.~~2009. As of ~~September~~June 30, ~~2009, approximately $794 million of cash and cash equivalents represented temporary overnight deposits. As of September 30, 2009~~2010 and December 31, ~~2008,~~2009, FirstEnergy had ~~$171~~approximately $10 million and ~~$17~~$12 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

During the first ~~nine~~six months of ~~2009,~~2010, FirstEnergy received ~~$621~~$655 million of cash ~~from~~ dividends ~~and equity repurchases~~ from its subsidiaries and paid ~~$503~~$335 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%. CEI and TE are the only utility subsidiaries currently precluded from that action.

Cash Flows From Operating Activities

~~FirstEnergy's~~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~~decreased by ~~$33~~$244 million during the first ~~nine~~six months of ~~2009~~2010 compared to the comparable period in ~~2008,~~2009, as summarized in the following table:


									Six Months
	Nine Months Ended September 30								Ended June 30						Increase
Operating Cash Flows	2009		2008			Increase (Decrease)			2010			2009			(Decrease)
	(In millions)								*(In millions)*
Net income	$	754	$	1,011		$	(257	)	$	405		$	523		$	(118	)
Non-cash charges and other adjustments		1,755		1,033			722			789			719			70
Pension trust contribution		(500)		-			(500	)
Working capital and other		(545)		(613	)		68
Working Capital and other										(336	)		(140	)		(196	)
	$	1,464	$	1,431		$	33
									$	858		$	1,102		$	(244	)

The increase in non-cash charges and other adjustments is primarily due to higher deferred income taxes and investment tax credits ($90 million) and higher non-cash retirement benefit expenses ($66 million) recognized in the first six months of 2010, partially offset by lower net amortization of regulatory assets ($~~233~~133 million), including CEI’s $216 million regulatory asset impairment ~~changes in accrued compensation and retirement benefits ($147 million), changes in deferred income taxes and investment tax credits, net ($143 million), and an increase in~~recorded during the ~~provision for depreciation ($50 million). Also included in non-cash charges and other adjustments was a $142 million charge relating to debt redemptions in 2009,~~first quarter of ~~which $122 million was related primarily to the premium paid and included as a cash outflow in financing activities.~~2009. The ~~changes~~change in working capital and other charges primarily resulted from a ~~$73~~$111 million decrease in ~~stock-based compensation payments~~cash collateral received, a $98 million decrease in prepayments and another current assets, and a $43 million increase in ~~other~~ accrued ~~expenses principally associated with~~taxes, partially offset by a $188 million increase in receivables and a $23 million increase in materials and supplies. The change in prepayments and accrued taxes primarily relates to the ~~implementation~~timing of ~~the Ohio Companies’ Amended ESP.~~income tax payments.

Cash Flows From Financing Activities

In the first ~~nine~~six months of ~~2009,~~2010, cash used for financing activities was $484 million compared to cash provided from financing activities ~~was $617 million compared to $911~~of $426 million in the first ~~nine~~six months of ~~2008.~~2009. The decrease was primarily due to ~~increased~~new debt issuances in 2009 and the repayment of short-term borrowings in 2010, partially offset by decreased long-term debt redemptions ~~and reduced short-term borrowings, partially offset by increased long-term debt issuances~~ in the first nine months of 2009. The increased long-term debt redemptions were primarily due to the $1.2 billion tender offer completed by FirstEnergy in September 2009, including approximately $122 million of premiums and redemption expenses paid.2010. The following table summarizes security issuances (net of any discounts) and ~~redemptions, including premiums paid to debt holders as a result of the tender offer.~~redemptions:


	Six Months
	Ended June 30
Securities Issued or Redeemed	2010		2009
	*(In millions)*

New Issues
First mortgage bonds		—		100
Pollution control notes		—		682
Senior secured notes		—		297
Unsecured Notes		—		600

	$	—	$	1,679


Redemptions
Pollution control notes		251		682
Senior secured notes		55		46
Unsecured notes		100		153

	$	406	$	881


Short-term borrowings, net	$	281	$	—

Nine Months Ended
September 30
Securities Issued or Redeemed
2009 2008
(In millions)
New issues
First mortgage bonds $ 398 $ -
Pollution control notes 859 611
Senior secured notes 297 -
Unsecured notes 2,597 20
$ 4,151 $ 631

Redemptions
First mortgage bonds $ - $ 1
Pollution control notes 687 534
Senior secured notes 54 23
Unsecured notes* 1,472 175
$ 2,213 $ 733

Short-term borrowings, net $ (764) $ 1,489

* Including premiums and redemption expenses paid of $122 million.

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

Issuing Company

Issue
Date

Principal
(in millions)

Type

Maturity

Use of Proceeds

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

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

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

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

FES 08/07/2009
$400
$600
$500

4.80% Senior Notes
6.05% Senior Notes
6.80% Senior Notes

2015
2021
2039

Repay short-term borrowings and other
general purposes

CEI* 08/18/2009 $300 5.50% FMB 2024
$150M placed with trustee for future debt redemption, repay short-term borrowings
and other general purposes

Penelec* 9/30/2009
$250
$250

5.20% Senior Notes
6.15% Senior Notes

2020
2038
Repay short-term borrowings

* Issued under the shelf registration statement referenced above.

On October 30, 2009, Penelec provided notice for early redemption of its $35 million aggregate principal 7.77% Notes due August 2, 2010. The Notes are scheduled to be redeemed on November 30, 2009 with a make-whole redemption price.

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 ~~nine~~first six months ~~ended September 30,~~of 2010 and 2009 ~~and 2008~~ by business segment:


Summary of Cash Flows	Property												Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total			Additions			Investments			Other			Total
													*(In millions)*
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2009
Six Months Ended June 30, 2010
Energy delivery services	$	(524	)	$	(121	)	$	(35	)	$	(680	)	$	(338	)	$	87		$	(20	)	$	(271	)
Competitive energy services		(893	)		(6	)		(21	)		(920	)		(605	)		(11	)		(1	)		(617	)
Other		(133	)		-			(11	)		(144	)		(10	)		(3	)		—			(13	)
Inter-Segment reconciling items		(25	)		(25	)		6			(44	)		(44	)		(22	)		—			(66	)

Total	$	(1,575	)	$	(152	)	$	(61	)	$	(1,788	)	$	(997	)	$	51		$	(21	)	$	(967	)

Nine Months Ended September 30, 2008

Six Months Ended June 30, 2009
Energy delivery services	$	(621	)	$	33		$	(3	)	$	(591	)	$	(343	)	$	48		$	(23	)	$	(318	)
Competitive energy services		(1,430	)		(13	)		(121	)		(1,564	)		(669	)		2			(22	)		(689	)
Other		(106	)		57			(54	)		(103	)		(119	)		(7	)		(3	)		(129	)
Inter-Segment reconciling items		(20	)		(12	)		-			(32	)		(12	)		(25	)		—			(37	)

Total	$	(2,177	)	$	65		$	(178	)	$	(2,290	)	$	(1,143	)	$	18		$	(48	)	$	(1,173	)

Net cash used for investing activities in the first ~~nine~~six months of ~~2009~~2010 decreased by ~~$502~~$206 million compared to the first ~~nine~~six months of ~~2008.~~2009. The decrease was principally due to a ~~$602~~$146 million decrease in property additions, which reflects lower AQC system expenditures, and ~~the absence in 2009~~cash proceeds of the purchase of certain lessor equity interests in Beaver Valley Unit 2 and Perry, and the purchase of the partially-completed Fremont Energy Center. The decrease in property additions was partially offset by the absence in 2009 of cash proceedsapproximately $116 million from the sale of ~~telecommunication~~ assets, inpartially offset by $105 million relating to the ~~first quarter~~acquisition of ~~2008 combined with increased restricted funds to be used for future debt redemptions.~~customer intangible assets.

During the ~~last three months~~remaining two quarters of ~~2009,~~2010, capital requirements for property additions and capital leases are expected to be approximately ~~$410~~$918 million, including approximately ~~$65~~$155 million for nuclear fuel. ~~FirstEnergy has additional requirements of approximately $164 million for maturing long-term debt during the remainder of 2009.~~ These cash requirements are expected to be satisfied from a combination of internal cash and short-term credit ~~arrangements and funds raised in the capital markets.~~

arrangements.

FirstEnergy's capital spending for the period 2009-2013 is expected to be approximately $8.0 billion (excluding nuclear fuel), of which approximately $1.7 billion applies to 2009. Investments for additional nuclear fuel during the 2009-2013 period are estimated to be approximately $1.3 billion, of which about $295 million applies to 2009. During the same period, FirstEnergy's nuclear fuel investments are expected to be reduced by approximately $1.0 billion and $130 million, respectively, as the nuclear fuel is consumed.

GUARANTEES AND OTHER ASSURANCES

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

As of ~~September~~June 30, ~~2009,~~2010, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated ~~$4.1~~$3.9 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⁾	$	300
LOC (long-term debt) —Interest coverage⁽²⁾		6
FirstEnergy guarantee of OVEC obligations		300
Other⁽³⁾		294

		900


Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		54
LOC (long-term debt) —Interest coverage⁽²⁾		4
FES’ guarantee of NGC’s nuclear property insurance		70
FES’ guarantee of FGCO’s sale and leaseback obligations		2,413
Other		2

		2,543


Surety Bonds		90
LOC (long-term debt) — Interest coverage⁽²⁾		3
LOC (non-debt)⁽⁴⁾⁽⁵⁾		372

		465

Total Guarantees and Other Assurances	$	3,908

Maximum
Guarantees and Other Assurances

Exposure

(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts (1)
$ 385
LOC (long-term debt) – interest coverage (2)
6
FirstEnergy guarantee of OVEC obligations 300
Other (3)
296
987

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

Surety Bonds 103
LOC (long-term debt) – interest coverage (2)
4
LOC (non-debt) (4)(5)
398
505
Total Guarantees and Other Assurances $ 4,131


⁽¹⁾		Issued for open-ended terms, with a 10-day termination right by FirstEnergy.


⁽²⁾		Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of ~~$1.6~~ $1.3 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets.


⁽³⁾		Includes guarantees of $80 million for nuclear decommissioning funding ~~(see~~ ~~Nuclear Plant Matters below)~~ assurances, which has been reduced to $15 million in July 2010, and $161 million supporting OE’s sale and leaseback arrangement.


⁽⁴⁾		Includes ~~$58~~$193 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.


⁽⁵⁾		Includes approximately ~~$206~~$135 million pledged in connection with the sale and l ~~easeback~~leaseback of Beaver Valley Unit 2 by OE and ~~$134~~$44 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'~~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~~counterparty’s legal claim to be satisfied by ~~FirstEnergy~~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 ana LOC or accelerated payments may be required of the subsidiary. As of ~~September~~June 30, ~~2009,~~2010, FirstEnergy’s maximum exposure under these collateral provisions was ~~$616~~$451 million, as shown below:


Collateral Provisions	FES		Utilities		Total		FES		Utilities		Total
	(In millions)						*(In millions)*
Credit rating downgrade to below investment grade	$	305	$	115	$	420	$	314	$	17	$	331
Acceleration of payment or funding obligation		80		63		143		15		68		83
Material adverse event		53		-		53		37		—		37

Total	$	438	$	178	$	616	$	366	$	85	$	451

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 ~~$699~~$609 million, consisting of ~~$60~~$56 million due to “material adverse event” contractual clauses, $83 million due to an acceleration of payment or funding obligation, and ~~$639~~$470 million due to a below investment grade credit rating.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $90 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 ~~September~~June 30, ~~2009,~~2010, and forward prices as of that date, FES ~~had $183 million~~has posted collateral of ~~outstanding collateral payments.~~$245 million. Under a hypothetical adverse change in forward prices ~~(15% decrease~~(95% confidence level change in ~~the first 12 months and 20% decrease thereafter in prices)~~forward prices over a one year time horizon), FES would be required to post an additional ~~$45~~$107 million. Depending on the volume of forward contracts ~~entered~~ and future price movements, FES could be required to post ~~significantly~~ higher amounts for margining.

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

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~~$1.6 billion as of ~~September~~June 30, ~~2009.~~2010.

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

MARKET RISK INFORMATION

FirstEnergy uses various market risk sensitive instruments, including derivative contracts, primarily to manage the risk of price and interest rate fluctuations. ~~FirstEnergy's~~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. These non-trading contracts are adjusted to fair value at the end of each quarter, with a corresponding regulatory asset recognized for above-market costs or regulatory liability for below-market costs. The change in the fair value of commodity derivative contracts related to energy production during the three months and nine months ended September 30, 2009 are summarized in the following table:

~~100~~

Three Months Ended Nine Months Ended
September 30, 2009 September 30, 2009
Fair Value of Commodity Derivative Contracts
Non-Hedge Hedge Total Non-Hedge Hedge Total
(In millions)
Change in the Fair Value of
Commodity Derivative Contracts:
Outstanding net liability at beginning of period $ (515 ) $ (14 ) $ (529 ) $ (304 ) $ (41 ) $ (345 )
Additions/change in value of existing contracts (23 ) 13 (10 ) (404 ) 10 (394 )
Settled contracts 92 (5 ) 87 262 25 287
Outstanding net liability at end of period (1)
$ (446 ) $ (6 ) $ (452 ) $ (446 ) $ (6 ) $ (452 )

Non-commodity Net Liabilities at End of Period:
Interest rate swaps (2)
- (2 ) (2 ) - (2 ) (2 )
Net Liabilities - Derivative Contracts
at End of Period
$ (446 ) $ (8 ) $ (454 ) $ (446 ) $ (8 ) $ (454 )

Impact of Changes in Commodity Derivative
Contracts(3)

Income statement effects (pre-tax) $ (2 ) $ - $ (2 ) $ 2 $ - $ 2
Balance sheet effects:
Other comprehensive income (pre-tax) $ - $ 8 $ 8 $ - $ 35 $ 35
Regulatory assets (net) $ (71 ) $ - $ (71 ) $ 144 $ - $ 144

~~(1)~~

~~Includes $446 million in non-hedge commodity derivative contracts (primarily with NUGs) which are offset by a regulatory asset.~~

~~(2)~~

~~Interest rate swaps are treated as cash flow or fair value hedges.~~

~~(3)~~

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

~~Derivatives are included on the Consolidated Balance Sheet as of September 30, 2009 as follows:~~

Balance Sheet Classification
Non-Hedge Hedge Total
(In millions)
Current-

Other assets

$
-

$
13

$
13

Other liabilities

-

(18)

(18)

Non-Current-

Other deferred charges
239 - 239
Other non-current liabilities
(685) (3) (688)
Net liabilities

$
(446)
$
(8)
$
(454)

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 53 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of ~~September~~June 30, ~~2009~~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⁾	$	(5	)	$	—		$	—		$	—		$	—		$	—		$	(5	)
Other external sources⁽²⁾		(322	)		(332	)		(147	)		(34	)		4			(17	)		(848	)
Prices based on models		—			—			—			—			(9	)		138			129

Total⁽³⁾	$	(327	)	$	(332	)	$	(147	)	$	(34	)	$	(5	)	$	121		$	(724	)


⁽¹⁾		Represents exchange traded NYMEX futures and options.

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

⁽³⁾		Includes $547 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.

Source of Information
- Fair Value by Contract Year

2009(1)

2010

2011

2012

2013

Thereafter

Total

(In millions)
Prices actively quoted(2)
$ (2) $ (13 ) $ - $ - $ - $ - $ (15 )
Other external sources(3)
(64) (251 ) (209 ) (129 ) - - (653 )
Prices based on models
-

-

-

-

(1
)
217

216

Total
$
(66)

$
(264
)
$
(209
)
$
(129
)
$
(1
)
$
217

$
(452
)

~~(1)~~ ~~For the fourth quarter of 2009.~~

~~(2)~~ ~~Represents exchange traded NYMEX futures and options.~~

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

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. A hypothetical 10% adverse shift (an increase or decrease depending on the derivative position) in quoted market prices in the near term on its derivative instruments would not have had a material effect on its consolidated financial position (assets, liabilities and equity) or cash flows as of September 30, 2009. Based on derivative contracts held as of ~~September~~June 30, ~~2009,~~2010, an adverse 10% change in commodity prices would decrease net income by approximately $4$9 million ($6 million net of tax) during the next 12 months.

