UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C.  20549

FORM 10-Q

(Mark One)

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

SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2009

OR

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

SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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

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

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

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

Yes (X) No (  ) FirstEnergy Corp.

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

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

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

Smaller Reporting Company (  ) N/A

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

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

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

	OUTSTANDING
CLASS	AS OF Novembe 6, 2009
FirstEnergy Corp., $0.10 par value	304,835, 407
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
The Cleveland Electric Illuminating Company, no par value	67,930,743
The Toledo Edison Company, $5 par value	29,402,054
Jersey Central Power & Light Company, $10 par value	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.

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 Ohio Companies associated with the distribution rate case.

·   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.

·   Operating and maintenance costs being higher than anticipated.

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

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

·   The uncertainty of the timing and amounts of the capital expenditures needed to, among other things, implement the Air Quality Compliance Plan (including that such amounts could be higher than anticipated or that certain generating units may need to be shut down) or levels of emission reductions related to the Consent Decree resolving the NSR litigation or other potential 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.

·   Met-Ed’s and Penelec’s transmission service charge 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.

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

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

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

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

·   Changes in general economic conditions affecting the registrants.

·   The state of the capital and credit markets affecting the registrants.

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

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

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

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

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

TABLE OF CONTENTS

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

i

TABLE OF CONTENTS (Cont'd)

	Pages
Combined Notes To Consolidated Financial Statements	26-65
Report of Independent Registered Public Accounting Firm
FirstEnergy Corp.	66
FirstEnergy Solutions Corp.	67
Ohio Edison  Company	68
The Cleveland Electric Illuminating Company	69
The Toledo Edison Company	70
Jersey Central Power & Light Company	71
Metropolitan Edison Company	72
Pennsylvania Electric Company	73
Item 2.   Management's Discussion and Analysis of Registrant and Subsidiaries	74-118
Management's Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	119-121
Ohio Edison Company	122-123
The Cleveland Electric Illuminating Company	124-125
The Toledo Edison Company	126-127
Jersey Central Power & Light Company	128-129
Metropolitan Edison Company	130-131
Pennsylvania Electric Company	132-133
Item 3.    Quantitative and Qualitative Disclosures About Market Risk	134
Item 4.    Controls and Procedures – FirstEnergy	134
Item 4T.  Controls and Procedures – FES, OE, CEI, TE, JCP&L, Met-Ed and Penelec	134
Part II.     Other Information
Item 1.    Legal Proceedings	135
Item 1A. Risk Factors	135
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds	135
Item 5.    Other Information	135
Item 6.    Exhibits	136-137

ii

GLOSSARY OF TERMS

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

ATSI	American Transmission Systems, Incorporated, owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC	FirstEnergy Nuclear Operating Company, operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., provides energy-related products and services
FESC	FirstEnergy Service Company, provides legal, financial and other corporate support services
FEV	FirstEnergy Ventures Corp., invests in certain unregulated enterprises and business ventures
FGCO	FirstEnergy Generation Corp., owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, which merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
JCP&L Transition    Funding	JCP&L Transition Funding LLC, a Delaware limited liability company and issuer of transition bonds
JCP&L Transition    Funding II	JCP&L Transition Funding II LLC, a Delaware limited liability company and issuer of transition bonds
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
NGC	FirstEnergy Nuclear Generation Corp., owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
Penelec	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	Met-Ed, Penelec and Penn
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shelf Registrants	OE, CEI, TE, JCP&L, Met-Ed and Penelec
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FirstEnergy Ventures Corp. and Boich Companies, that owns mining and    coal transportation operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed and Penelec
Waverly	The Waverly Power and Light Company, a wholly owned subsidiary of Penelec
The following abbreviations and acronyms are used to identify frequently used terms in this report:
AEP	American Electric Power Company, Inc.
ALJ	Administrative Law Judge
AMP-Ohio	American Municipal Power-Ohio, Inc.
AOCL	Accumulated Other Comprehensive Loss
AQC	Air Quality Control
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CBP	Competitive Bid Process
CO2	Carbon Dioxide
CTC	Competitive Transition Charge
DOJ	United States Department of Justice
DPA	Department of the Public Advocate, Division of Rate Counsel (New Jersey)
EE&C	Energy Efficiency and Conservation
EMP	Energy Master Plan
EPA	United States Environmental Protection Agency
EPACT	Energy Policy Act of 2005
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FMB	First Mortgage Bond
GAAP	Accounting Principles Generally Accepted in the United States
GHG	Greenhouse Gases

iii

GLOSSARY OF TERMS, Cont'd.

IRS	Internal Revenue Service
kV	Kilovolt
KWH	Kilowatt-hours
LED	Light-emitting Diode
LIBOR	London Interbank Offered Rate
LOC	Letter of Credit
MISO	Midwest Independent Transmission System Operator, Inc.
Moody's	Moody's Investors Service, Inc.
MRO	Market Rate Offer
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NOV	Notice of Violation
NOX	Nitrogen Oxide
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYMEX	New York Mercantile Exchange
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OVEC	Ohio Valley Electric Corporation
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection L. L. C.
PLR	Provider of Last Resort; an electric utility's obligation to provide generation service to customers    whose alternative supplier fails to deliver service
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PUCO	Public Utilities Commission of Ohio
QSPE	Qualifying Special-Purpose Entity
RCP	Rate Certainty Plan
RFP	Request for Proposal
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor's Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SECA	Seams Elimination Cost Adjustment
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	Voluntary Enhanced Retirement Option
VIE	Variable Interest Entity

iv

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.

1

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.

2

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.

3

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.

4

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.