~~101~~

~~Forward Starting~~Interest Rate Swap Agreements ~~- Cash Flow~~— Fair Value Hedges

FirstEnergy uses ~~forward starting~~fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with ~~issuances of fixed-rate, long-term~~the debt ~~securities~~portfolio of its subsidiaries. These derivatives are treated as ~~cash flow~~fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in ~~future~~the fair value of fixed-rate debt instruments due to lower interest ~~payments resulting from changes in benchmark U.S. Treasury rates between the date~~rates. In May of ~~hedge inception and the date of the debt issuance. For the three months and nine months ended September 30, 2009,~~2010, FirstEnergy terminated ~~forward swaps~~fixed-for-floating interest rate swap agreements with a notional value of ~~$2.3~~$3.15 billion, ~~and $2.4 billion, respectively. FirstEnergy recognized losses~~which resulted in cash proceeds of ~~approximately $17 million and $18 million, respectively -- of which the ineffective portion recognized as an adjustment to interest expense was immaterial. The remaining effective portions~~$43.1 million. These proceeds will be amortized to ~~interest expense~~earnings over the life of the ~~hedged~~underlying debt.

Effective June 1, 2010, FirstEnergy executed multiple fixed-for-floating interest rate swap agreements with a combined notional value of $3.2 billion, which essentially replaced the swap agreements terminated in May of 2010. As of June 30, 2010, the debt underlying the $3.2 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 4%. A hypothetical 10% increase in the interest rates associated with variable-rate debt would decrease net income by less than $1 million for the three and six months ended June 30, 2010.

September 30, 2009 December 31, 2008
Notional Maturity Fair Notional Maturity Fair
Forward Starting Swaps
Amount Date Value Amount Date Value
(In millions)
Cash flow hedges $
100

2009
$ (1
)
$
100

2009
$
(2
)

100

2010
(1
)

100

2010

(2
)

-

2019
-
100

2019

1

$
200
$ (2
)
$
300
$
(3
)
On July 16, 2010, FirstEnergy terminated these fixed-for-floating interest rate swap agreements with a notional value of $3.2 billion, which resulted in cash proceeds of $83.6 million. These proceeds will be amortized to earnings over the life of the underlying debt. While FirstEnergy currently does not have any interest rate swaps outstanding, costs associated with entering into future swap transactions may be increased as a result of the recent passage of the Dodd-Frank Wall Street Reform and Consumer Protection Act, which requires increased regulation of swaps, swap dealers and major swap participants.

Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement ~~date. FirstEnergy’s other postretirement benefits plans were remeasured~~date or as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of plan participants. The remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009, including a $27 million reduction that is applicable to the first nine months of 2009 (see Note 6). In the third quarter of 2009, the Plan also incurred a $13 million net postretirement benefit cost (including amounts capitalized) related to an additional liability created by the VERO offered by FirstEnergy to qualified employees (see Note 6). On September 2, 2009, FirstEnergy elected to remeasure its qualified defined pension plan due to a $500 million voluntary contribution made by the Utilities and ATSI. The remeasurement and voluntary contribution decreased FirstEnergy’s accumulated other comprehensive income by approximately $494 million ($304 million, net of tax) in the third quarter of 2009 and will reduce FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009 by $7 million ($2 million is applicable to the third quarter of 2009) (see Note 6). Reductions in plan assets from investment losses during 2008 resulted in a decrease to the plans' funded status of $1.7 billion and an after-tax decrease to common stockholders' equity of $1.2 billion. For the first eight months of 2009, the actual plan asset investment results were 9.4% compared to (23.8%) for 2008.significant triggering events occur. As of ~~December 31, 2008,~~June 30, 2010, approximately 53% of the pension plan ~~was underfunded~~is invested in equity securities and ~~it remained underfunded after~~47% is invested in fixed income securities and the ~~voluntary contribution and remeasurement on August 31, 2009.~~plan is currently underfunded. A decline in the value of FirstEnergy’s pension plans could result in additional funding requirements. FirstEnergy currently estimates that additional cash contributions will be required beginning in ~~2014 for the 2013 plan year.~~2012. The overall actual investment result during 2009 was a gain of 13.6% compared to an assumed 9% positive return.

Nuclear decommissioning trust funds have been established to satisfy ~~NGC's~~NGC’s and the ~~Utilities'~~Utilities’ nuclear decommissioning obligations. As of ~~September~~June 30, ~~2009,~~2010, approximately 15% of the funds were invested in equity securities and ~~85%~~ 85%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 ~~$278~~$275 million as of ~~September~~June 30, ~~2009.~~2010. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of ~~September~~June 30, ~~2009.~~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 ~~based on the guidance for~~as other-than-temporary impairments. ~~On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed~~A decline in the value of FirstEnergy’s nuclear decommissioning trusts could result in additional funding requirements. As of June 30, 2010, $4 million was contributed to the OE and TE nuclear decommissioning trusts to comply with requirements under certain sale-leaseback transactions in which OE and TE continue as lessees, and $3 million was contributed to the JCP&L and Pennsylvania nuclear decommissioning trusts to comply with regulatory requirements. FirstEnergy continues to evaluate the status of its funding obligations for the decommissioning ~~trust fund for Beaver Valley Unit 1.~~ ~~On November 5, 2009,~~of these nuclear facilities and does not expect to make additional cash contributions to the ~~NRC issued a renewed operating license for Beaver Valley Power Station, Units 1 and 2. The operating licenses for these facilities were extended until 2036 and 2047 for Units 1 and 2, respectively.~~ ~~Renewal of the operating license for Beaver Valley Unit 1 (see Nuclear Plant Matters) is expected to mitigate the estimated shortfall in the unit’s~~ nuclear decommissioning ~~funding status. FENOC will continue to work with the NRC Staff as it completes its review of the license renewal application, and expects to obtain renewed licenses~~trusts for the ~~Beaver Valley Power Station in 2009. FENOC continues~~remainder of 2010 other than those to ~~communicate with~~ the ~~NRC regarding future actions~~JCP&L and Pennsylvania Companies’ nuclear decommissioning trusts due to ~~provide reasonable assurance for decommissioning funding. Such actions may include additional parental guarantees or contributions to those funds.~~

regulatory requirements.

~~102~~

CREDIT RISK

Credit risk is the risk of an ~~obligor's~~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. ~~We engage~~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.

~~We maintain~~FirstEnergy maintains credit policies with respect to ~~our~~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 ~~our~~its credit program, weFirstEnergy aggressively ~~manage~~manages the quality of ~~our~~its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of ~~September~~June 30, ~~2009,~~2010, the largest credit concentration was with ~~JP Morgan,~~AEP, which is currently rated investment grade, representing ~~10.7%~~7.85% of ~~our~~FirstEnergy’s total approved credit risk.

OUTLOOK

State Regulatory Matters

~~In Ohio, New Jersey~~FirstEnergy and ~~Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected~~the utilities prepare their consolidated financial statements in accordance with the ~~Utilities' respective state regulatory plans. These provisions include:~~

·	~~restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities;~~

·	~~establishing or defining the PLR obligations to customers in the Utilities' service areas;~~

·	~~providing the Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;~~

·	~~itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;~~

·	~~continuing regulation of the Utilities' transmission and distribution systems; and~~

·	~~requiring corporate separation of regulated and unregulated business activities.~~

~~The Utilities and ATSI recognize, as~~authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred or accrued costs ~~which the FERC, the PUCO, the PPUC and the NJBPU~~that have ~~authorized for~~been deferred because of their probable future recovery from customers inthrough regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future ~~periods or for which authorization is probable. Without~~regulated rates. The following table provides the ~~probability~~balance of ~~such authorization, costs currently recorded as~~ regulatory assets ~~would have been charged to income~~by Company as ~~incurred.~~ of June 30, 2010 and December 31, 2009, and changes during the six months then ended:


	June 30,		December 31,		Increase
Regulatory Assets	2010		2009		(Decrease)
	*(In millions)*
OE	$	423	$	465	$	(42	)
CEI		468		546		(78	)
TE		82		70		12
JCP&L		801		888		(87	)
Met-Ed		385		357		28
Penelec		139		9		130
Other		15		21		(6	)

Total	$	2,313	$	2,356	$	(43	)

The following table provides information about the composition of regulatory assets as of June 30, 2010 and December 31, 2009 and the changes during the six months then ended:


	June 30,			December 31,			Increase
Regulatory Assets by Source	2010			2009			(Decrease)
	*(In millions)*
Regulatory transition costs	$	1,153		$	1,100		$	53
Customer shopping incentives		74			154			(80	)
Customer receivables for future income taxes		332			329			3
Loss on reacquired debt		49			51			(2	)
Employee postretirement benefits		19			23			(4	)
Nuclear decommissioning, decontamination and spent fuel disposal costs		(152	)		(162	)		10
Asset removal costs		(235	)		(231	)		(4	)
MISO/PJM transmission costs		156			148			8
Fuel costs		385			369			16
Distribution costs		408			482			(74	)
Other		124			93			31

Total	$	2,313		$	2,356		$	(43	)

Regulatory assets that do not earn a current return totaled approximately ~~$172~~$181 million as of ~~September~~June 30, ~~2009~~2010 (JCP&L ~~- $42~~— $43 million, Met-Ed ~~- $102~~— $131 million, Penelec — $3 million and ~~Penelec - $28~~CEI $4 million). Regulatory assets not earning a current return (primarily for certain regulatory transition costs and employee postretirement benefits) are expected to be recovered by 2014 for JCP&L and by 2020 for Met-Ed and Penelec. ~~The following table discloses net regulatory assets by company:~~

September 30, December 31, Increase
Regulatory Assets 2009 2008 (Decrease)
(In millions)
OE $ 494 $ 575 $ (81 )
CEI 592 784 (192 )
TE 77 109 (32 )
JCP&L 950 1,228 (278 )
Met-Ed 404 413 (9 )
Penelec* 3 - 3
ATSI
23

31

(8
)
Total
$
2,543

$
3,140

$
(597
)

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

~~103~~

~~Regulatory assets by source are as follows:~~

September 30, December 31, Increase
Regulatory Assets By Source 2009 2008 (Decrease)
(In millions)
Regulatory transition costs $ 1,142 $ 1,452 $ (310 )
Customer shopping incentives 192 420 (228 )
Customer receivables for future income taxes 339 245 94
Loss on reacquired debt 51 51 -
Employee postretirement benefits 25 31 (6 )
Nuclear decommissioning, decontamination
and spent fuel disposal costs (152 ) (57 ) (95 )
Asset removal costs (228 ) (215 ) (13 )
MISO/PJM transmission costs 207 389 (182 )
Purchased power costs 356 214 142
Distribution costs 525 475 50
Other
86

135

(49
)
Total
$
2,543

$
3,140

$
(597
)

Reliability Initiatives

Ohio

The Ohio Companies operate under an Amended ESP, which expires on ~~the data submittals or interview results.~~

~~104~~

~~Ohio~~

~~105~~

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~~through a CBP, ~~to secure~~ generation supply for customers who do not shop with an alternative supplier ~~and~~for the period beginning June 1, 2011. The CBP 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 ~~reduce~~and supplier risk and encourage bidder participation. A technical conference ~~was~~and hearings were held ~~on October 29,~~in 2009 atand the ~~PUCO.~~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, therefore,~~requirements. Although the Ohio Companies ~~have~~ requested a PUCO determination by January 18, ~~2010.~~2010, on February 3, 2010, the PUCO announced that its determination would be delayed. Under a determination that such statutory requirements ~~were~~are met, and to the extent the ESP described below has not been implemented, the Ohio Companies would ~~be able~~expect to implement the MRO.

Ohio Companies’ alternative energy requirements as set forth in SB221. RFP bids are due August 3, 2010 and contracts are expected to be signed the week of August 9, 2010.

~~Pennsylvania~~On February 12, 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. On March 3, 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect on March 17, 2010. On April 15, 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that the new credit would remain in place through at least the 2011 winter season, and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect on May 21, 2010. The Ohio Companies also filed on May 14, 2010 an application for rehearing of the Second Entry on Rehearing, which was granted for purposes of further consideration on June 9, 2010. No hearing has been scheduled in this matter.

Pennsylvania

~~106~~

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

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

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

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

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

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

Act 129 requires utilities to file with the PPUC an energy efficiency and peak load reduction plan by July 1, 2009. On January 15, 2009, in compliance with Act 129, the PPUC issued its proposed guidelines for the filing of utilities’ energy efficiency and peak load reduction plans. On 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 an evidentiary hearing and briefing, the Companies filed revised EE&C Plans on September 21, 2009. In an Order entered October 28, 2009, the PPUC approved in part, and rejected in part, the Pennsylvania Companies’ filing. The Companies must file revised – EE&C plans by December 28, 2009, incorporating minor revisions required by the PPUC. These revisions are not expected to impose any additional financial obligations on the Pennsylvania Companies.

~~107~~

On April 1, 2010, Met-Ed and Penelec filed a Petition for Review with the ~~July 30, 2009 order,~~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 ~~increasing~~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 ~~in compliance~~increases commencing January 1, 2011, and the PPUC entered an Order on June 7, 2010, granting Met-Ed’s and Penelec’s request. On July 9 2010, Met-Ed and Penelec filed their briefs with the ~~companies’ Restructuring Orders~~Commonwealth Court of ~~1998.~~ Pennsylvania. The Office of Small Business Advocate filed its brief on July 9, 2010. The PPUC’s brief is due to be filed in August 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 ~~September~~June 30, ~~2009,~~2010, the accumulated deferred cost balance totaled approximately ~~$102~~$81 million. To better align the recovery of expected costs, on July 26, 2010, JCP&L filed a request to decrease the amount recovered for the costs incurred under the NUG agreements by $180 million annually. If approved as filed, the change would not go into effect until January 1, 2011.

~~108~~

~~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.~~

FERC Matters

~~Transmission Service between MISO and PJM~~

PJM Transmission Rate

~~109~~

The FERC’s April 19, 2007 ~~order. On January 31, 2008, the requests for rehearing were denied. On February 11, 2008, AEP~~order was appealed the FERC’s April 19, 2007, and January 31, 2008, orders to the federal Court of Appeals for the D.C. Circuit. The Illinois Commerce Commission, the PUCO and Dayton Power & Light have also appealed these orders to the Seventh Circuit Court of Appeals. The appeals of these parties and others have been consolidated for argument in the Seventh Circuit. Oral arguments were held on April 13, 2009. The Seventh Circuit Court of Appeals issued a decision on August 6, 2009, that remanded the rate design to FERC and denied AEP’s appeal. A request for rehearing and rehearing en banc by Baltimore Gas & Electric and Old Dominion electric Cooperative was denied by the Seventh Circuit on October 20, 2009.

~~Post Transition Period Rate Design~~

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 ~~Appeals has held this appeal~~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 ~~abeyance pending resolution~~response to the FERC order. PJM’s filing demonstrated that allocation of the ~~Order 494 appeal discussed above.~~cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of their costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. FERC is not expected to act before the fourth quarter of 2010.

RTO Consolidation

~~110~~

meet PJM’s capacity requirements. FirstEnergy ~~has requested that FERC rule on its application by December 17, 2009, to provide time to permit management to make a decision on whether~~expects to integrate ~~ATSI~~ into PJM ~~prior to the 2010 Base Residual Auction for capacity. Subject to a satisfactory FERC ruling, the integration is expected to be complete on~~effective June 1, ~~2011, to coincide with delivery of power under the next competitive generation procurement process for FirstEnergy's Ohio companies.~~

2011.