5

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.

6

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.

7

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.

8

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.

9

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.

10

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.

11

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.

12

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.

13

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.

14

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.

15

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.

16

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.

17

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.

18

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.

19

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.

20

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.

21

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.

22

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.

23

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.

24

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.

25

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

FirstEnergy and its subsidiaries follow GAAP and comply with the regulations, orders, policies and practices prescribed by the SEC, the FERC and, as applicable, the PUCO, the PPUC and the NJBPU. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period. 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 for FirstEnergy, FES and the Utilities. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utilities reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE (see Note 7) when it is determined to be the VIE's primary beneficiary. Investments in non-consolidated affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but not control (20-50% owned companies, joint ventures and partnerships) follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity's earnings is reported in the Consolidated Statements of Income.

The consolidated financial statements as of September 30, 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 computed using the weighted average of actual common shares outstanding during the respective period as the denominator. The denominator for diluted earnings per share of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

	Three Months Ended				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

26

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

All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported on the Consolidated Balance Sheets at cost, which approximates their fair market value, in the caption "short-term borrowings." The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations as of September 30, 2009 and December 31, 2008:

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy	$	13,675	$	14,483	$	11,585	$	11,146
FES		4,233		4,304		2,552		2,528
OE		1,169		1,318		1,232		1,223
CEI		1,900		2,033		1,741		1,618
TE		600		656		300		244
JCP&L		1,849		1,977		1,569		1,520
Met-Ed		842		911		542		519
Penelec		1,179		1,221		779		721

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

(B) INVESTMENTS

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

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.

27

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities as of September 30, 2009 and December 31, 2008:

	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 $1million 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 period ended September 30, 2009 were as follows:

	FirstEnergy		FES		OE		TE		JCP&L		Met-Ed		Penelec
	(In millions)
Proceeds from sales	$	3,040	$	2,153	$	207	$	171	$	339	$	89	$	81
Realized gains		186		162		11		7		4		1		1
Realized losses		96		62		3		-		11		13		7
Interest and dividend income		47		22		4		2		10		5		4

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 investments of $271 million and $293 million that are not required to be disclosed) as of September 30, 2009 and December 31, 2008:

	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

28

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

	September 30, 2009				December 31, 2008
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
Notes receivable	(In millions)
FirstEnergy	$	45	$	42	$	45	$	44
FES		4		4		75		74
OE		193		234		257		294
TE		161		180		180		189

The fair value of notes receivable represents the present value of the cash inflows based on the yield to maturity. The yields assumed were based on financial instruments with similar characteristics and terms. The maturity dates range from 2009 to 2040.

(C) RECURRING FAIR VALUE MEASUREMENTS

FirstEnergy's valuation techniques, including the three levels of the fair value hierarchy, are disclosed in Note 5 of the Notes to Consolidated Financial Statements in FirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2008.

The following tables set forth financial assets and financial liabilities that are accounted for at fair value by level within the fair value hierarchy as of September 30, 2009 and December 31, 2008. Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. FirstEnergy's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair valuation of assets and liabilities and their placement within the fair value hierarchy levels.

Recurring Fair Value Measures as of 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

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

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

29

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 million of receivables, payables and accrued income.

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

The determination of the above fair value measures takes into consideration various factors. 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 months ended September 30, 2009 and 2008 (in millions):

	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)

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

30

	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. DERIVATIVE INSTRUMENTS

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

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchase and normal sales criteria. Derivatives that meet those criteria are accounted for at cost. The changes in the fair value of derivative instruments that do not meet the normal purchase and normal sales criteria are included in other expense, unrealized gain (loss) on derivative hedges in other comprehensive income (loss), or as part of the value of the hedged item.

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. 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 forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. 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 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:

31

		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 hedges totaled $94 million ($57million net of tax) as of September 30, 2009. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. FirstEnergy’s interest rate swaps do not include any contingent credit risk related features.

Commodity Derivatives

FirstEnergy uses both physically and financially settled derivatives to manage its exposure to volatility in commodity prices. Commodity derivatives are used for risk management purposes to hedge exposures when it makes economic sense to do so, including circumstances in which the hedging relationship does not qualify for hedge accounting. Derivatives that do not qualify under the normal purchase or sales criteria or for hedge accounting as cash flow hedges 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
			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

32

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 30, 2009.

	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 months ended September 30, 2009 and 2008, for instruments designated in cash flow hedging relationships and not in hedging relationships, respectively, are summarized in the following tables:

Derivatives in Cash Flow Hedging Relationships			Electricity			Natural Gas			Heating Oil
			Forwards			Futures			Futures			Total
Three Months Ended 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.

	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.

33

Total unamortized losses included in AOCL associated with commodity derivatives were $9 million ($5 million net of tax) as of September 30, 2009, as compared to $44 million ($27 million net of tax) as of December 31, 2008. The net of tax change resulted from a net $7 million decrease related to current hedging activity and a $15 million decrease due to net hedge losses reclassified to earnings during the first nine months of 2009. Based on current estimates, approximately $3million (after tax) of the net deferred losses on derivative instruments in AOCL as of September 30, 2009 are expected to be reclassified to earnings during the next twelve months as hedged transactions occur. The fair value of these derivative instruments fluctuate from period to period based on various market factors.