On September 4, 2009, the PUCO opened a case to take comments from ~~Ohio~~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 hearing on September 15, 2009 to respond to questions regarding the RTO consolidation.

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

In addition, on April 12, 2010, PJM filed a complaint ~~at the~~with FERC ~~against PJM~~pursuant to Section 206, 306, and 309 alleging that ~~three~~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 ~~four transitional RPM auctions yielded prices that are unjust~~RTOs and ~~unreasonable under the Federal Power Act.~~ 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.

On ~~September 19, 2008, the~~June 29, 2010, FERC denied the RPM Buyers’ complaint. The FERC also ordered PJM to file on or before December 15, 2008, a report on potential adjustments to the RPM program as suggested in a Brattle Group report. On December 12, 2008, PJM filed proposed tariff amendments that would adjust slightly the RPM program. PJM also requested that the FERC conduct a settlement hearing to address changes to the RPM and suggested that the FERC should rule on the tariff amendments only if settlement could not be reached in January, 2009. The request for settlement hearings was granted. Settlement had not been reached by January 9, 2009 and, accordingly, FirstEnergy and other parties submitted comments on PJM’s proposed tariff amendments. On January 15, 2009, the Chief Judge issued an order ~~terminating~~consolidating the cases and establishing settlement ~~discussions. On February 9, 2009, PJM and a group~~judge procedures. If the settlement process is unsuccessful, the cases will proceed to evidentiary hearings. FirstEnergy is unable to predict the outcome 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.this matter.

MISO Multi-Value Project Rule Proposal

On ~~March 26, 2009,~~July 15, 2010, MISO and certain MISO transmission owners jointly filed with the FERC ~~accepted in~~their proposed cost allocation methodology for new transmission projects. If approved, so-called Multi Value Projects (MVPs) — transmission projects that have a regional impact and are part ~~and rejected in part, tariff provisions submitted~~of a regional plan — will have a 100% regional allocation of costs under the proposed methodology. If approved by ~~PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements~~FERC, MISO’s proposal is expected to ~~RPM; clarification on certain aspects~~permit the allocation of the ~~March 26, 2009 Order. On April 27, 2009, PJM submitted~~costs of large transmission projects designed to integrate wind from the upper Midwest across the entire MISO. MISO has requested a ~~compliance filing addressing the changes the~~ FERC ordered in the March 26, 2009 Order; and subsequently, numerous parties filed requests for rehearing of the March 26, 2009 Order. On June 18, 2009, the FERC denied rehearing and request for oral argument of the March 26, 2009 Order.

PJM has reconvened the Capacity Market Evolution Committee (CMEC) and has scheduled a CMEC Long-Term Issues Symposium to address near-term changes directed by the March 26, 2009 Order and other long-term issues not addressed in the February 2009 settlement. PJM made a compliance filing on September 1, 2009, incorporating tariff changes directed by the March 26, 2009 Order. The tariff changes, which provide for incremental improvements to the RPM, will be effective November 1, 2009, pending FERC approval. In addition, the CMEC continues to work to address additional compliance items directed by the March 26, 2009 Order. Another compliance filing is due December 1, 2009.

~~MISO Resource Adequacy Proposal~~

MISO made a filing on December 28, 2007 that would create an enforceable planning reserve requirement in the MISO tariff for load-serving entities such as the Ohio Companies, Penn and FES. This requirement was proposed to become effective for the planning year beginning June 1, 2009. The filing would permit MISO to establish the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

~~111~~

~~FES Sales to Affiliates~~

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount2011 effective date of ~~capacity resources required~~FirstEnergy’s integration into PJM would continue to be ~~supplied by FES~~allocated to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. ~~FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load.~~ FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.FirstEnergy.

Environmental Matters

CAA Compliance

~~Clean Air Act Compliance~~

~~112~~

~~On May 22,~~In 2007, ~~FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of~~PennFuture filed a citizen suit under the ~~federal~~ CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members,limitations, in the ~~United States~~U.S. District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the ~~United States~~U.S. District Court for the Western District of Pennsylvania also seeking damages based on Bruce Mansfield Plant air emissions. ~~In addition to seeking damages, two~~Two of ~~the three~~these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. ~~On October 14, 2008, the Court granted FGCO’s motion to consolidate discovery for all four complaints pending against the Bruce Mansfield Plant. On August 17, 2009, a~~A settlement ~~of the PennFuture complaint~~ was reached with ~~PennFuture and one of the three individual complaintants. On October 16, 2009, the Court approved the settlement and dismissed~~PennFuture. FGCO believes the claims of ~~PennFuture and of~~ the ~~settling individual complaintant. The other two non-settling complaintants are now represented by counsel handling the three cases filed in July 2008. FGCO believes those claims~~remaining plaintiffs are without merit and intends to defend itself against the allegations made in those three complaints.

~~113~~

On May 16, 2008, FGCO received a request from the EPA for information pursuant to Section 114(a) of the CAA for certain operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants to allow the EPA to determine whether these generating sources are complying with the NSR provisions of the CAA. On July 10, 2008, FGCO and the EPA entered into an Administrative Consent Order modifying that request and setting forth a schedule for FGCO’s response. On October 27, 2008, FGCO received a second request from the EPA for information pursuant to Section 114(a) of the CAA for additional operating and maintenance information regarding the Eastlake, Lakeshore, Bay Shore and Ashtabula generating plants. OnIn August ~~12,~~ 2009, the EPA issued a Finding of Violation and NOV alleging violations of the ~~Clean Air Act~~CAA and Ohio regulations, including the ~~prevention of significant deterioration (“PSD”), non-attainment new source review (NNSR”),~~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. ~~On September 15, 2009,~~ FGCO received ~~an additional information~~a request ~~pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit~~for certain operating and maintenance information and planning information ~~regarding the Eastlake, Lake Shore, Bay Shore~~for these same generating plants 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 ~~provisions~~provision of the CAA. Later in 2009, FGCO received another information request regarding emission projections for the Eastlake generating plant. FGCO intends to comply with the CAA, including the EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. ~~A June 15, 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.~~

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.The EPA’s CAIR requires reductions of NO_X and SO₂ emissions in two phases ~~(Phase I in 2009 for NO~~X, (2009/2010 ~~for SO~~2and ~~Phase II in 2015 for both NO~~X ~~and SO~~2)2015), ultimately capping SO₂ emissions in affected states to 2.5 million tons annually and NO_X emissions to 1.3 million tons annually. ~~CAIR was challenged in~~In 2008, the ~~United States~~U.S. Court of Appeals for the District of Columbia ~~and on July 11, 2008, the Court~~ vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” ~~On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On~~In December ~~23,~~ 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s ~~July 11, 2008~~ opinion. ~~On July 10, 2009, the United States~~The Court ~~of Appeals for the District of Columbia~~ ruled in a different case that a cap-and-trade program similar to CAIR, called the “NO_X SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the ~~"8-hour"~~“8-hour” ozone NAAQS. ~~FGCO's~~In July 2010, the EPA proposed the Clean Air Transport Rule (CATR) to replace CAIR, which remains in effect until the EPA finalizes CATR. CATR requires reductions of NO_X and SO₂ emissions in two phases (2012 and 2014), ultimately capping SO₂ emissions in affected states to 2.6 million tons annually and NO_X emissions to 1.3 million tons annually. The EPA proposed a preferred regulatory approach that allows trading of NO_X and SO₂ emission allowances between power plants located in the same state with severe limits on interstate trading and two alternative approaches—the first eliminates interstate trading of NO_X and SO₂ emission allowances and the second eliminates trading of NO_X and SO₂ emission allowances in its entirety. Depending on the actions taken by the EPA with respect to CATR, the proposed MACT regulations discussed below, and any future regulations that are ultimately implemented, FGCO’s future cost of compliance ~~with these regulations~~ may be ~~substantial~~substantial. Management is currently assessing the impact of these environmental proposals and ~~will depend, in part,~~other factors on FCGO’s facilities, particularly on the ~~action taken by the EPA in response~~operation of its smaller, non-supercritical units. For example, management may decide to ~~the Court’s ruling.~~idle certain of these units or operate them on a seasonal basis until developments clarify.

Hazardous Air Pollutant Emissions

~~114~~

~~Mercury Emissions~~

implemented, FGCO’s future cost of compliance with MACT regulations may be substantial and changes to FGCO’s operations may result.

Climate Change

~~On April 2, 2007, the United States Supreme Court found that the~~The EPA has ~~the authority to regulate CO~~2 ~~emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO~~2 ~~emissions from electric generating plants, the EPA has similar~~ authority under the CAA to regulate “air pollutants” from ~~those~~electric generating plants and other facilities. ~~On April 17,~~In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. In December 2009, the EPA released ~~a “Proposed Endangerment~~its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s ~~proposed~~ finding concludes that ~~the atmospheric~~ concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence toGHG increase the threat of climate change. ~~Although~~In April 2010, the ~~EPA’s proposed finding, if~~EPA finalized ~~does~~new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA will not ~~establish emission requirements~~be triggered for ~~motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including~~ electric generating plants ~~those findings, if finalized, would be expected to support~~and other stationary sources until January 2, 2011, at the ~~establishment of future emission requirements by~~earliest. In May 2010, the EPA ~~for stationary sources, . On September 23, 2009, the EPA~~ finalized a GHG reporting rule establishing a national GHG emissions collection and reporting program. The EPA rules will require FirstEnergy to measure GHG emissions commencing in 2010 and submit reports commencing in 2011. On September 30, 2009, EPA proposed new thresholds for GHG emissions that define when ~~Clean Air Act~~ permits under the ~~New Source Review and Title V operating permits programs~~CAA program would be required. The EPA ~~is proposing a major source~~established an emissions applicability threshold of ~~25,000~~75,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) effective January 2, 2011 for existing facilities under the ~~Title V operating permits program and the~~CAA’s Prevention of Significant Determination (PSD) ~~portion~~program, but until July 1, 2011 that emissions applicability threshold will only apply if PSD is triggered by non-carbon dioxide pollutants.

~~115~~

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

~~On September 7, 2004, the~~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~~facility’s cooling water system). ~~On January 26, 2007,~~The EPA has taken the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, notingposition 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 ~~of the United States~~ reversed one significant aspect of the Second ~~Circuit Court’s~~Circuit’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 ~~will now take up consideration~~is developing a new regulation under Section 316(b) of the ~~rule on remand and take further action~~Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals including whether to exercise its discretion to retain or modify the cost-benefit rule as it appeared in the initial regulation. It is expected that the EPA will issue a proposed rule on remand in 2010. The Courts’ opinionswhich have created significant uncertainty about the specific nature, scope and timing of the final ~~compliance requirements .FirstEnergy~~performance standard. FirstEnergy is studying various control options and their costs and ~~effectiveness.~~effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. On March 15, 2010, the EPA issued a draft permit for the Bay Shore power plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

Regulation of Waste Disposal

~~116~~

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 ~~September~~June 30, ~~2009,~~2010, based on estimates of the total costs of cleanup, the ~~Utilities'~~Utilities’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately ~~$104~~$105 million (JCP&L ~~- - $77~~— $76 million, TE -— $1 million, CEI -— $1 million, FGCO -— $1 million and FirstEnergy ~~- $24~~— $26 million) have been accrued through ~~September~~June 30, ~~2009.~~2010. Included in the total are accrued liabilities of approximately ~~$68~~$67 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation

After various motions, rulings and appeals, the ~~Plaintiffs'~~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)~~Early in 2010, the Appellate Division ~~limited the class only to those customers directly impacted by the outages of JCP&L transformers in Red Bank, NJ, based~~heard oral argument 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 theirplaintiff’s appeal of the trial ~~court's~~court’s decision decertifying the ~~class. JCP&L is now waiting for~~class, and on July 29, 2010, the Appellate Division upheld the trial court’s decision.

Litigation Relating to ~~schedule~~ the ~~appeal~~Proposed Allegheny Energy Merger

In connection with the proposed merger (Note 15), 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. In summary, 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 complaints seek, among other things, jury trials, money damages and injunctive relief. Additional details about the actions are provided below. While FirstEnergy believes the lawsuits are without merit and has defended vigorously against the claims, in order to avoid the costs associated with the litigation, the defendants have agreed to the terms of a disclosure-based settlement of the lawsuits. The defendants reached an agreement with counsel for all of the plaintiffs concerning fee applications, but a formal stipulation of settlement has not yet been filed with any court. If the parties are unable to obtain final approval of the settlement, then litigation will proceed, and 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. 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.

Four putative class action and derivative lawsuits were filed in the Circuit Court for Baltimore City, Maryland. One was withdrawn. The court consolidated the three cases under the captionOakmont Capital Management, LLC v. Evanson, et al., C.A. No. 24-C-10-1301, and appointed Lewis M. Lynn as Lead Plaintiff. Plaintiff Lynn filed a Consolidated Amended Complaint on April 12, 2010. On April 21, 2010, defendants filed Motions to Dismiss the Consolidated Amended Complaint for failure to state a claim. The court has stayed all discovery pending resolution of those motions. The court also has entered a stipulated order certifying a class with no opt-out rights. On May 27, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement and requested that the court cancel the oral ~~arguments.~~argument on the motions to dismiss that had been scheduled for June 3, 2010. On May 28, 2010, the court removed the hearing from its calendar.

100

Three shareholder lawsuits were filed in the Court of Common Pleas of Westmoreland County, Pennsylvania, raising putative class action and derivative claims against the Allegheny Energy directors and officers, FirstEnergy and Allegheny Energy. The court has consolidated these actions under the caption,In re Allegheny Energy, Inc. Shareholder Class and Derivative, Litigation, Lead Case No. 1101 of 2010, and appointed lead counsel. On April 5, 2010, the Allegheny Energy defendants filed a Motion to Stay the Proceedings. Shortly thereafter, FirstEnergy similarly filed a Motion to Stay. Plaintiffs filed a Motion for Expedited Discovery. The court scheduled a hearing on the motions for May 27, 2010. On May 21, 2010, plaintiffs filed a Verified Consolidated Shareholder Derivative and Class Complaint. On May 26, 2010, the parties filed a Motion for a Continuance of the May 27 hearing, which the court granted. On June 1, 2010, the parties reported to the court that they have agreed to the terms of a disclosure-based settlement.

Nuclear Plant Matters

UCS request, have not been determined.

~~117~~

Other Legal Matters

101

defend these claims including challenging any class certification.

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

~~In June 2009, the FASB amended the derecognition guidance in the Transfers and Servicing Topic~~See Note 10 of the FASB Accounting Standards Codification and eliminates the concept of a QSPE. It requires an evaluation of all existing QSPEs to determine whether they must be consolidated. This standard is effective for financial asset transfers that occur in fiscal years beginning after November 15, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.

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

102

In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance to determine fair value when a quoted price in an active market for an identical liability is not available. In such instances, an entity should measure fair value using one of the following approaches; (i) the quoted price of an identical liability when traded as an asset; (ii) the quoted price of a similar liability or a similar liability traded as an asset; (iii) a technique based on the amount an entity would pay to transfer the identical liability; or (iv) a technique based on the amount an entity would receive to enter into an identical liability. This standard is effective for fiscal years beginning October 1, 2009. FirstEnergy does not expect this standard to have a material effect upon its financial statements.

~~118~~

FIRSTENERGY SOLUTIONS CORP.