Many of FirstEnergy’s commodity derivatives contain credit risk features. As of September 30, 2009, FirstEnergy posted $133 million of collateral related to net liability positions and held no counterparties’ funds related to asset positions. The collateral FirstEnergy has posted relates to both derivative and non-derivative contracts. FirstEnergy’s largest derivative counterparties fully collateralize all derivative transactions. Certain commodity derivative contracts include credit risk-related contingent features that would require FirstEnergy to post additional collateral if the credit rating for its debt were to fall below investment grade. The aggregate fair value of derivative instruments with credit risk-related contingent features that are in a liability position on September 30, 2009 was $2million, for which $106 million in collateral has been posted. If FirstEnergy’s credit rating were to fall below investment grade, it would be required to post $18 million of additional collateral related to commodity derivatives.

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

34

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

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

	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	)

35

7. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries consolidate VIEs when they are determined to be the VIE's primary beneficiary. 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 ($14 million), the acquisition of additional interest in certain joint ventures ($13 million), and distributions to owners ($4 million).

Mining Operations

On July 16, 2008, FEV entered into a joint venture with the Boich Companies, a Columbus, Ohio-based coal company, to acquire a majority stake in the Signal Peak mining and coal transportation operations near Roundup, Montana. FEV made a $125 million equity investment in the joint venture, which acquired 80% of the mining operations (Signal Peak Energy, LLC) and 100% of the transportation operations, with FEV owning a 45% economic interest and an affiliate of the Boich Companies owning a 55% economic interest in the joint venture. Both parties have a 50% voting interest in the joint venture. In March 2009, FEV agreed to pay a total of $8.5 million to affiliates of the Boich Companies to purchase an additional 5% economic interest in the Signal Peak mining and coal transportation operations. Voting interests remained unchanged after the sale was completed in July 2009. Effective 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 created in 1996 and 1997, respectively, to refinance debt originally issued in connection with sale and leaseback transactions. PNBV and Shippingport financial data are included in the consolidated financial statements of OE and CEI, respectively.

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

Loss Contingencies

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

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

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

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

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.

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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.

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8. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Accounting guidance prescribes a recognition threshold and measurement attribute for financial statement recognition and measurement of tax positions taken or expected to be taken on a company's tax return. 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 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 be resolved within the next twelve months, of which approximately $148 million, if recognized, would affect FirstEnergy's effective tax rate. The potential decrease in the amount of unrecognized tax benefits is primarily associated with issues related to the capitalization of certain costs, gains and losses recognized on the disposition of assets and various other tax items.

The Company recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The reversal of accrued interest associated with the $45 million in recognized tax benefits in 2008 favorably affected FirstEnergy’s effective tax rate by $12 million in the third quarter and first nine months of 2008. During the first nine months of 2009, there were no material changes to the amount of interest accrued. The net amount of accumulated interest accrued as of September 30, 2009 was $67million, as compared to $59 million as of December 31, 2008.

In 2008, FirstEnergy, on behalf of FGCO and NGC, filed a change in accounting method related to the costs to repair and maintain electric generation stations. During the second quarter of 2009, the IRS approved 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.

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 under appeal. The federal audits for the years 2004-2006 were completed in 2008 and several items are under appeal. The IRS began auditing the year 2007 in February 2007 under its Compliance Assurance Process program and was completed in the first quarter of 2009 with two items under appeal. The IRS began auditing the year 2008 in February 2008 and the year 2009 in February 2009 under its Compliance Assurance Process program. Neither audit is expected to close before December 2009. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy's financial condition or results of operations.

9. COMMITMENTS, GUARANTEES AND CONTINGENCIES

(A)    GUARANTEES AND OTHER ASSURANCES

As part of normal business activities, FirstEnergy enters into various agreements on behalf of its subsidiaries to provide financial or performance assurances to third parties. These agreements include contract guarantees, surety bonds and LOCs. As of September 30, 2009, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting primarily of parental guarantees ($1billion), subsidiaries’ guarantees ($2.6billion), surety bonds ($0.1 billion) and LOCs ($0.4billion).

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 obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy's guarantee enables the counterparty's legal claim to be satisfied by other FirstEnergy assets. The likelihood is remote that such parental guarantees of $0.4 billion (included in the $1 billion shown above) as of September 30, 2009 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

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While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2009, FirstEnergy's maximum exposure under these collateral provisions was $616 million, consisting of $53 million due to “material adverse event” contractual clauses and $563 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 million, consisting of $60 million due to “material adverse event” contractual clauses and $639 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 $103 million provide additional assurance to outside parties that contractual and statutory obligations will be met in a number of areas including construction contracts, environmental commitments and various retail transactions.

In addition to guarantees and surety bonds, FES’ contracts, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions which require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ contracts as of September 30, 2009, and forward prices as of that date, FES had $183 million of outstanding collateral payments of which $134 million is included in other assets on the Consolidated Balance Sheet as of September 30, 2009. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease in prices thereafter), FES would be required to post an additional $45 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 amount of approximately $500 million. The 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 guarantees entered into on March 26, 2007. Similar guarantees were entered into on that date pursuant to which FES guaranteed the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC will have claims against each of FES, FGCO and NGC regardless of whether their primary obligor is FES, FGCO or NGC.

(B)     ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $800 million for the period 2009-2013.

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

Clean Air Act Compliance

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

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 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 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 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 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 of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009, and on September 30, 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.

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On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.

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. On August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air Act and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (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 request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provision of the CAA. FGCO intends to comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 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. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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Mercury Emissions

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

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at 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. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources. 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 would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.

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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.  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 (5th Cir. 2009)(seeking damages only), respectively.  While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be affirmed, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. EPA is developing a new regulation under Section 316(b) of the Clean Water Act consistent with the opinions of the Supreme Court and the Court of Appeals which have created significant uncertainty about the specific nature, scope and timing of the final performance standard. FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, 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 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 could have a significant impact on our management, beneficial use, and disposal, of coal ash. FGCO's future cost of compliance with any coal combustion waste 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 states.

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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 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L - $77 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through September 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

(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 territory. Two class action lawsuits (subsequently consolidated into a single proceeding) were filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU companies, seeking compensatory and punitive damages due to the outages.

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

Nuclear Plant Matters

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. 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.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2009, 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 the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. 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.

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Other Legal Matters

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. 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.

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

10. REGULATORY MATTERS

(A)    RELIABILITY INITIATIVES

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

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

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

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

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

(B)    OHIO

On June 7, 2007, the Ohio Companies filed an application for an increase in electric distribution rates with the PUCO and, on August 6, 2007, updated their filing 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 at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

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On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved 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. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.

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.

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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, 2020. Under a determination that such statutory requirements were met, the Ohio Companies would be able to implement the MRO and conduct the CBP

(C)    PENNSYLVANIA

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

On 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.

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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 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, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order 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 filed reply comments on October 26, 2009, and await the decision of the PPUC.

(D)    NEW JERSEY

JCP&L is permitted to defer for future collection from customers the amounts by which its costs of supplying BGS to non-shopping customers, costs incurred under NUG agreements, and certain other stranded costs, exceed amounts collected through BGS and NUGC rates and market sales of NUG energy and capacity. As of September 30, 2009, the accumulated deferred cost balance totaled approximately $102 million.

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

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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 to be filed with the BPU by July 1, 2010. At this time, FirstEnergy and JCP&L cannot determine the impact, if any, the EMP may have on their operations.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. 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 on August 19, 2009, and implementation will begin in 2009. 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.

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PJM Transmission Rate

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

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

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On September 17, 2007, AEP filed a complaint under Sections 206 and 306 of the Federal Power Act seeking to have the entire transmission rate design and cost allocation methods used by MISO and PJM declared unjust, unreasonable, and unduly discriminatory, and to have the FERC fix a uniform regional transmission rate design and cost allocation method for the entire MISO and PJM “Super Region” that recovers the average cost of new and existing transmission facilities operated at voltages of 345 kV and above from all transmission customers. Lower voltage facilities would continue to be recovered in the local utility transmission rate zone through a license plate rate. AEP requested a refund effective October 1, 2007, or alternatively, February 1, 2008. On January 31, 2008, the FERC issued an order denying the complaint. The effect of this order is to prevent the shift of significant costs to the FirstEnergy zones in MISO and PJM. A rehearing request by AEP was denied by the FERC on December 19, 2008. On February 17, 2009, AEP appealed the FERC’s January 31, 2008, and December 19, 2008, orders to the U.S. Court of Appeals for the Seventh Circuit. FESC, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Opinion 494 appeal discussed above. Now that the Seventh Circuit has ruled on the Opinion 494 case, AEP and FERC have until November 11, 2009, to advise the Seventh Circuit of any changes to their litigation positions that result from or reflect the Seventh Circuit’s decision in the Opinion 494 case.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM.

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 and the related complaint 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’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 PJM Reliability Pricing Model (RPM) Auction

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

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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 the reserve margin requirement for load-serving entities based upon a one day loss of load in ten years standard, unless the state utility regulatory agency establishes a different planning reserve for load-serving entities in its state. FirstEnergy believes the proposal promotes a mechanism that will result in commitments from both load-serving entities and resources, including both generation and demand side resources that are necessary for reliable resource adequacy and planning in the MISO footprint. Comments on the filing were submitted on January 28, 2008. The FERC conditionally approved MISO’s Resource Adequacy proposal on March 26, 2008, requiring MISO to submit to further compliance filings. Rehearing requests are pending on the FERC’s March 26 Order. On May 27, 2008, MISO submitted a compliance filing to address issues associated with planning reserve margins. On June 17, 2008, various parties submitted comments and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific issues that must be clarified and addressed. On June 25, 2008, MISO submitted a second compliance filing establishing the enforcement mechanism for the reserve margin requirement which establishes deficiency payments for load-serving entities that do not meet the resource adequacy requirements. Numerous parties, including FirstEnergy, protested this filing.

On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify. On October 23, 2009, FERC issued an order approving a MISO compliance filing that revised its tariff to provide for netting of demand resources, but prohibiting the netting of behind-the-meter generation.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 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.

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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 (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.

11. 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, the FASB amended the derecognition guidance in the Transfers and Servicing Topic of the FASB Accounting Standards Codification and eliminated the concept of a QSPE. The amended guidance 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 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.

In August 2009, the FASB updated the Fair Value Measurement and Disclosures Topic, which provides guidance 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." FES and the Utilities do not have separate reportable operating segments.

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

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

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

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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

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.

56

13. SUPPLEMENTAL GUARANTOR INFORMATION

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

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

57

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

58

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

59

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

60

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

61

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

62

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

63

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

64

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

65

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of

Directors of FirstEnergy Corp.:

We have reviewed the accompanying consolidated balance sheet of FirstEnergy Corp. and its subsidiaries as of September 30, 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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, common stockholders’ equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

66

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

67

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

68

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

69

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. As discussed in Note 7 to the accompanying consolidated financial statements, the Company changed its reporting related to noncontrolling interest. The accompanying December 31, 2008 consolidated balance sheet reflects this change.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

70

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

71

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

72

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.

We conducted our review in accordance with the standards of the Public Company Accounting Oversight Board (United States). A review of interim financial information consists principally of applying analytical procedures and making inquiries of persons responsible for financial and accounting matters. It is substantially less in scope than an audit conducted in accordance with the standards of the Public Company Accounting Oversight Board (United States), the objective of which is the expression of an opinion regarding the financial statements taken as a whole. Accordingly, we do not express such an opinion.