~~MANAGEMENT'S~~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~~FirstEnergy’s fossil and hydroelectric generation facilities, and owns ~~FirstEnergy's~~FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

~~FES'~~FES’ revenues ~~have been primarily~~are derived from sales to individual retail customers, sales to communities in the form of government aggregation programs, the sale of electricity ~~(provided from FES' generating facilities~~to Met-Ed and ~~through purchased power arrangements) to affiliated utility companies~~Penelec to meet all ~~or a portion~~ of their ~~PLR~~POLR and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond. On November 3, 2009, FES, Met-Ed, Penelec and Waverly restated their partial requirements power purchase agreement for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and ~~managing congestion expenses.~~ ~~FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load.~~ ~~FES is responsible for obtaining additional power supplies~~its participation in ~~the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77~~affiliated and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010. FES also supplied, through May 31, 2009, a portion of Penn's default service requirements at market-based rates as a result of Penn's 2008 competitive solicitations. FES'non-affiliated POLR auctions. FES’ revenues also include ~~competitive retail and wholesale~~ sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan, Illinois and ~~Illinois. These sales may provide a greater portion of revenues in future years depending upon FES' participation in its Ohio and Pennsylvania utility affiliates' power procurement arrangements.~~

Maryland.

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 in FirstEnergy’s service territories. The current recessionary economic conditions, particularly in the automotive and steel industries, compounded by unusually mild regional summertime temperatures, have adversely affected FES’ operations and revenues.

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

conditions.

For additional information with respect to FES, please see the information contained in FirstEnergy's Management 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 and Outlook.

~~Results of Operations~~

In the first nine months of 2009, net income increased to $668 million from $344 million in the same period in 2008. The increase in net income includes FGCO’s $252 million pre-tax gain from the sale of 9% of its participation in OVEC ($158 million after-tax), an increase in investment income of $142 million resulting primarily from the sale of securities held in the nuclear decommissioning trusts and an increase in gross sales margins.

~~Revenues~~

Revenues increased by $260 million in the first nine months of 2009 compared to the same period in 2008 primarily due to the OVEC sale and increase in revenues from non-affiliated and affiliated wholesale sales, partially offset by lower retail generation sales. The increase in revenues resulted from the following sources:

~~119~~

Nine Months Ended
September 30 Increase
Revenues by Type of Service 2009 2008 (Decrease)
(In millions)
Non-Affiliated Generation Sales:

Retail

$
406

$
485

$
(79
)
Wholesale

523

509

14

Total Non-Affiliated Generation Sales

929

994

(65
)
Affiliated Generation Sales

2,349

2,266

83

Transmission

57

113

(56
)
Sale of OVEC participation interest

252

-

252

Other

85

39

46

Total Revenues

$
3,672

$
3,412

$
260

The lower retail revenues resulted from the expiration of government aggregation programs in Ohio at the end of 2008 that were supplied by FES, partially offset by increased revenue in both the PJM and MISO markets. The increase in MISO retail sales is primarily the result of the acquisition of new customers and higher unit prices. The increase in PJM retail sales resulted from the acquisition of new customers, higher sales volumes and unit prices. FES has signed new government aggregation contracts with 50 communities in Ohio that will provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from higher capacity prices in PJM offset by decreased spot market prices in PJM and increased sales volumes and favorable settlements on hedged transactions in MISO, offset by decreased sales volumes in PJM.

The increased affiliated company generation revenues were due to higher unit prices to the Ohio Companies and increased sales volumes to Met-Ed and Penelec, partially offset by lower sales volumes to the Ohio Companies. The higher unit prices reflected the results of the Ohio Companies' power procurement processes in the first half of 2009 (see Regulatory Matters – Ohio). The higher sales to the Pennsylvania Companies were due to increased Met-Ed and Penelec generation sales requirements supplied by FES, partially offset by lower sales to Penn due to decreased default service requirements in the first nine months of 2009 compared to the first nine months of 2008.

In the first quarter of 2009, FES supplied approximately 75% of the Ohio Companies’ power requirements as one of four winning bidders in the Ohio Companies' RFP process. In the second quarter of 2009, FES supplied 100% of the power for the Ohio Companies’ PLR service in April and May 2009, and approximately 56% of the Ohio Companies' supply needs beginning in June 2009. Subsequent to the Ohio Companies’ CBP, FES purchased additional tranches from other winning bidders and as of September 1, 2009, FES supplied 72% of the Ohio Companies’ PLR generation requirements.

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

Increase
Source of Change in Affiliated Generation Revenues

(Decrease)

(In millions)
Ohio Companies:
Effect of 28.9% decrease in sales volumes
$ (508 )
Change in prices

557

49

Pennsylvania Companies:
Effect of 11.1% increase in sales volumes
57
Change in prices

(23
)

34

Net Increase in Affiliated Generation Revenues
$
83

~~120~~

~~Transmission revenues decreased $56 million due primarily to reduced loads in MISO following the expiration of the government aggregation programs in Ohio at the end of 2008.~~ ~~Other revenue increased $46 million primarily due to rental income associated with NGC's acquisition of additional equity interests in Perry and Beaver Valley Unit 2.~~

~~Expenses~~

Total expenses decreased by $82 million in the first nine months of 2009 compared with the same period of 2008. The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2009 from the same period last year:

Source of Change in Fuel and Purchased Power

Increase
(Decrease)

(In millions)
Fossil Fuel:
Change due to increased unit costs
$ 112
Change due to volume consumed
(230 )
(118 )
Nuclear Fuel:
Change due to increased unit costs
14
Change due to volume consumed
(7 )
7
Non-affiliated Purchased Power:
Change due to increased unit costs
73
Change due to volume purchased
(170 )
(97 )
Affiliated Purchased Power:
Change due to increased unit costs
71
Change due to volume purchased
2
73
Net Decrease in Fuel and Purchased Power Costs
$
(135
)

Fossil fuel costs decreased $118 million in the first nine months of 2009 as a result of decreased coal consumption, reflecting lower generation. Higher unit prices, which are expected to continue during the remainder of 2009, were due to increased fuel costs associated with purchases of eastern coal. Nuclear fuel costs increased slightly due to increased unit prices in the first nine months of 2009 compared to the same period of 2008.

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

Other operating expenses increased by $28 million in the first nine months of 2009 from the same period of 2008. Higher expenses in the 2009 period relate to increased transmission expenses ($64 million) due to increased net congestion charges in PJM and higher transmission loss expenses in MISO and PJM combined with increased other expenses ($14 million) relating to increased intersegment billings for leasehold costs from the Ohio Companies and higher pension expense. These increases were partially offset by lower fossil operating costs ($46 million) and nuclear operating costs ($4 million). Decreased fossil operating costs were primarily due to a reduction in contractor and material costs and more labor dedicated to capital projects compared to the prior year.

~~Depreciation expense increased by $22 million in the first nine months of 2009 primarily due to NGC’s increased ownership interest in Beaver Valley Unit 2 and Perry.~~

~~Other Expense~~

Total other expense in the first nine months of 2009 was $156 million lower than the first nine months of 2008, primarily due to a $137 million increase in earnings from nuclear decommissioning trust investments and a decline in interest expense (net of capitalized interest) of $21 million primarily due to the repayment of notes payable to affiliates.

~~121~~

~~OHIO EDISON COMPANY~~

~~MANAGEMENT'S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

OE is a wholly owned electric utility subsidiary of FirstEnergy. OE and its wholly owned subsidiary, Penn, conduct business in portions of Ohio and Pennsylvania, providing regulated electric distribution services. They provide generation services to those franchise customers electing to retain OE and Penn as their power supplier. Until December 31, 2008, OE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that reflected the rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

~~For additional information with respect to OE, please see the information contained in FirstEnergy's Management~~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 ~~Outlook.~~New Accounting Standards and Interpretations.

Results of Operations

InNet income decreased by $254 million in the first ~~nine~~six months of ~~2009, net income decreased~~2010, compared to ~~$80 million from $166 million in~~ the same period of ~~2008.~~2009. The decrease ~~primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009.~~

~~Revenues~~

Revenues increased by $59 million, or 3.0%, in the first nine months of 2009 compared with the same period in 2008, primarily due to increases in retail generation revenues ($204 million) and wholesale revenues ($80 million), partially offset by decreases in distribution throughput revenues ($203 million) and other miscellaneous revenues ($22 million).

~~Retail generation revenues increased~~was primarily due to higher ~~average prices across all customer classes~~purchased power costs, the absence of a $252 million ($158 million after tax) gain in 2009 from the sale of a 9% participation interest in OVEC and increased ~~KWH sales~~fuel and interest expense, partially offset by higher revenues and investment income.

Revenues

Total revenues, excluding the OVEC sale, increased $388 million in the first six months of 2010, compared to ~~residential and commercial customers, reflecting a decrease in customer shopping in those sectors as most~~the same period of ~~OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s service territory. Average prices increased~~2009 primarily due to an increase in ~~OE's fuel cost recovery rider~~direct and government aggregation sales volumes and sales of RECs, partially offset by decreases in POLR sales to the Ohio Companies and wholesale sales.

The increase in revenues resulted from the following sources:


	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2010		2009		(Decrease)
	*(In millions)*
Direct and Government Aggregation	$	1,097	$	174	$	923
POLR		1,260		1,732		(472	)
Wholesale		186		311		(125	)
Transmission		36		41		(5	)
RECs		67		—		67
Sale of OVEC participation interest		—		252		(252	)
Other		57		57		—

Total Revenues	$	2,703	$	2,567	$	136

The increase in direct and government aggregation revenues of $923 million resulted from increased revenue in both the MISO and PJM markets. The increase in revenue primarily resulted from the acquisition of new commercial and industrial customers, as well as new government aggregation contracts with communities in Ohio that provide generation to approximately 1.1 million residential and small commercial customers at the end of June 2010 compared to approximately 21,000 at the end of June 2009, partially offset by lower unit prices. During January 2010, FES began supplying power to approximately 425,000 NOPEC customers.

103

The decrease in POLR revenues of $472 million was ~~effective~~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 2010 reflected the results of the May 2009 power procurement process. The increased revenues to the Pennsylvania Companies resulted from ~~January~~FES supplying Met-Ed and Penelec with volumes previously supplied through ~~May~~a third-party contract at prices that were slightly higher than in 2009. ~~Effective June 1, 2009,~~

Wholesale revenues decreased $125 million due to reduced volumes reflecting market declines and lower prices.

The following tables summarize the ~~transmission tariff ended~~price and ~~the recovery of transmission costs is included~~volume factors contributing to changes in ~~the~~revenues from generation ~~rate established under OE’s CBP.~~sales:


	Increase
Source of Change in Direct and Government Aggregation	(Decrease)
	*(In millions)*
Direct Sales:
Effect of increase in sales volumes	$	633
Change in prices		(47	)

		586

Government Aggregation
Effect of an increase in sales volumes		337
Change in prices		—

		337

Net Increase in Direct and Gov’t Aggregation Revenues	$	923

~~Changes in retail generation sales and~~


Source of Change in Wholesale Revenues	(Decrease)
	*(In millions)*
POLR:
Effect of 15.1% decrease in sales volumes	$	(262	)
Change in prices		(210	)

		(472	)

Wholesale:
Effect of 56.7% decrease in sales volumes		(123	)
Change in prices		(2	)

		(125	)

Decrease in Wholesale Revenues	$	(597	)

Transmission revenues decreased $5 million due primarily to lower PJM congestion revenue.

Expenses

Total expenses increased $539 million in the first ~~nine~~six months of ~~2009~~2010, compared with the same period of 2009.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first six months of 2010, from the same period ~~in 2008 are summarized in the following tables:~~last year:


	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	*(In millions)*
Fossil Fuel:
Change due to increased unit costs	$	33
Change due to volume consumed		40

		73

Nuclear Fuel:
Change due to increased unit costs		18
Change due to volume consumed		3

		21

Non-affiliated Purchased Power:
Power contract mark-to-market adjustment		17
Change due to decreased unit costs		(98	)
Change due to volume purchased		484

		403

Affiliated Purchased Power:
Change due to decreased unit costs		(4	)
Change due to volume purchased		19

		15

Net Increase in Fuel and Purchased Power Costs	$	512

104

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

~~Residential~~	~~6.6~~	%
~~Commercial~~	~~10.4~~	%
~~Industrial~~	~~(19.0~~	)%
~~Net Decrease in Generation Sales~~	~~(0.6~~	)%

Retail Generation Revenues Increase
(In millions)
Residential $ 93
Commercial 87
Industrial 24
Increase in Generation Revenues $ 204

~~The increase in wholesale revenues was primarily due to higher average unit prices.~~

~~Revenues from distribution throughput decreased by $203~~Fossil fuel costs increased $73 million in the first ~~nine~~six months of ~~2009~~2010, compared to the same period in 2008 due to lower average unit prices and lower KWH deliveries to all customer classes. Reduced deliveries to commercial and industrial customers reflect the weakened economy. Transition charges that ceased effective January 1,of 2009, as a result of higher volumes consumed combined with ~~the full recovery of related costs, were partially offset by a July 2008 increase to a PUCO-approved transmission rider and a January 2009 distribution rate increase (see Regulatory Matters – Ohio).~~

~~122~~

~~Changes in distribution KWH deliveries and revenues~~increased prices. Increased volume reflects higher generation in the first ~~nine~~six months of ~~2009 from the same period in 2008 are summarized in the following tables.~~

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

~~Residential~~		~~(3.3~~	)%
~~Commercial~~		~~(4.8~~	)%
~~Industrial~~		~~(24.5~~	)%
~~Decrease in Distribution Deliveries~~		~~(11.1~~	)%

Distribution Revenues Decrease
(In millions)
Residential $ (41 )
Commercial (75 )
Industrial (87 )
Decrease in Distribution Revenues $ (203 )

~~Expenses~~

~~Total expenses increased by $171 million in the first nine months of 2009 from the same period of 2008. The following table presents changes from the prior year by expense category.~~

Expenses – Changes Increase (Decrease)
(In millions)
Purchased power costs $ 248
Other operating costs (51 )
Provision for depreciation 8
Amortization of regulatory assets, net (28 )
General taxes (6 )
Net Increase in Expenses $ 171

Higher purchased power costs reflect the results of OE’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). The decrease in other operating costs for the first nine months of 2009 was primarily due to lower transmission expenses (included in the cost of purchased power beginning June 1, 2009), partially offset by costs for economic development programs and energy efficiency obligations under OE’s ESP. Higher depreciation expense in the first nine months of 2009 reflected capital additions subsequent to the third quarter of 2008. Lower amortization of net regulatory assets was primarily due to the conclusion of transition cost amortization and distribution reliability deferrals in 2008, partially offset by lower MISO transmission cost deferrals. The decrease in general taxes for the first nine months of 2009 was primarily due to lower Ohio KWH taxes.

~~Other Expenses~~

~~Other expenses increased by $15 million in the first nine months of 2009~~2010, compared to the same period last year due to improving economic conditions. The increased costs reflect higher coal and transportation charges in ~~2008~~the first six months of 2010, compared to the same period last year. Nuclear fuel costs increased $21 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 $403 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. Affiliated purchased power increased primarily due to higher ~~interest expense~~volumes purchased from affiliated companies due to the Perry nuclear refueling outage in 2009.

Other operating expenses increased $23 million in the first six months of 2010, compared to the same period of 2009, primarily due to increased transmission expenses ($33 million) and increased uncollectible customer accounts and agent fees associated with the ~~issuance~~growth in direct and government aggregation sales ($19 million), partially offset by lower nuclear operating costs ($37 million).

General taxes increased $4 million due to sales taxes associated with increased revenues.

Other Expense

Total other expense decreased $2 million in the first six months of ~~$300~~2010, compared to the same period of 2009, primarily due to a $36 million increase in investment income resulting from more favorable performance of ~~FMBs~~nuclear decommissioning trust investments, partially offset by OEa $31 million increase in ~~October 2008.~~interest expense (net of capitalized interest). Interest expense increased primarily due to new long-term debt issued in the second half of 2009 combined with the restructuring of existing long-term debt.