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

We previously audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet as of December 31, 2008, and the related consolidated statements of income, capitalization, common stockholder's equity, and cash flows for the year then ended (not presented herein), and in our report dated February 24, 2009, we expressed an unqualified opinion on those consolidated financial statements. In our opinion, the information set forth in the accompanying consolidated balance sheet information as of December 31, 2008, is fairly stated in all material respects in relation to the consolidated balance sheet from which it has been derived.

PricewaterhouseCoopers LLP

Cleveland, Ohio

November 6, 2009

73

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

FIRSTENERGY CORP.

MANAGEMENT'S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Net income in the third quarter of 2009 was $234 million, or basic and diluted earnings of $0.77 per share of common stock, compared with net income of $471 million, or basic earnings of $1.55 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 $768 million or basic earnings of $2.52per share of common stock ($2.51 diluted), compared with net income of $1.01 billion, or basic earnings of $3.32 per share of common stock ($3.29diluted) in the first nine months 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, 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 forecasting 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.

74

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.

75

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 cost to complete the project to be $180 million.

Nuclear Outage

On October 12, 2009, NGC's Beaver Valley Nuclear Power Station Unit 2, located in Shippingport, Pennsylvania began a scheduled refueling 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 filed an application with the FERC 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 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 customers with the benefits of a more fully developed retail choice market, and 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 filed an application for economic stimulus funding with the U.S. Department of Energy under the American Recovery and Reinvestment Act that proposed investing $114 million on smart grid technologies to improve the reliability and interactivity of its electric distribution infrastructure in its three-state service area. The application requested $57 million, which represents half of the funding needed for targeted projects in communities served by the Utilities. On October 27, 2009, 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.

76

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 issuance 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 portion of the proceeds will  be used to replace $150 million of CEI’s 7.43% Series D Secured Notes that mature on November 1, 2009. The remaining proceeds were used to repay a portion of CEI’s short-term borrowings.

On September 2, 2009, the Utilities and ATSI voluntarily contributed $500 million to the pension plan. On September 30, 2009, Penelec issued $500 million 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 $52.1million and $29.6million of PCRBs subject to mandatory purchase. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs in the near future.

FIRSTENERGY'S BUSINESS

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

·   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 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 business segments. A reconciliation of segment financial results is provided in Note 12 to the consolidated financial statements. Earnings by major business segment were as follows:

77

	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 Quarter 2009 Compared with Third Quarter 2008

Financial results for FirstEnergy's major business segments in the third quarter of 2009 and 2008 were as follows:

							Ohio
	Energy			Competitive			Transitional			Other and
	Delivery			Energy			Generation			Reconciling			FirstEnergy
Third Quarter 2009 Financial Results	Services			Services			Services			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,067		$	444		$	737		$	-		$	3,248
Other		136			46			2			(24	)		160
Internal		-			617			-			(617	)		-
Total Revenues		2,203			1,107			739			(641	)		3,408
Expenses:
Fuel		-			302			-			-			302
Purchased power		1,011			205			714			(617	)		1,313
Other operating expenses		373			331			(9	)		(30	)		665
Provision for depreciation		112			69			-			7			188
Amortization of regulatory assets		244			-			17			-			261
Deferral of new regulatory assets		-			-			-			-			-
General taxes		160			27			2			3			192
Total Expenses		1,900			934			724			(637	)		2,921
Operating Income		303			173			15			(4	)		487
Other Income (Expense):
Investment income		46			159			-			(14	)		191
Interest expense		(118	)		(46	)		-			(191	)		(355	)
Capitalized interest		1			18			-			16			35
Total Other Expense		(71	)		131			-			(189	)		(129	)
Income Before Income Taxes		232			304			15			(193	)		358
Income taxes		93			121			6			(92	)		128
Net Income		139			183			9			(101	)		230
Less: Noncontrolling interest income (loss)		-			-			-			(4	)		(4	)
Earnings available to FirstEnergy Corp.	$	139		$	183		$	9		$	(97	)	$	234

78

							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	)

79

Energy Delivery Services – Third Quarter 2009 Compared with Third Quarter 2008

Net income decreased $144 million to $139 million in the third quarter of 2009 compared to $283 million in the third quarter 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:

	Three Months
	Ended September 30				Increase
Revenues by Type of Service	2009		2008		(Decrease)
	(In millions)
Distribution services	$	915	$	1,100	$	(185	)
Generation sales:
Retail		825		986		(161	)
Wholesale		195		286		(91	)
Total generation sales		1,020		1,272		(252	)
Transmission		221		241		(20	)
Other		47		44		3
Total Revenues	$	2,203	$	2,657	$	(454	)

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

Electric Distribution KWH Deliveries
Residential	(8.1)	%
Commercial	(6.2)	%
Industrial	(15.7)	%
Total Distribution KWH Deliveries	(9.8)	%

Lower deliveries to residential customers reflected decreased weather-related usage in the third quarter of 2009, as cooling degree days decreased by 14% from the same period in 2008. The decrease in distribution deliveries to commercial and industrial customers was primarily due to economic conditions in FirstEnergy's service territory. In the industrial sector, KWH deliveries declined due to major automotive customers (10.1%) and steel customers (42.3%). 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 $252 million decrease in generation revenues in the third quarter of 2009 compared to the third quarter of 2008:

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)

The decrease in retail generation sales volumes was primarily due to weakened economic conditions and the lower weather-related usage described above. The decrease in retail generation prices during the third quarter of 2009 reflected lower composite generation rates for JCP&L resulting from the New Jersey BGS auction and for Penn under its RFP process. 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 prices for PJM market participants.

80

Transmission revenues decreased $20 million primarily due to lower PJM transmission revenues partially offset by higher transmission rates for Met-Ed resulting from the annual update to its TSC rider in June 2009. Met-Ed and Penelec defer the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings (see Regulatory Matters – Pennsylvania).

Expenses –

Total expenses decreased by $233 million due to the net impact of the following:

· Purchased power costs were $237million lower in the third quarter of 2009 due to lower volume requirements and an increase in the amount of NUG costs deferred. JCP&L, Met-Ed and Penelec are permitted to defer for future collection from customers the amounts by which costs incurred under NUG agreements exceed amounts collected through rates. 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	$	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 $18million in the third quarter of 2009 compared to the third quarter of 2008 due to higher interest expense of $16million, 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).

81

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 $139million in the third quarter of 2009 primarily due to lower generation sales to the Ohio Companies, partially offset by higher non-affiliated retail generation sales volumes.

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	)

The higher retail revenues reflect the acquisition of government aggregation programs in Ohio and the acquisition of new retail customer contracts in the MISO and PJM markets in the third quarter of 2009. FES has signed new government aggregation contracts with 50 communities that provide discounted generation prices to approximately 600,000 residential and small commercial customers. Higher non-affiliated wholesale revenues resulted from lower sales volumes and higher prices in the PJM market offset by lower prices in the MISO market.

The lower affiliated company generation revenues were due primarily to a decrease in sales volumes to the Ohio Companies partially offset by higher unit prices for sales to the Ohio Companies and higher sales volumes to the Pennsylvania Companies. While unit prices for each of the Pennsylvania Companies did not change, the mix of sales among the companies caused the composite price to decline. Subsequent to the 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.

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

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	)

82

Transmission revenues decreased $30 million due primarily to reduced loads following the expiration of the government aggregation programs in Ohio at the end of 2008.

Expenses -

Total expenses decreased $21 million in the third quarter of 2009 due to the following factors:

·   Fuel costs decreased $54 million due to decreased generation volumes ($109 million), partially offset by higher unit prices ($55 million).

·   Purchased power costs decreased $16 million due primarily to lower volume requirements ($71 million), partially offset by higher unit costs ($55 million) resulting from higher capacity costs.

·   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 million due primarily to lower labor and employee benefit expenses of $6 million and reductions in contractor costs of $5 million.

·   Other operating expenses increased $32 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 in MISO of $24 million and higher congestion expenses in PJM of $15 million.

 · 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 quarter of 2009 was $149million 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 $9million 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	)

83

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 $91million 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.

84

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

85

							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	)

86

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.

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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 $375million 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 $38million resulted from debt issuances described above under Financing Activities.

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Competitive Energy Services – First Nine Months of 2009 Compared to First Nine Months of 2008

Net income increased to $614million in the first nine months of 2009 compared to $317million 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 $248million 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 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	)

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	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 $159million 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 $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 $55million 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.

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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 $659million 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 million decrease in FirstEnergy's net income in the first nine months of 2009 compared to the same period in 2008. The decrease resulted primarily from debt redemption costs ($90 million, net of taxes) and  the absence of the gain on the 2008 sale of telecommunication assets ($19 million, net of taxes).

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CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy's business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. During 2009 and in subsequent years, FirstEnergy expects to satisfy these requirements with a combination of cash from operations and funds from the capital markets as market conditions warrant. FirstEnergy also expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods.

As of September 30, 2009, FirstEnergy's net deficit in working capital (current assets less current liabilities) was principally due to short-term borrowings ($1.7 billion) and the classification of certain variable interest rate PCRBs as currently payable long-term debt. Currently payable long-term debt as of September 30, 2009, included the following (in millions):

Currently Payable Long-term Debt
PCRBs supported by bank LOCs(1)	$	1,553
FGCO and NGC unsecured PCRBs(1)	97
CEI secured notes(2)	150
Met-Ed unsecured notes(3)	100
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 billion of short-term borrowings as of September 30, 2009 and $2.4 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's available liquidity as of October 30, 2009, is summarized in the following table:

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. Commitments under the facility are available until August 24, 2012, unless the lenders agree, at the request of the borrowers, to an unlimited number of additional one-year extensions. Generally, borrowings under the facility must be repaid within 364 days. Available amounts for each borrower are subject to a specified sub-limit, as well as applicable regulatory and other limitations.

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The following table summarizes the borrowing sub-limits for each borrower under the facility, as well as the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of September 30, 2009:

	Revolving			Regulatory and
	Credit Facility			Other Short-Term
Borrower	Sub-Limit			Debt Limitations
	(In millions)
FirstEnergy	$	2,750		$	-	(1)
FES		1,000			-	(1)
OE		500			500
Penn		50			39	(2)
CEI		250	(3)		500
TE		250	(3)		500
JCP&L		425			428	(2)
Met-Ed		250			300	(2)
Penelec		250			300	(2)
ATSI		-	(4)		50
(1)No regulatory approvals, statutory or charter limitations applicable. (2)Excluding amounts which may be borrowed under the regulated companies' money pool. (3)Borrowing sub-limits for CEI and TE may be increased to up to $500 million by delivering notice to the administrative agent that such borrower has senior unsecured debt ratings of at least BBB by S&P and Baa2 by Moody's.  (4)The borrowing sub-limit for ATSI may be increased up to $100 million by delivering notice to the administrative agent that either (i) ATSI has senior unsecured debt ratings of at least BBB- by S&P and Baa3 by Moody's or (ii) FirstEnergy has guaranteed ATSI's obligations of such borrower under the facility.