105

OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

~~123~~

~~THE CLEVELAND ELECTRIC ILLUMINATING COMPANY~~

~~MANAGEMENT'S NARRATIVE~~

ANALYSIS OF RESULTS OF OPERATIONS

~~CEI~~OE is a wholly owned electric utility subsidiary of FirstEnergy. ~~CEI conducts~~OE and its wholly owned subsidiary, Penn, conduct business in ~~northeastern~~portions of Ohio and Pennsylvania, providing regulated electric distribution services. ~~CEI also provides~~They procure generation services tofor those franchise customers electing to retain ~~CEI~~OE and Penn as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

For additional information with respect to ~~CEI,~~OE, please see the information contained in ~~FirstEnergy's Management~~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 ~~Outlook.~~New Accounting Standards and Interpretations.

Results of Operations

~~CEI experienced a net loss of $32~~Earnings available to parent increased by $28 million in the first ~~nine~~six months of 2009 compared to net income of $219 million in the same period of 2008. The net loss in 2009 resulted from regulatory charges ($228 million) related to the implementation of CEI's ESP. The 2009 results were also adversely impacted by increased purchased power costs, partially offset by higher deferrals of new regulatory assets and lower other operating costs.

~~Revenues~~

~~Revenues decreased by $35 million, or 2.5%, in the first nine months of 2009~~2010, compared to the same period of ~~2008~~2009. The increase primarily resulted from lower purchased power costs and other operating costs, partially offset by lower revenues.

Revenues

Revenues decreased $473 million, or 33.3%, in the first six months of 2010, compared with the same period in 2009, due primarily to a decrease in generation revenues. Distribution revenues also were lower than they were in the first half of 2009.

Retail generation revenues decreased $438 million primarily due to ~~decreases~~a decrease in KWH sales in all customer classes, partially offset by higher average prices in the commercial and industrial classes. Lower KWH sales were primarily the result of a 46.1% increase in customer shopping in the first six months of 2010. Lower KWH sales to residential customers were partially offset by increased weather-related usage in the first six months of 2010, reflecting a 62% increase in cooling 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 KWH sales and revenues in the first six months of 2010, compared to the same period in 2009, are summarized in the following tables:


Retail Generation KWH Sales	Decrease

Residential		(30.3	)%
Commercial		(60.0	)%
Industrial		(64.3	)%

Decrease in Retail Generation Sales		(48.1	)%


Retail Generation Revenues	Decrease
	*(In millions)*
Residential	$	(143	)
Commercial		(167	)
Industrial		(128	)

Decrease in Retail Generation Revenues	$	(438	)

Distribution revenues decreased $17 million in the first six 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. Residential distribution revenues were higher due to higher average unit prices resulting from the 2009 ESP and slightly higher 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 (36%) and automotive customers (27%).

106

Changes in distribution KWH deliveries and revenues ~~($117 million), transmission~~in the first six months of 2010, compared to the same period in 2009, are summarized in the following tables:


Distribution KWH Sales	Increase

Residential		0.2	%
Commercial		0.7	%
Industrial		12.7	%

Increase in Distribution Deliveries		4.0	%


	Increase
Distribution Revenues	(Decrease)
	*(In millions)*
Residential	$	9
Commercial		(8	)
Industrial		(18	)

Net Decrease in Distribution Revenues	$	(17	)

Wholesale revenues ~~($14 million) and other miscellaneous revenues ($7 million),~~decreased $11 million primarily due to lower unit prices, partially offset by an increase in sales to FES from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.

Expenses

Total expenses decreased $521 million in the first six months of 2010, from 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	$	(422	)
Other operating expenses		(93	)
Amortization of regulatory assets, net		(4	)
General taxes		(2	)

Decrease in Expenses	$	(521	)

Purchased power costs decreased in the first six months of 2010, compared to the same period of 2009, primarily due to lower KWH purchases resulting from increased customer shopping in the first six months of 2010 and slightly lower unit costs. The decrease in other operating costs for the first six months of 2010, was primarily due to lower MISO transmission expenses (assumed by third party suppliers beginning June 1, 2009) and the absence in 2010 of $18 million of costs incurred in the first six months of 2009 associated with regulatory obligations for economic development and energy efficiency programs under OE’s 2009 ESP. Lower amortization of net regulatory assets was primarily due to lower amortization of deferred MISO transmission costs, partially offset by the recovery of certain regulatory assets that began in 2010. The decrease in general taxes was primarily due to lower Ohio KWH taxes and lower property taxes.

107

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 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 increased by $94 million in the first six months of 2010, compared to the same period of 2009. The increase in earnings was primarily due to the absence in 2010 of one-time regulatory charges recognized in 2009, and decreased purchased power and other operating costs, partially offset by decreased revenues and deferred regulatory assets.

Revenues

Revenues decreased $299 million, or 32%, in the first six months of 2010, compared to the same period of 2009, due to decreased retail generation ~~revenues ($103 million).~~

and distribution revenues.

Retail generation revenues ~~increased~~decreased $200 million in the first ~~nine~~six 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~~classes. Reduced KWH sales were primarily the result of increased customer shopping in the first six months of 2010. Lower KWH sales to residential customers were partially offset by ~~decreased sales volume to residential and industrial customers compared to~~increased weather-related usage in the ~~same period~~first six months of ~~2008. Average~~2010, reflecting a 113% increase in cooling degree days. Retail generation prices increased ~~due to an increase~~ in ~~CEI’s fuel cost recovery rider that was effective from January through May 2009. In addition, effective~~2010 as a result of the CBP auction for the service period beginning June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under CEI's CBP. Reduced industrial KWH sales, principally to major automotive and steel customers, reflected weakened economic conditions. The increase in sales volumes for commercial customers resulted from a decrease in customer shopping, as most of CEI’s customers returned to PLR service in December 2008 following the termination of certain government aggregation programs in CEI’s service territory.

2009.

Changes in retail generation sales and revenues in the first ~~nine~~six months of ~~2009~~2010, compared to the same period ~~in 2008~~of 2009, are summarized in the following tables:


Retail Generation KWH Sales	Decrease

Residential		(54.3	)%
Commercial		(68.5	)%
Industrial		(49.2	)%

Decrease in Retail Generation Sales		(55.6	)%


Retail Generation Revenues	Decrease
	*(In millions)*
Residential	$	(50	)
Commercial		(80	)
Industrial		(70	)

Decrease in Retail Generation Revenues	$	(200	)

Distribution revenues decreased $91 million in the first six 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 and commercial sectors. The lower average unit prices were the result of lower transition rates in 2010. Increased industrial deliveries were the result of improving economic conditions, reflecting an increase in KWH deliveries to major steel customers (158%) and automotive customers (14%).

108

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


	Increase
Distribution KWH Sales	(Decrease)

Residential		(0.6	)%
Commercial		1.7	%
Industrial		12.0	%

Net Increase in Distribution Deliveries		5.1	%


Distribution Revenues	Decrease
	*(In millions)*
Residential	$	(13	)
Commercial		(28	)
Industrial		(50	)

Decrease in Distribution Revenues	$	(91	)

Expenses

Total expenses decreased $452 million in the first six months of 2010, compared to the same period of 2009. The following table presents the change from the prior period by expense category:


	Increase
Expenses — Changes	(Decrease)
	*(In millions)*
Purchased power costs	$	(325	)
Other operating costs		(44	)
Amortization of regulatory assets, net		(210	)
Deferral of new regulatory assets		135
General taxes		(8	)

Net Decrease in Expenses	$	(452	)

Purchased power costs decreased in the first six months of 2010, primarily due to lower KWH sales requirements as discussed above. Other operating costs decreased due to lower transmission expenses (assumed by third party suppliers beginning June 1, 2009), labor and employee benefit expenses and the absence in 2010 of $12 million of costs incurred in the first six months of 2009 associated with 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. General taxes decreased in the first six months of 2010, primarily due to a 2010 favorable tax settlement in Ohio.

Other Expense

Other expense increased $4 million in the first six months of 2010, compared to the same period of 2009 due to lower investment income and higher interest expense associated with the August 2009 issuance of $300 million first mortgage bonds, partially offset by the November 2009 redemption of $150 million senior secured notes.

109

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 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 by $7 million in the first six months of 2010, compared to 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 an increase in interest expense and decreases in revenues and investment income.

Revenues

Revenues decreased $218 million, or 46%, in the first six 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 $203 million in the first six 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 the result of a 63% increase in customer shopping in the first six months of 2010. Lower unit prices for industrial customers are primarily due to the absence of TE’s fuel cost recovery and rate stabilization riders that were effective from January through May 2009, partially offset by increased generation prices resulting from the CBP auction, effective June 1, 2009.

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


Retail Generation KWH Sales	Decrease

Residential		(48.6	)%
Commercial		(72.3	)%
Industrial		(60.8	)%

Decrease in Retail Generation Sales		(60.5	)%


Retail Generation Revenues	Decrease
	*(In millions)*
Residential	$	(44	)
Commercial		(72	)
Industrial		(87	)

Decrease in Retail Generation Revenues	$	(203	)

Distribution revenues decreased $26 million in the first six months of 2010, compared to the same period of 2009, primarily due to lower unit prices in all customer classes, partially offset by increased KWH deliveries to industrial customers. Lower unit prices 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 (36%) and steel customers (37%).

110

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


	Increase
Distribution KWH Deliveries	(Decrease)

Residential		(0.4	)%
Commercial		(1.6	)%
Industrial		14.8	%

Net Increase in Distribution Deliveries		6.2	%


Distribution Revenues	Decrease
	*(In millions)*
Residential	$	(5	)
Commercial		(6	)
Industrial		(15	)

Decrease in Distribution Revenues	$	(26	)

Wholesale revenues increased $7 million in the first six months of 2010, compared to the same period of 2009, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.

Expenses

Total expenses decreased $241 million in the first six 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	$	(179	)
Other operating costs		(29	)
Amortization of regulatory assets, net		(32	)
General taxes		(1	)

Decrease in Expenses	$	(241	)

Purchased power costs decreased $179 million in the first six months of 2010, compared to the same period of 2009 due to lower volume as a result of decreased KWH sales requirements. Other operating costs decreased $29 million primarily due to reduced transmission expense (assumed by third party suppliers beginning June 1, 2009), lower costs associated with regulatory obligations for economic development and energy efficiency programs and decreased labor expenses. The $32 million decrease in net regulatory asset amortization was primarily due to PUCO-approved cost deferrals and lower MISO transmission cost amortization, partially offset by the absence of MISO transmission and fuel cost deferrals in the first six months of 2010, compared to the same period of 2009.

Other Expense

Other expense increased $13 million in the first six 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 and lower investment income.

111

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 under the following subheadings, which information is incorporated by reference herein: Capital Resources and Liquidity, Guarantees and Other Assurances, Market Risk Information, Credit Risk, Outlook and New Accounting Standards and Interpretations.

Results of Operations

Net income increased by $13 million in the first six months of 2010, compared to 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 six months of 2010, revenues decreased $57 million, or 4%, compared to the same period of 2009. The decrease in revenues is primarily due to a decrease in retail and wholesale generation revenues, partially offset by higher distribution and transmission revenues.

Retail generation revenues decreased $73 million due to lower retail generation KWH sales in commercial and industrial classes, partially offset by higher KWH sales in the residential class. Lower sales to the commercial and industrial classes were primarily due to an increase in the number of shopping customers. Higher KWH sales to the residential class reflected increased weather-related usage resulting from a 105% increase in cooling degree days.

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


	Increase
Retail Generation KWH Sales	(Decrease)

Residential		~~(2.7~~5.1	)%
Commercial		~~4.8~~(31.0	)%
Industrial		(~~14.6~~24.7	)%

Net Decrease in Retail Generation Sales		(~~6.4~~10.1	)%


	Increase
Retail Generation Revenues	(Decrease)
	*(In millions)*
Residential	$	30
Commercial		(95	)
Industrial		(8	)

Net Decrease in Retail Generation Revenues	$	(73	)

Retail Generation Revenues Increase

(in millions)

Residential $ 30
Commercial 40
Industrial 33
Increase in Generation Revenues $ 103

~~124~~

~~Revenues from distribution throughput~~Wholesale generation revenues decreased ~~by $117~~$7 million in the first ~~nine~~six months of ~~2009~~2010, compared to the same period of ~~2008~~2009; less power was available for sale due to the termination of a ~~decrease~~NUG power purchase contract in July 2009.

Distribution revenues increased $17 million in the first six months of 2010, compared to the same period of 2009, due to higher KWH deliveries in all customer ~~classes~~classes. Increased usage from warmer weather and ~~lower average~~improving economic conditions in JCP&L’s service territory was partially offset by a decrease in composite unit prices in the ~~residential~~commercial and commercial sectors. The lower average unit price was the net result of reduced transition rates (see Regulatory Matters – Ohio), partially offset by a PUCO-approved distribution rate increase effective May 1, 2009. The lower KWH deliveries in the first nine months of 2009 were due to weaker economic conditions and a decrease of 14% in cooling degree days in the first nine months of 2009 as compared to the previous year.industrial classes.

112

Changes in distribution KWH deliveries and revenues in the first ~~nine~~six months of ~~2009~~2010 compared to the same period of ~~2008~~2009, are summarized in the following ~~tables.~~

tables:


Distribution KWH ~~Deliveries~~Sales	~~Decrease~~Increase

Residential		~~(4.0~~5.1	)%
Commercial		~~(4.7~~1.7	)%
Industrial		~~(18.6~~1.1	)%
~~Decrease in Distribution Deliveries~~		~~(10.8~~	)%

Distribution Revenues Decrease
(In millions)
Residential $ (52 )
Commercial (26 )
Industrial (39 )
Decrease in Distribution Revenues $ (117 )

~~Expenses~~

Total operating expenses increased by $343 million in the first nine months of 2009 compared to the same period of 2008. The following table presents the change from the prior year by expense category:

Expenses - Changes
Increase
(Decrease)

(in millions)
Purchased power costs $ 254
Other operating costs (52 )
Amortization of regulatory assets 200
Deferral of new regulatory assets (63 )
General Taxes 4
Net Increase in Expenses $ 343

Higher purchased power costs reflect the results of CEI’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). Increased amortization of regulatory assets was due to the impairment of CEI’s Extended RTC balance ($216 million) in accordance with the PUCO-approved ESP. The increase in the deferral of new regulatory assets was due to CEI’s deferral of purchased power costs as approved by the PUCO, partially offset by lower deferred MISO transmission expenses and the absence of RCP distribution deferrals that ceased at the end of 2008. Other operating costs were $52 million lower than in the previous year due to lower transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and reduced labor and contractor costs, partially offset by costs associated with the ESP for economic development and energy efficiency programs, higher pension expense and restructuring costs. The increase in general taxes was primarily due to higher property taxes.

~~125~~

~~THE TOLEDO EDISON COMPANY~~

~~MANAGEMENT'S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

TE is a wholly owned electric utility subsidiary of FirstEnergy. TE conducts business in northwestern Ohio, providing regulated electric distribution services. TE also provides generation services to those customers electing to retain TE as their power supplier. Until December 31, 2008, TE purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio in our Combined Notes to the Consolidated Financial Statements for a discussion of Ohio power supply procurement issues for 2009 and beyond.

For additional information with respect to TE, please see the information contained in FirstEnergy's Management 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 and Outlook.

~~Results of Operations~~

Net income in the first nine months of 2009 decreased to $14 million from $70 million in the same period of 2008. The change resulted primarily from increased purchased power expense and the completion of transition cost recovery in 2008.

~~Revenues~~

Revenues increased slightly in the first nine months of 2009 compared to the same period of 2008 primarily due to increased retail generation revenues ($143 million) and other miscellaneous revenue ($3 million), partially offset by lower distribution revenues ($130 million) and wholesale generation revenues ($16 million).