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

The revolving credit facility contains financial covenants requiring each borrower to maintain a consolidated debt to total capitalization ratio of no more than 65%, measured at the end of each fiscal quarter. As of September 30, 2009, FirstEnergy's and its subsidiaries' debt to total capitalization ratios (as defined under the revolving credit facility) were as follows:

Borrower
FirstEnergy(1)	61.6	%
FES	54.2	%
OE	46.6	%
Penn	32.9	%
CEI	59.3	%
TE	53.9	%
JCP&L	34.9	%
Met-Ed	41.6	%
Penelec	54.1	%

 (1) As of September 30, 2009, FirstEnergy could issue additional debt of approximately $2.4 billion, or recognize a reduction in equity of approximately $1.3 billion, and remain within the limitations of the financial covenants required by its revolving credit facility.  

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

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FirstEnergy Money Pools

FirstEnergy's regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy's unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2009 was 0.78% for the regulated companies' money pool and 0.96% for the unregulated companies' money pool.

Pollution Control Revenue Bonds

As of September 30, 2009, FirstEnergy's currently payable long-term debt included approximately $1.6 billion (FES - $1.5 billion, Met-Ed - $29 million and Penelec - $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

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

	Aggregate LOC			Reimbursements of
LOC Bank	Amount(3)		LOC Termination Date	LOC Draws Due
	(In millions)
CitiBank N.A.	$	166	June 2014	June 2014
The Bank of Nova Scotia	255		Beginning June 2010	Shorter of 6 months or LOC termination date
The Royal Bank of Scotland	131		June 2012	6 months
KeyBank(1)	266		June 2010	6 months
Wachovia Bank	153		March 2014	March 2014
Barclays Bank(2)	528		Beginning December 2010	30 days
PNC Bank	70		Beginning November 2010	180 days
Total	$	1,569
(1)Supported by four participating banks, with the LOC bank having 62% of the total commitment. (2)Supported by 18 participating banks, with no one bank having more than 14% of the total commitment. (3)Includes approximately $16 million of applicable interest coverage.

In February 2009, holders of approximately $434 million principal of LOC-supported PCRBs of OE and NGC were notified that the applicable Wachovia Bank LOCs were to expire on March 18, 2009. As a result, these PCRBs were subject to mandatory purchase at a price equal to the principal amount, plus accrued and unpaid interest, which OE and NGC funded through short-term borrowings. In March 2009, FGCO remarketed $100 million of those PCRBs, which were previously held by OE. During the second quarter of 2009, NGC remarketed the remaining $334 million of PCRBs, of which $170 million was remarketed in fixed interest rate modes and secured by FMBs, thereby eliminating the need for third-party credit support. During the second quarter of 2009, FGCO remarketed approximately $248 million of PCRBs supported by LOCs set to expire in June 2009. These PCRBs were 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 issued and sold on behalf of 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 approximately $52.1 million and $29.6 million of variable rate PCRBs, respectively. These PCRBs are secured by a corresponding series of FMBs until December 31, 2009. Subject to market conditions, FGCO and NGC plan to remarket the purchased PCRBs in fixed-rate mode in the near future.

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Long-Term Debt Capacity

As of September 30, 2009, the Ohio Companies and Penn had the aggregate capability to issue approximately $1.5 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 million and $32 million, respectively, as of September 30, 2009. In April 2009, TE issued $300 million of new senior secured notes backed by FMBs. Concurrently with that issuance, and in order to satisfy the limitation on secured debt under its senior note indenture, TE issued an additional $300 million of FMBs to secure $300 million of its outstanding unsecured senior notes originally issued in November 2006. As a result, the provisions for TE to incur additional secured debt do not apply. In August 2009 CEI issued $300 million of FMB. CEI restricted $150 million of the proceeds to fund the redemption of $150 million of secured notes due in November 2009.

Based upon FGCO's FMB indenture, net earnings and available bondable property additions as of September 30, 2009, FGCO had the capability to issue $2.2 billion of additional FMBs under the terms of that indenture. On June 16, 2009, FGCO issued a total of approximately $395.9 million 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 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.

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 access to capital markets and costs of financing are influenced by the ratings of its securities. The following table displays FirstEnergy's, FES' and the Utilities' securities ratings as of September 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."

Issuer	Securities	S&P	Moody's
FirstEnergy	Senior unsecured	BBB-	Baa3
FES	Senior secured	BBB	Baa1
	Senior unsecured	BBB	Baa2
OE	Senior secured	BBB+	A3
	Senior unsecured	BBB	Baa2
Penn	Senior secured	A-	A3
CEI	Senior secured	BBB+	Baa1
	Senior unsecured	BBB	Baa3
TE	Senior secured	BBB+	Baa1
	Senior unsecured	BBB	Baa3
JCP&L	Senior unsecured	BBB	Baa2
Met-Ed	Senior unsecured	BBB	Baa2
Penelec	Senior unsecured	BBB	Baa2

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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 30, 2009, FirstEnergy had $838 million in cash and cash equivalents compared to $545 million as of December 31, 2008. Cash and cash equivalents consist of unrestricted, highly liquid instruments with an original or remaining maturity of three months or less. As of September 30, 2009, approximately $794 million of cash and cash equivalents represented temporary overnight deposits. As of September 30, 2009 and December 31, 2008, FirstEnergy had $171 million and $17 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

During the first nine months of 2009, FirstEnergy received $621 million of cash from dividends and equity repurchases from its subsidiaries and paid $503 million in cash dividends to common shareholders. With the exception of Met-Ed, which is currently in an accumulated deficit position, there are no material restrictions on the payment of cash dividends by FirstEnergy’s subsidiaries. In addition to paying dividends from retained earnings, each of FirstEnergy’s electric utility subsidiaries has authorization from the FERC to pay cash dividends from paid-in capital accounts, as long as the subsidiary’s debt to total capitalization ratio (without consideration of retained earnings) remains below 65%. CEI and TE are the only utility subsidiaries currently precluded from that action.