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

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

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

~~Residential~~ Increase in Distribution Deliveries		~~2.4~~3.1	%
~~Commercial~~		~~30.0~~	%
~~Industrial~~		~~(17.8~~	)%
~~Net decrease in Retail Generation Sales~~		~~(2.7~~	)%

Retail Generation Revenues Increase

(In millions)

Residential $ 35
Commercial 66
Industrial 42
Increase in Retail Generation Revenues $ 143

The decrease in wholesale revenues was primarily due to the expiration of a sales agreement with AMP-Ohio at the end of 2008 ($10 million) and lower revenues from associated sales to NGC ($6 million) from TE's leasehold interest in Beaver Valley Unit 2.

~~126~~

Revenues from distribution throughput decreased by $130 million in the first nine months of 2009 compared to the same period of 2008 due to lower average unit prices and lower KWH deliveries for all customer classes due primarily to economic conditions. Transition charges that ceased effective January 1, 2009, with the full recovery of related costs, were partially offset by a PUCO-approved distribution rate increase (see Regulatory Matters – Ohio).

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

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

~~Residential~~		~~(5.2~~	)%
~~Commercial~~		~~(10.2~~	)%
~~Industrial~~		~~(12.9~~	)%
~~Decrease in Distribution Deliveries~~		~~(10.3~~	)%


	Increase
Distribution Revenues	(Decrease)
	*(In millions)*
Residential	$	18
Commercial		—
Industrial		(1	)

Net Increase in Distribution Revenues	$	17

Distribution Revenues Decrease
(In millions)
Residential $ (31 )
Commercial (61 )
Industrial (38 )
Decrease in Distribution Revenues $ (130 )

~~Expenses~~

~~Total expenses~~Transmission revenues increased ~~$80~~$4 million in the first ~~nine~~six months of ~~2009 from~~2010, compared to the same period of ~~2008.~~2009, due to an increase in network transmission system revenues from PJM.

Expenses

Total expenses decreased $77 million in the first six 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 $
141

Other operating costs

(32
)
Provision for depreciation

(2
)
Amortization of regulatory assets, net

(27
)
Net Increase in Expenses

$
80

Higher purchased power costs reflect the results of TE’s power procurement process for retail customers in the first nine months of 2009 (see Regulatory Matters – Ohio). Other operating costs decreased primarily due to reduced transmission expenses (included in the cost of power purchased from others beginning June 1, 2009) and lower costs associated with TE’s leasehold interest in Beaver Valley Unit 2 (absence of a refueling outage in the 2009 period). These reductions were partially offset by costs associated with regulatory obligations for economic development and energy efficiency programs under TE’s ESP. The decrease in net amortization of regulatory assets is primarily due to the completion of transition cost recovery and distribution reliability deferrals in 2008, partially offset by lower MISO transmission cost deferrals in 2009.

~~127~~

~~JERSEY CENTRAL POWER & LIGHT COMPANY~~

~~MANAGEMENT'S NARRATIVE~~

~~ANALYSIS OF RESULTS OF OPERATIONS~~

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

For additional information with respect to JCP&L, please see the information contained in FirstEnergy's Management 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 and Outlook.

~~Results of Operations~~

Net income for the first nine months of 2009 decreased to $128 million from $153 million in the same period in 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and reduced amortization of regulatory assets.

~~Revenues~~

In the first nine months of 2009, revenues decreased by $382 million, or 14%, compared with the same period of 2008. The decrease in revenues is primarily due to a decrease in retail generation revenues ($131 million), wholesale generation revenues ($208 million), and distribution revenues ($39 million) in the first nine months of 2009.

Retail generation revenues decreased due to lower retail generation KWH sales in all sectors, partially offset by higher unit prices in the residential and commercial sectors resulting from the BGS auctions. Lower sales to the residential sector reflected milder weather in JCP&L’s service territory, while the decrease in sales to the commercial sector was primarily due to an increase in the number of shopping customers. Industrial sales were lower as a result of weakened economic conditions.

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

~~Retail Generation KWH Sales~~	~~Decrease~~

~~Residential~~		~~(5.3)~~	%
~~Commercial~~		~~(19.7)~~	%
~~Industrial~~		~~(13.7)~~	%
~~Decrease in Generation Sales~~		~~(11.4)~~	%

~~Retail Generation Revenues~~	~~Decrease~~
	~~(In millions)~~
~~Residential~~	$	~~(15)~~
~~Commercial~~		~~(104)~~
~~Industrial~~		~~(12)~~
~~Net Decrease in Generation Revenues~~	$	~~(131)~~

Wholesale generation revenues decreased $208 million in the first nine months of 2009 due to lower market prices and a decrease in sales volume from NUG purchases resulting from the termination of a NUG contract in October 2008.

Distribution revenues decreased $39 million in the first nine months of 2009 compared to the same period of 2008 due to lower KWH deliveries, reflecting weather and economic impacts in JCP&L’s service territory, partially offset by an increase in composite unit prices.

~~128~~

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

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

~~Residential~~		~~(5.3)~~	%
~~Commercial~~		~~(3.9)~~	%
~~Industrial~~		~~(13.1)~~	%
~~Decrease in Distribution Deliveries~~		~~(5.6)~~	%

~~Distribution Revenues~~	~~Decrease~~
	~~(In millions)~~
~~Residential~~	$	~~(25)~~
~~Commercial~~		~~(10)~~
~~Industrial~~		~~(4)~~
~~Decrease in Distribution Revenues~~	$	~~(39)~~

~~Expenses~~

~~Total expenses decreased by $346 million in the first nine months of 2009 compared to the same period of 2008. The following table presents changes from the prior year~~ period by expense category:

Expenses - Changes	Increase (Decrease)

				Increase
Expenses — Changes				(Decrease)
	(In millions)			*(In millions)*
Purchased power costs	$	(338	)	$	(81	)
Other operating costs		7			14
Provision for depreciation		7			5
Amortization of regulatory assets		(18	)
Amortization of regulatory assets, net					(16	)
General taxes		(4	)		1
Net decrease in expenses	$	(346	)

Net Decrease in Expenses				$	(77	)

Purchased power costs decreased in the first ~~nine~~six months of ~~2009~~2010 primarily due to the lower KWH sales requirements ~~discussed above~~ and ~~lower unit prices due to reduced energy rates.~~the termination of a NUG contract in July 2009. Other operating costs increased in the first ~~nine~~six months of ~~2009~~2010 primarily due to higher ~~expenses related to employee benefits and customer assistance programs.~~tree trimming costs resulting from major storm clean up in JCP&L’s service territory, offset by a favorable labor settlement of $7 million in the second quarter of 2010. Depreciation expense increased due to an increase in depreciable property since the ~~third~~second quarter of ~~2008. Amortization of~~2009. Net regulatory ~~assets~~asset amortization decreased in the first ~~nine~~six months of ~~2009~~2010 primarily due to ~~the full recovery of certain regulatory assets in June 2008. General taxes decreased principally as the result of lower Transitional Energy Facility Assessment (TEFA) and sales taxes.~~

~~Other Expenses~~

Other expenses increased by $9 million in the first nine months of 2009 compared to the same period in 2008 primarily due to higher interest expense associated with JCP&L's $300 million Senior Notes issuance in January 2009.

~~Sale of Investment~~

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

113

~~129~~

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also ~~provides~~procures generation service tofor those customers electing to retain Met-Ed as their power supplier. ~~On November 3, 2009, FES,~~ Met-Ed ~~Penelec and Waverly restated their~~has a partial requirements wholesale power ~~purchase~~sales agreement ~~for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires~~with FES, to supply ~~essentially~~nearly all of ~~Met-Ed, Penelec, and Waverly’s~~its energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. ~~FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load.~~ FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at ~~the end of~~fixed prices through 2010.

For additional information with respect to Met-Ed, please see the information contained in ~~FirstEnergy's Management~~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, Market Risk Information, Credit Risk, Outlook and ~~Outlook.~~New Accounting Standards and Interpretations.

Results of Operations

Net income ~~decreased to $37~~increased by $3 million in the first ~~nine~~six months of 2009, compared to $64 million in the same period of 2008. The decrease was primarily due to increased amortization of regulatory assets, partially offset by lower other operating costs, purchased power and income taxes.

~~Revenues~~

~~Revenues increased by $5 million, or 0.4%, in the first nine months of 2009~~2010, compared to the same period of ~~2008~~2009. The increase was primarily due to increased revenues, partially offset by increased purchased power, other operating expenses and amortization of net regulatory assets.

Revenues

The revenue increase of $109 million, or 13%, in the first six months of 2010 compared to the same period of 2009 reflected higher distribution, ~~throughput~~wholesale and generation revenues, partially offset by a decrease in ~~retail generation and wholesale~~transmission revenues. ~~Wholesale~~

Distribution revenues ~~decreased by $7~~increased $57 million in the first ~~nine~~six months of ~~2009 due to lower wholesale KWH sales volume, partially offset by higher capacity prices for PJM market participants.~~

In the first nine months of 2009, retail generation revenues decreased $28 million due to lower KWH sales to all classes with a slight increase in composite unit prices in the residential and commercial customer classes and a slight decrease in composite unit prices in the industrial customer class. Lower KWH sales to commercial and industrial customers were principally due to economic conditions in Met-Ed’s service territory. Lower KWH sales in the residential sector were due to decreased weather-related usage, reflecting a 13.9% decrease in cooling degree days in the first nine months of 2009.

~~Changes in retail generation sales and revenues in the first nine months of 2009~~2010, compared to the same period of ~~2008 are summarized in the following tables:~~

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

~~Residential~~		~~(2.0~~	)%
~~Commercial~~		~~(4.7~~	)%
~~Industrial~~		~~(11.9~~	)%
~~Decrease in Retail Generation Sales~~		~~(5.6~~	)%

~~Retail Generation Revenues~~	~~(Decrease)~~
	~~(In millions)~~
~~Residential~~	$	(4	)
~~Commercial~~		(8	)
~~Industrial~~		~~(16~~	)
~~Decrease in Retail Generation Revenues~~	$	~~(28~~	)

~~130~~

~~In the first nine months of~~ 2009, ~~distribution throughput revenues increased $63 million~~ primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, ~~2009. Decreased~~2009 and 2010, partially offset by lower CTC rates for the residential class. Higher KWH deliveries to commercial and industrial customers ~~reflected~~were due to improving economic conditions in Met-Ed’s service territory. Higher residential KWH deliveries reflect increased weather-related usage due to a 97% increase in cooling degree days in the ~~weakened economy, while decreased deliveries to residential customers were~~first six months of 2010, partially offset by a ~~result of~~10% decrease in heating degree days for the ~~weather conditions described above.~~

same time period.

Changes in distribution KWH deliveries and revenues in the first ~~nine~~six months of ~~2009~~2010, compared to the same period of ~~2008~~2009 are summarized in the following tables:


Distribution KWH Deliveries		~~(Decrease)~~Increase

Residential			~~(2.0~~0.7	)%
Commercial			~~(4.7~~4.2	)%
Industrial			~~(11.9~~4.5	)%
~~Decrease in Distribution Deliveries~~				~~(5.6~~
Increase in Distribution Deliveries	)		2.8	%


Distribution Revenues	Increase
	*(In millions)*
Residential	$	23
Commercial		21
Industrial		13

Increase in Distribution Revenues	$	57

Wholesale revenues increased $40 million in the first six months of 2010 compared to the same period of 2009, primarily reflecting higher PJM capacity prices.

Retail generation revenues increased $21 million in the first six months of 2010, compared to the same period of 2009, due to higher composite unit prices in the residential and commercial customer classes and higher KWH sales to all customer classes.

114

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

~~Distribution Revenues~~
Retail Generation KWH Sales	Increase
	~~(In millions)~~
Residential	$	320.7	%
Commercial		203.7	%
Industrial		113.5	%

Increase in ~~Distribution Revenues~~Retail Generation Sales	$	632.4	%


Retail Generation Revenues	Increase
	*(In millions)*
Residential	$	14
Commercial		5
Industrial		2

Increase in Retail Generation Revenues	$	21

Transmission ~~service~~ revenues decreased ~~by $22~~$9 million in the first ~~nine~~six months of ~~2009~~2010 compared to the same period of ~~2008,~~2009 primarily due to decreased ~~revenues related to Met-Ed’s~~ Financial Transmission ~~Rights.~~Rights revenues. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

~~Operating~~ Expenses

Total ~~operating~~ expenses increased ~~by $44~~$103 million in the first ~~nine~~six months of ~~2009~~2010 compared to the same period of ~~2008.~~2009. The following table presents changes from the prior year by expense category:


	Increase
Expenses — Changes	(Decrease)
	*(In millions)*
Purchased power costs	$	61
Other operating costs		35
Provision for depreciation		1
Amortization of regulatory assets, net		8
General taxes		(2	)

Net Increase in Expenses	$	103

Expenses – Changes Increase (Decrease)
(In millions)
Purchased power costs $ (17 )
Other operating costs (129 )
Provision for depreciation 5
Amortization of regulatory assets, net 184
General taxes 1
Net Increase in Expenses $ 44

Purchased power costs increased $61 million in the first six months of 2010 due to an increase in unit costs and increased KWH purchased to source increased generation sales requirements. Other operating costs increased $35 million in the first six months of 2010 compared to the same period in 2009 primarily due to higher transmission congestion expenses. The ~~net~~ amortization of regulatory assets increased ~~by $184~~$8 million in the first ~~nine~~six months of ~~2009 compared to the same period of 2008~~2010 primarily due to increased transmission cost ~~recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costs~~recovery. General taxes decreased ~~$129~~$2 million ~~in the first nine months of 2009 primarily~~mostly due to ~~lower transmission expenses as~~ a result of decreased congestion costs and transmission loss expenses. Purchased power costs decreased by $17 million, or 2.5%, in the first nine months of 2009 due to reduced volumes purchased as a result of lower KWH sales requirements, partially offset by an increase in composite unit prices.Pennsylvania tax amnesty settlement. Depreciation expense increased ~~primarily~~$1 million due to an increase in depreciable property since ~~the third quarter~~June of ~~2008.~~2009.

115

~~Other Expense~~

Other expense increased in the first nine months of 2009 primarily due to a decrease in interest earned on regulatory assets, reflecting a lower regulatory asset base, and an increase in interest expense from Met-Ed’s $300 million Senior Notes issuance in January 2009.

~~131~~

PENNSYLVANIA ELECTRIC COMPANY

MANAGEMENT’S NARRATIVE

~~MANAGEMENT'S NARRATIVE~~

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also ~~provides~~procures generation services tofor those customers electing to retain Penelec as their power supplier. ~~On November 3, 2009, FES, Met-Ed,~~ Penelec ~~and Waverly restated their~~has a partial requirements wholesale power ~~purchase~~sales agreement ~~for 2010. The Fourth Restated Partial Requirements Agreement continues to limit the amount of capacity resources required to be supplied by FES to 3544 MW, but requires~~with FES, to supply ~~essentially~~nearly all of ~~Met-Ed, Penelec, and Waverly’s~~its energy requirements in 2010 Under the new agreement, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. ~~FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load.~~ FES is responsible for obtaining additional power supplies in the event of failure of supply of the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at ~~the end of~~fixed prices through 2010.

For additional information with respect to Penelec, please see the information contained in ~~FirstEnergy's Management~~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 ~~Outlook.~~New Accounting Standards and Interpretations.

Results of Operations

Net income decreased ~~to $49~~by $3 million in the first ~~nine~~six months of ~~2009,~~2010, compared to ~~$62 million in~~ the same period of ~~2008.~~2009. The decrease was primarily due to ~~lower revenues, partially offset by lower~~higher purchased power ~~costs~~ and ~~decreased amortization of regulatory assets.~~

~~Revenues~~

~~Revenues decreased by $61 million, or 5.4%, in the first nine months of 2009 primarily due to lower retail generation revenues, distribution throughput revenues and transmission revenues,~~other operating costs, partially offset by higher ~~wholesale generation revenues. Wholesale~~revenues and lower amortization (deferral) of net regulatory assets and general taxes.

Revenues

In the first six months of 2010, revenues increased $1$50 million, ~~in the first nine months of 2009,~~or 6.9%, compared to the same period of ~~2008, primarily reflecting higher KWH sales.~~

~~In the first nine months of 2009, retail generation revenues decreased $31 million~~2009. The increase in revenue was primarily due to higher retail and wholesale generation revenues, partially offset by lower distribution and transmission revenues.

Retail generation revenues increased $39 million in the first six months of 2010, compared to the same period of 2009, primarily due to higher unit prices and KWH sales in all customer classes. Higher unit prices across all customer classes are primarily due to an increase in the generation rate, effective January 1, 2010. Higher KWH sales to ~~the~~ commercial and industrial ~~customer classes~~customers were due to ~~weakened~~improving economic ~~conditions; reduced~~conditions in Penelec’s service territory. Higher KWH sales to ~~the~~ residential ~~customer class were~~customers increased primarily due to ~~decreased~~ weather-related usage, reflecting a ~~28.5% decrease~~129% increase in cooling degree days in the first ~~nine~~six months of ~~2009.~~

2010, partially offset by a 10% decrease in heating degree days for the same time period.

Changes in retail generation sales and revenues in the first ~~nine~~six months of ~~2009~~2010 compared to the same period of ~~2008~~2009 are summarized in the following tables:


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

Residential		~~(1.4)~~1.3	%
Commercial		~~(3.2)~~3.9	%
Industrial		~~(16.2)~~5.6	%
~~Decrease in Retail Generation Sales~~		~~(6.6)~~	%


Increase in Retail Generation ~~Revenues~~Sales	~~(Decrease)~~	3.4	%
	~~(In millions)~~
~~Residential~~	$	~~(2)~~
~~Commercial~~		~~(6)~~
~~Industrial~~		~~(23)~~
~~Decrease in Retail Generation Revenues~~	$	~~(31)~~


Retail Generation Revenues	Increase
	*(In millions)*
Residential	$	8
Commercial		17
Industrial		14

Increase in Retail Generation Revenues	$	39

~~132~~

~~Revenues from distribution throughput decreased $2~~Wholesale generation revenues increased $34 million in the first ~~nine~~six months of ~~2009~~2010, compared to the same period of ~~2008,~~2009, due primarily to higher PJM capacity prices.

Distribution revenues decreased by $11 million in the first six months of 2010, compared to the same period of 2009, primarily due to ~~decreased deliveries to~~a decrease in the ~~commercial and industrial sectors reflecting the economic conditions~~CTC rate in ~~Penelec's service area. Offsetting this decrease was~~all customer classes, partially offset by an increase in the universal service and energy efficiency rates for the residential ~~unit prices due to an increase~~customer class and increased KWH sales in ~~transmission rates, resulting from the annual update of Penelec's TSC rider effective June 1, 2009.~~all customer classes.

116

Changes in distribution KWH deliveries and revenues in the first ~~nine~~six months of ~~2009~~2010, compared to the same period of ~~2008~~2009, are summarized in the following tables:


Distribution KWH Deliveries	~~(Decrease)~~Increase

Residential		~~(1.4)~~1.3	%
Commercial		~~(3.2)~~4.0	%
Industrial		~~(15.4)~~5.3	%
~~Decrease in Distribution Deliveries~~			~~(6.6)~~
Increase in Distribution Deliveries		3.5	%


				Increase
Distribution Revenues	Increase (Decrease)			(Decrease)
	(In millions)			*(In millions)*
Residential	$	4		$	6
Commercial		(2	)		(10	)
Industrial		(4	)		(7	)
Net Decrease in Distribution Revenues	$	(2	)

Net decrease in Distribution Revenues				$	(11	)

Transmission revenues decreased by ~~$34~~$8 million in the first ~~nine~~six months of ~~2009~~2010, compared to the same period of ~~2008,~~2009, primarily due to lower ~~revenues related to Penelec’s~~ Financial Transmission ~~Rights.~~Rights revenue. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

~~Operating~~ Expenses

Total ~~operating~~ expenses ~~decreased~~increased by ~~$27~~$45 million in the first ~~nine~~six months of ~~2009~~2010, as compared with the same period of ~~2008.~~2009. The following table presents changes from the prior ~~year~~period by expense category:

Expenses - Changes	Increase (Decrease)

				Increase
Expenses — Changes				(Decrease)
	(In millions)			*(In millions)*
Purchased power costs	$	(11	)	$	79
Other operating costs		(5	)		16
Provision for depreciation		5			1
Amortization of regulatory assets, net		(11	)
Amortization (deferral) of regulatory assets, net					(47	)
General taxes		(5	)		(4	)
Net Decrease in Expenses	$	(27	)

Net Increase in Expenses				$	45

Purchased power costs ~~decreased by $11~~increased $79 million ~~or 1.7%,~~ in the first ~~nine~~six months of ~~2009~~2010, compared to the same period of ~~2008~~2009, primarily due to ~~reduced volume as a result of lower KWH sales requirements, partially offset by increased composite~~higher unit ~~prices.~~costs. Other operating costs ~~decreased by $5~~increased $16 million in the first ~~nine~~six months of ~~2009~~2010, primarily due to increased locational marginal prices partially offset by lower transmission expenses. The amortization (deferral) of net regulatory assets decreased $47 million in the first six months of 2010, primarily due to ~~reduced labor and~~increased cost deferrals resulting from higher transmission expenses and decreased amortization of regulatory assets resulting from lower CTC revenues. General taxes decreased $4 million primarily due to a ~~decrease in contingency reserves based~~favorable ruling on a ~~favorable legal ruling, partially offset by higher pension and OPEB expenses. Depreciation~~property tax appeal in the first quarter of 2010.

Other Expense

In the first six months of 2010, other expense increased $8 million primarily due to an increase in depreciable property since the third quarter of 2008. The net amortization of regulatory assets decreased in the first nine months of 2009 primarily due to increased transmission cost deferrals as a result of increased net congestion costs. General taxes decreased due to lower gross receipts tax due to the reduced KWH sales mentioned above.

~~Other Expense~~

~~In the first nine months of 2009, other expense decreased primarily due to lower interest expense on borrowings from the regulated money pool combined with reduced~~ interest expense on long-term debt due to the ~~$100~~$500 million ~~repayment of unsecured notes~~debt issuance in ~~April~~September 2009.

117

~~133~~

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4. CONTROLS AND PROCEDURES

(a) EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

~~FirstEnergy's~~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~~registrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, ~~those officers~~the chief executive officer and chief financial officer have concluded that the ~~registrant's~~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 ~~September~~June 30, ~~2009,~~2010, there were no changes in ~~FirstEnergy's~~FirstEnergy’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the ~~registrant's~~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~~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~~registrant’s disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15(d)-15(e), as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, ~~those officers~~each registrant’s chief executive officer and chief financial officer have concluded that such ~~registrant's~~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 ~~September~~June 30, ~~2009,~~2010, there were no changes in the ~~registrants'~~registrants’ internal control over financial reporting that ~~have~~has materially affected, or are reasonably likely to materially affect, the ~~registrants'~~registrants’ internal control over financial reporting.

118

~~134~~

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Notes 98 and 109 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

~~FirstEnergy's~~FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, ~~2008, and Quarterly Report on Form 10-Q for the quarter ended March 31,~~ 2009, ~~and June 30, 2009, include~~includes a detailed discussion of its risk factors. ~~For the quarter ended September 30, 2009, there~~There have been no material changes to these risk ~~factors.~~factors for the quarter ended June 30, 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 ~~third~~second quarter of ~~2009.~~2010.


	Period
	April		May		June		Second Quarter

Total Number of Shares Purchased^(a)		75,577		41,674		549,279		666,530

Average Price Paid per Share	$	38.14	$	36.28	$	34.77	$	35.24

Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs		—		—		—		—

Maximum Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased Under the Plans or Programs		—		—		—		—

Period
July August September Third Quarter
Total Number of Shares Purchased (a)
30,128 108,110 367,075 505,313
Average Price Paid per Share $39.05 $45.21 $45.46 $45.02
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~~FirstEnergy’s obligations to deliver common stock under its 2007 Incentive Compensation Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan and Stock Investment Plan. In addition, such amounts reflect shares tendered by employees to pay the exercise price or withholding taxes upon exercise of stock options granted under the 2007 Incentive Compensation Plan and the Executive Deferred Compensation Plan.

ITEM 5. OTHER INFORMATION

None

119

On November 3, 2009, FirstEnergy Solutions Corp. (FES), Met-Ed, Penelec and Waverly executed a Fourth Restated Partial Requirements Agreement (Fourth PRA) effective January 1, 2010. The Fourth PRA supersedes the Third Restated Partial Requirements Agreement executed November 1, 2008, among the parties. The Fourth PRA also terminates the call options provided under the Third Restated Partial Requirements Agreement. The Fourth PRA continues to limit the amount of capacity resources supplied by FES to 3544 MW, but requires FES to supply essentially all of Met-Ed, Penelec, and Waverly’s (Buyers) energy requirements in 2010 Under the Fourth PRA, Met-Ed, Penelec, and Waverly assign 1300 MW of existing energy purchases from a third party, non-affiliated supplier to FES to assist it in supplying Buyers’ power supply requirements and managing congestion expenses. FES can either sell the assigned power from the third party into the market or use it to serve the Met-Ed/Penelec load. FES is responsible for obtaining additional power supplies in the event of failure of supply under the assigned energy purchase contracts. Prices for the power sold by FES were increased to $42.77 and $44.42, respectively for Met-Ed and Penelec. In addition, FES agreed to reimburse Met-Ed and Penelec, respectively, for congestion expenses and marginal losses in excess of $208 million and $79 million as billed by PJM in 2010, and associated with delivery of power by FES under the Fourth Restated Partial Requirements Agreement. The Fourth Restated Partial Requirements Agreement terminates at the end of 2010.

~~The foregoing summary does not purport to be complete and is qualified in its entirety by reference to the Fourth Restated Partial Requirements Agreements filed as an exhibit to this Form 10-Q.~~

~~135~~

ITEM 6. EXHIBITS


Exhibit Number

FirstEnergy
~~FirstEnergy~~		2.1		Amendment No.1 to the 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 S-4 filed June
				4, 2010, Exhibit 2.2, File No. 333-165640)
		12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350
	101*	101	*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy
				Corp. for the period ended ~~September~~June 30, ~~2009,~~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.
FES
	~~3.1~~	Amended and Restated Code of Regulations of FirstEnergy Solutions Corp. effective as of August 26, 2009 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 3.1)
	~~4.1~~	Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.1)
	~~4.2~~	First Supplemental Indenture, dated as of August 1, 2009, between FirstEnergy Solutions Corp. and The Bank of New York Mellon Trust Company, N.A. (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)
	~~4.3~~	~~Form of 4.80% Senior Notes due 2015 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)~~
	~~4.4~~	~~Form of 6.05% Senior Notes due 2021 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)~~
	~~4.5~~	~~Form of 6.80% Senior Notes due 2039 (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 4.2)~~
	~~10.1~~	Registration Rights Agreement, dated August 7, 2009, among FirstEnergy Solutions Corp., and Morgan Stanley & Co. Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC and RBS Securities Inc., as representatives of the initial purchasers (incorporated by reference to FES' Form 8-K filed on August 7, 2009 (SEC File No. 000-53742), Exhibit 10.1)
	~~10.2~~	~~The Fourth Restated Partial Requirements Agreement~~
	12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350
OE
		12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350
CEI
	~~4.1~~	Ninetieth Supplemental Indenture, dated as of August 1, 2009, to The Cleveland Electric Illuminating Company’s Mortgage and Deed of Trust dated July 1, 1940 (incorporated by reference to CEI's Form 8-K filed on August 18, 2009 (SEC File No. 1-2323), Exhibit 4.1)
	~~4.2~~	~~Form of First Mortgage Bonds, 5.50% Series due 2024 (incorporated by reference to CEI's Form 8-K filed on August 18, 2009 (SEC File No. 1-2323), Exhibit 4.1)~~
	12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350

~~136~~

TE
		12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350
JCP&L
		12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350
Met-Ed
	~~10.2~~	~~The Fourth Restated Partial Requirements Agreement~~
	12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350
Penelec
	~~4.1~~	Company Order, dated as of September 30, 2009 establishing the terms of the 5.20% Senior Notes due 2020 and 6.15% Senior Notes due 2038 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1)
	~~4.2~~	~~Form of 5.20% Senior Notes due 2020 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1)~~
	~~4.3~~	~~Form of 6.15% Senior Notes due 2038 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.1)~~
	~~4.4~~	Supplemental Indenture No. 2, dated as of October 1, 2009, to the Indenture dated as of April 1, 2009, as amended, between Pennsylvania Electric Company and The Bank of New York Mellon, as successor trustee (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.4)
	~~4.5~~	Agreement of Resignation, Appointment and Acceptance among The Bank of New York Mellon, as Resigning Trustee, The Bank of New York Mellon Trust Company, N.A., as Successor Trustee and Pennsylvania Electric Company, dated October 1, 2009 (incorporated by reference to Penelec's Form 8-K filed on October 6, 2009 (SEC File No. 1-3522), Exhibit 4.5)
	~~10.2~~	~~The Fourth Restated Partial Requirements Agreement~~
	12		Fixed charge ratios
	15	~~Letter from independent registered public accounting firm~~
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
		31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
		32		Certification of chief executive officer and chief financial officer, pursuant
				to 18 U.S.C. Section 1350

120

* 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.


*		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.

121

~~137~~

SIGNATURES

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

~~November 6, 2009~~

August 3, 2010

	~~FIRSTENERGY CORP.~~
	~~Registrant~~

		FIRSTENERGY ~~SOLUTIONS~~ CORP.
	~~Registrant~~

	~~OHIO EDISON COMPANY~~
	Registrant

	~~THE CLEVELAND ELECTRIC~~
	~~ILLUMINATING COMPANY~~
	~~Registrant~~

	~~THE TOLEDO EDISON COMPANY~~
	~~Registrant~~FIRSTENERGY SOLUTIONS CORP.

	~~METROPOLITAN EDISON COMPANY~~
	~~Registrant~~

	~~PENNSYLVANIA ELECTRIC COMPANY~~	Registrant
	~~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~~



		Registrant

		/s/ Kevin R. Burgess

		Kevin R. Burgess
	~~Controller~~
		Controller (Principal Accounting Officer)

122

~~138~~

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30						September 30
	2009			2008			2009			2008
	(In millions, except per share amounts)
REVENUES:
Electric utilities	$	2,940		$	3,469		$	8,751		$	9,247
Unregulated businesses		468			435			1,262			1,179
Total revenues *		3,408			3,904			10,013			10,426

EXPENSES:
Fuel		302			356			890			1,000
Purchased power		1,313			1,306			3,480			3,376
Other operating expenses		665			794			2,103			2,374
Provision for depreciation		188			168			550			500
Amortization of regulatory assets		261			291			903			795
Deferral of regulatory assets		-			(58	)		(136	)		(261	)
General taxes		192			201			587			596
Total expenses		2,921			3,058			8,377			8,380

OPERATING INCOME		487			846			1,636			2,046

OTHER INCOME (EXPENSE):
Investment income		191			40			207			73
Interest expense		(355	)		(192	)		(755	)		(559	)
Capitalized interest		35			15			96			36
Total other expense		(129	)		(137	)		(452	)		(450	)

INCOME BEFORE INCOME TAXES		358			709			1,184			1,596

INCOME TAXES		128			238			430			585

NET INCOME		230			471			754			1,011

Noncontrolling interest income (loss)		(4	)		-			(14	)		1

EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	234		$	471		$	768		$	1,010


BASIC EARNINGS PER SHARE OF COMMON STOCK	$	0.77		$	1.55		$	2.52		$	3.32


WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		304			304			304			304


DILUTED EARNINGS PER SHARE OF COMMON STOCK	$	0.77		$	1.54		$	2.51		$	3.29


WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		306			307			306			307


DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.10		$	1.10		$	1.65		$	1.65


* Includes excise tax collections of $106 million and $115 million in the three months ended September 30, 2009 and 2008, respectively,
and $310 million and $329 million in the nine months ended September 2009 and 2008, respectively.

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

	September 30, 2009(1)								December 31, 2008(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
Debt securities	(In millions)
FirstEnergy(3)	$	576	$	25	$	-	$	601	$	1,078	$	56	$	-	$	1,134
FES		7		1		-		8		401		28		-		429
OE		2		-		-		2		86		9		-		95
TE		-		-		-		-		66		8		-		74
JCP&L		266		13		-		279		249		9		-		258
Met-Ed		121		6		-		127		111		4		-		115
Penelec		180		5		-		185		164		3		-		167

Equity securities
FirstEnergy	$	245	$	33	$	-	$	278	$	589	$	39	$	-	$	628
FES		-		-		-		-		355		25		-		380
OE		-		-		-		-		17		1		-		18
JCP&L		72		8		-		80		64		2		-		66
Met-Ed		114		18		-		132		101		9		-		110
Penelec		59		7		-		66		51		2		-		53

(1) Excludes cash balances of $1,291 million at FirstEnergy, $1,094 million at FES, $2 million at JCP&L, $120 million at OE, $5 million at Penelec and $75 million at TE. (2) Excludes cash balances of $244 million at FirstEnergy, $225 million at FES, $12 million at Penelec, $4 million at OE and $1 million at Met-Ed. (3) Includes fair values as of September 30, 2009 and December 31, 2008 of $557 million and $953 million of government obligations, $44 million and $175 million of corporate debt and $1 million and $6 million of mortgage backed securities.

Recurring Fair Value Measures as of September 30, 2009
		Level 1 - Assets								Level 1 - Liabilities
	(In millions)
		Derivatives		Available-for- Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	278	$	-	$	278	$	15	$	-	$	15
FES		-		1		-		1		15		-		15
OE		-		-		-		-		-		-		-
JCP&L		-		81		-		81		-		-		-
Met-Ed		-		125		-		125		-		-		-
Penelec		-		71		-		71		-		-		-

		Level 2 - Assets								Level 2 - Liabilities
		Derivatives		Available-for- Sale Securities(1)		Other Investments		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	32	$	1,896	$	78	$	2,006	$	6	$	-	$	6
FES		13		1,103		-		1,116		5		-		5
OE		-		123		-		123		-		-		-
TE		-		75		-		75		-		-		-
JCP&L		5		276		-		281		-		-		-
Met-Ed		9		134		-		143		-		-		-
Penelec		5		185		-		190		-		-		-

		Level 3 - Assets								Level 3 - Liabilities
		Derivatives		Available-for- Sale Securities(1)		NUG Contracts(2)		Total		Derivatives		NUG Contracts(2)		Total
FirstEnergy	$	-	$	-	$	220	$	220	$	-	$	685	$	685
JCP&L		-		-		9		9		-		425		425
Met-Ed		-		-		187		187		-		152		152
Penelec		-		-		24		24		-		108		108

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

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

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

	Three Months Ended September 30									Nine Months Ended September 30
Derivatives Not in Hedging Relationships		NUG									NUG
		Contracts			Other			Total			Contracts			Other		Total
2009	(In millions)
Unrealized Gain (Loss) Recognized in:
Fuel Expense(1)	$	-		$	(1	)	$	(1	)	$	-		$	2	$	2
Regulatory Assets(2)		(22	)		-			(22	)		(406	)		-		(406	)
	$	(22	)	$	(1	)	$	(23	)	$	(406	)	$	2	$	(404	)
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)	$	-		$	1		$	1		$	-		$	-	$	-
Regulatory Assets(2)		(93	)		-			(93	)		(273	)		11		(262	)
	$	(93	)	$	1		$	(92	)	$	(273	)	$	11	$	(262	)
2008
Unrealized Gain (Loss) Recognized in:
Fuel Expense(1)	$	-		$	2		$	2		$	-		$	2	$	2
Regulatory Assets(2)		(362	)		1			(361	)		314			1		315
	$	(362	)	$	3		$	(359	)	$	314		$	3	$	317
Realized Gain (Loss) Reclassified to:
Fuel Expense(1)	$	-		$	1		$	1		$	-		$	1	$	1
Regulatory Assets(2)		(57	)		1			(56	)		(167	)		11		(156	)
	$	(57	)	$	2		$	(55	)	$	(167	)	$	12	$	(155	)

(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.

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,371	$	1,193	$	178
OE	729		561		168
CEI(2)	670		74		596
TE(2)	670		383		287

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

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

REVENUES	$	1,087,991		$	477,679		$	170,129		$	(631,227	)	$	1,104,572

EXPENSES:
Fuel		9,278			241,953			43,462			-			294,693
Purchased power from non-affiliates		205,200			-			-			-			205,200
Purchased power from affiliates		621,996			9,233			35,290			(631,229	)		35,290
Other operating expenses		70,246			109,828			113,669			12,192			305,935
Provision for depreciation		1,051			30,469			35,832			(1,311	)		66,041
General taxes		4,351			11,331			6,018			-			21,700
Total expenses		912,122			402,814			234,271			(620,348	)		928,859

OPERATING INCOME		175,869			74,865			(64,142	)		(10,879	)		175,713

OTHER INCOME (EXPENSE):
Investment income		35			319			158,503			-			158,857
Miscellaneous income, including net income
from equity investees		100,668			744			1			(98,609	)		2,804
Interest expense - affiliates		(35	)		(1,267	)		(907	)		-			(2,209	)
Interest expense - other		(15,358	)		(26,737	)		(16,205	)		16,113			(42,187	)
Capitalized interest		49			15,381			2,439			-			17,869
Total other income (expense)		85,359			(11,560	)		143,831			(82,496	)		135,134

INCOME BEFORE INCOME TAXES		261,228			63,305			79,689			(93,375	)		310,847

INCOME TAXES		61,545			19,646			27,801			2,172			111,164

NET INCOME	$	199,683		$	43,659		$	51,888		$	(95,547	)	$	199,683

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of September 30, 2009	FES		FGCO		NGC		Eliminations			Consolidated
	(In thousands)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	266,859	$	99	$	-	$	-		$	266,958
Receivables-
Customers		155,489		-		-		-			155,489
Associated companies		278,670		186,263		106,551		(227,097	)		344,387
Other		15,310		12,858		19,411		-			47,579
Notes receivable from associated companies		134,283		200,692		93,041		-			428,016
Materials and supplies, at average cost		9,925		304,358		213,995		-			528,278
Prepayments and other		90,377		19,064		10,921		-			120,362
		950,913		723,334		443,919		(227,097	)		1,891,069

PROPERTY, PLANT AND EQUIPMENT:
In service		90,179		5,508,790		5,041,783		(386,054	)		10,254,698
Less - Accumulated provision for depreciation		12,590		2,785,417		1,860,060		(170,235	)		4,487,832
		77,589		2,723,373		3,181,723		(215,819	)		5,766,866
Construction work in progress		4,179		1,830,141		361,679		-			2,195,999
		81,768		4,553,514		3,543,402		(215,819	)		7,962,865

INVESTMENTS:
Nuclear plant decommissioning trusts		-		-		1,101,884		-			1,101,884
Investment in associated companies		4,327,059		-		-		(4,327,059	)		-
Long-term notes receivable from associated companies		-		-		8,817		-			8,817
Other		1,320		25,121		201		-			26,642
		4,328,379		25,121		1,110,902		(4,327,059	)		1,137,343
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes		12,331		391,899		-		(366,131	)		38,099
Lease assignment receivable from associated companies		-		71,356		-		-			71,356
Goodwill		24,248		-		-		-			24,248
Property taxes		-		27,494		22,610		-			50,104
Unamortized sale and leaseback costs		-		2,938		-		55,412			58,350
Other		194,916		68,278		16,619		(53,679	)		226,134
		231,495		561,965		39,229		(364,398	)		468,291
	$	5,592,555	$	5,863,934	$	5,137,452	$	(5,134,373	)	$	11,459,568

LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	726	$	697,986	$	951,240	$	(18,186	)	$	1,631,766
Short-term borrowings-
Associated companies		-		-		-		-			-
Other		100,000		-		-		-			100,000
Accounts payable-
Associated companies		130,669		212,778		234,626		(190,891	)		387,182
Other		30,890		125,163		-		-			156,053
Accrued taxes		114,043		29,489		16,791		(54,749	)		105,574
Other		41,828		120,107		27,772		38,081			227,788
		418,156		1,185,523		1,230,429		(225,745	)		2,608,363

CAPITALIZATION:
Common stockholder's equity		3,607,283		2,252,002		2,054,817		(4,306,819	)		3,607,283
Long-term debt and other long-term obligations		1,519,585		1,865,313		533,990		(1,278,796	)		2,640,092
		5,126,868		4,117,315		2,588,807		(5,585,615	)		6,247,375

NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		-		-		-		1,001,298			1,001,298
Accumulated deferred income taxes		-		-		324,311		(324,311	)		-
Accumulated deferred investment tax credits		-		37,129		22,350		-			59,479
Asset retirement obligations		-		25,011		881,188		-			906,199
Retirement benefits		32,043		168,054		-		-			200,097
Property taxes		-		27,494		22,610		-			50,104
Lease market valuation liability		-		273,624		-		-			273,624
Other		15,488		29,784		67,757		-			113,029
		47,531		561,096		1,318,216		676,987			2,603,830
	$	5,592,555	$	5,863,934	$	5,137,452	$	(5,134,373	)	$	11,459,568

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

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

NET CASH PROVIDED FROM OPERATING ACTIVITIES	$	(37,990	)	$	520,169		$	408,364		$	(8,732	)	$	881,811

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		1,498,087			524,710			333,965			-			2,356,762
Equity contributions from parent		-			100,000			150,000			(250,000	)		-
Redemptions and Repayments-
Long-term debt		(1,507	)		(258,583	)		(366,857	)		8,734			(618,213	)
Short-term borrowings, net		(901,119	)		(257,357	)		(6,347	)		-			(1,164,823	)
Other		(11,583	)		(5,261	)		(3,160	)		(2	)		(20,006	)
Net cash provided from financing activities		583,878			103,509			107,601			(241,268	)		553,720

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,224	)		(439,531	)		(400,845	)		-			(842,600	)
Proceeds from asset sales		-			16,129			-			-			16,129
Sales of investment securities held in trusts		-			-			2,152,717			-			2,152,717
Purchases of investment securities held in trusts		-			-			(2,175,135	)		-			(2,175,135	)
Loan to associated companies, net		(27,054	)		(178,746	)		(93,041	)		-			(298,841	)
Investment in subsidiary		(250,000	)		-			-			250,000			-
Other		249			(21,470	)		339			-			(20,882	)
Net cash used for investing activities		(279,029	)		(623,618	)		(515,965	)		250,000			(1,168,612	)

Net change in cash and cash equivalents		266,859			60			-			-			266,919
Cash and cash equivalents at beginning of period		-			39			-			-			39
Cash and cash equivalents at end of period	$	266,859		$	99		$	-		$	-		$	266,958

Change in Basic Earnings Per Share From Prior Year Periods	Three Months Ended September 30				Nine Months Ended September 30

Basic Earnings Per Share – 2008		$	1.55			$	3.32
Gain on non-core asset sales		-				0.46
Litigation settlement – 2008		-				(0.03		)
Debt redemption premium - 2009		(0.30		)		(0.30		)
Organizational restructuring costs – 2009		(0.07		)		(0.14		)
Regulatory charges – 2009		-				(0.55		)
Investment Income		0.17				0.12
Trust securities impairments		0.08				0.08
Income tax adjustments		(0.12		)		(0.09		)
Revenues (excluding asset sales)		(1.04		)		(1.29		)
Fuel and purchased power		0.10				0.03
Transmission costs		0.30				0.56
Amortization of regulatory assets, net		(0.06		)		(0.03		)
Other expenses		0.16				0.38
Basic Earnings Per Share – 2009		$	0.77			$	2.52

	Nine Months
	Ended September 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Distribution services	$	2,578	$	2,974	$	(396	)
Generation sales:
Retail		2,355		2,548		(193	)
Wholesale		545		758		(213	)
Total generation sales		2,900		3,306		(406	)
Transmission		616		633		(17	)
Other		142		138		4
Total Revenues	$	6,236	$	7,051	$	(815	)

	Increase
Sources of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of 8% decrease in sales volumes	$	(208	)
Change in prices		15
		(193	)
Wholesale:
Effect of 14% decrease in sales volumes		(108	)
Change in prices		(105	)
		(213	)
Net Decrease in Generation Revenues	$	(406	)

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,553
FGCO and NGC unsecured PCRBs(1)	97
CEI secured notes(2)	150
Met-Ed unsecured notes(3)	100
Penelec unsecured notes(4)	35
NGC collateralized lease obligation bonds	44
Sinking fund requirements	41
	$	2,020

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

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

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

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

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

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

FES	08/07/2009	$400 $600 $500	4.80% Senior Notes 6.05% Senior Notes 6.80% Senior Notes	2015 2021 2039	Repay short-term borrowings and other general purposes

CEI*	08/18/2009	$300	5.50% FMB	2024	$150M placed with trustee for future debt redemption, repay short-term borrowings and other general purposes

Penelec*	9/30/2009	$250 $250	5.20% Senior Notes 6.15% Senior Notes	2020 2038	Repay short-term borrowings

* Issued under the shelf registration statement referenced above.

Balance Sheet Classification	Non-Hedge		Hedge		Total
	(In millions)
Current-
Other assets	$	-	$	13	$	13
Other liabilities		-		(18)		(18)

Non-Current-
Other deferred charges		239		-		239
Other non-current liabilities		(685)		(3)		(688)
Net liabilities	$	(446)	$	(8)	$	(454)

Source of Information
- Fair Value by Contract Year	2009(1)		2010			2011			2012			2013			Thereafter		Total
	(In millions)
Prices actively quoted(2)	$	(2)	$	(13	)	$	-		$	-		$	-		$	-	$	(15	)
Other external sources(3)		(64)		(251	)		(209	)		(129	)		-			-		(653	)
Prices based on models		-		-			-			-			(1	)		217		216
Total	$	(66)	$	(264	)	$	(209	)	$	(129	)	$	(1	)	$	217	$	(452	)

	September 30, 2009							December 31, 2008
	Notional		Maturity		Fair			Notional		Maturity		Fair
Forward Starting Swaps	Amount		Date		Value			Amount		Date		Value
	(In millions)
Cash flow hedges	$	100		2009	$	(1	)	$	100		2009	$	(2	)
		100		2010		(1	)		100		2010		(2	)
		-		2019		-			100		2019		1
	$	200			$	(2	)	$	300			$	(3	)

	September 30,		December 31,		Increase
Regulatory Assets	2009		2008		(Decrease)
	(In millions)
OE	$	494	$	575	$	(81	)
CEI		592		784		(192	)
TE		77		109		(32	)
JCP&L		950		1,228		(278	)
Met-Ed		404		413		(9	)
Penelec*		3		-		3
ATSI		23		31		(8	)
Total	$	2,543	$	3,140	$	(597	)

Expenses – Changes	Increase (Decrease)
		(In millions)
Purchased power costs	$	248
Other operating costs		(51	)
Provision for depreciation		8
Amortization of regulatory assets, net		(28	)
General taxes		(6	)
Net Increase in Expenses	$	171

	Period
	July	August	September	Third Quarter
Total Number of Shares Purchased (a)	30,128	108,110	367,075	505,313
Average Price Paid per Share	$39.05	$45.21	$45.46	$45.02
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	-	-	-	-