Cash Flows From Operating Activities

FirstEnergy's consolidated net cash from operating activities is provided primarily by its competitive energy services and energy delivery services businesses (see Results of Operations above). Net cash provided from operating activities increased by $33 million during the first nine months of 2009 compared to the comparable period in 2008, as summarized in the following table:

	Nine Months Ended September 30
Operating Cash Flows	2009		2008			Increase (Decrease)
	(In millions)
Net income	$	754	$	1,011		$	(257	)
Non-cash charges and other adjustments		1,755		1,033			722
Pension trust contribution		(500)		-			(500	)
Working capital and other		(545)		(613	)		68
	$	1,464	$	1,431		$	33

The increase in non-cash charges and other adjustments is primarily due to higher net amortization of regulatory assets ($233 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 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, of which $122 million was related primarily to the premium paid and included as a cash outflow in financing activities. The changes in working capital and other primarily resulted from a $73 million decrease in stock-based compensation payments and an increase in other accrued expenses principally associated with the implementation of the Ohio Companies’ Amended ESP.

Cash Flows From Financing Activities

In the first nine months of 2009, cash provided from financing activities was $617 million compared to $911 million in the first nine months of 2008. The decrease was primarily due to increased 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. 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.

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	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 months ended September 30, 2009 and 2008 by business segment:

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Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
Sources (Uses)	(In millions)
Nine Months Ended September 30, 2009
Energy delivery services	$	(524	)	$	(121	)	$	(35	)	$	(680	)
Competitive energy services		(893	)		(6	)		(21	)		(920	)
Other		(133	)		-			(11	)		(144	)
Inter-Segment reconciling items		(25	)		(25	)		6			(44	)
Total	$	(1,575	)	$	(152	)	$	(61	)	$	(1,788	)
Nine Months Ended September 30, 2008
Energy delivery services	$	(621	)	$	33		$	(3	)	$	(591	)
Competitive energy services		(1,430	)		(13	)		(121	)		(1,564	)
Other		(106	)		57			(54	)		(103	)
Inter-Segment reconciling items		(20	)		(12	)		-			(32	)
Total	$	(2,177	)	$	65		$	(178	)	$	(2,290	)

Net cash used for investing activities in the first nine months of 2009 decreased by $502 million compared to the first nine months of 2008. The decrease was principally due to a $602 million decrease in property additions, which reflects lower AQC system expenditures and the absence in 2009 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 proceeds from the sale of telecommunication assets in the first quarter of 2008 combined with increased restricted funds to be used for future debt redemptions.

During the last three months of 2009, capital requirements for property additions and capital leases are expected to be approximately $410million, including approximately $65 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, short-term credit arrangements and funds raised in the capital markets.

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 credit ratings.

As of September 30, 2009, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 billion, as summarized below:

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	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 billion is reflected in currently payable long-term debt on FirstEnergy’s consolidated balance sheets.

(3) Includes guarantees of $80 million for nuclear decommissioning funding (see Nuclear Plant Matters below) assurances and $161 million supporting OE’s sale and leaseback arrangement.

(4) Includes $58 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facility.

(5) Includes approximately $206 million pledged in connection with the sale and l easeback of Beaver Valley Unit 2 by OE and $134 million pledged in connection with the sale and leaseback of Perry by OE.

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by its subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financings where the law might otherwise limit the counterparties' claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty's legal claim to be satisfied by FirstEnergy 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 or a “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of September 30, 2009, FirstEnergy’s maximum exposure under these collateral provisions was $616 million as shown below:

Collateral Provisions	FES		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade	$	305	$	115	$	420
Acceleration of payment or funding obligation		80		63		143
Material adverse event		53		-		53
Total	$	438	$	178	$	616

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 million, consisting of $60 million due to “material adverse event” contractual clauses and $639 million due to a below investment grade credit rating.

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Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees 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 30, 2009, and forward prices as of that date, FES had $183 million of outstanding collateral payments. Under a hypothetical adverse change in forward prices (15% decrease in the first 12 months and 20% decrease thereafter in prices), FES would be required to post an additional $45 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 amount up to $500 million. The Surplus Margin Guaranty is secured by an NGC FMB issued in favor of the Ohio Companies.

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

OFF-BALANCE SHEET ARRANGEMENTS

FES and the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to sale and leaseback arrangements involving the Bruce Mansfield Plant, Perry Unit 1 and Beaver Valley Unit 2, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, is $1.7 billion as of September 30, 2009.

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 Risk Policy Committee, comprised of members of senior management, provides general oversight for risk management activities throughout the company.

Commodity Price Risk

FirstEnergy is exposed to financial and market risks resulting from the fluctuation of interest rates and commodity prices -- electricity, energy transmission, natural gas, coal, nuclear fuel and emission allowances. To manage the volatility relating to these exposures, FirstEnergy uses a variety of non-derivative and derivative instruments, including forward contracts, options, futures contracts and swaps. The derivatives are used principally for hedging purposes. 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:

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	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 $446million 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 5to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of September 30, 2009 are summarized by year in the following table:

Source of Information
- Fair Value by Contract Year	2009(1)		2010			2011			2012			2013			Thereafter		Total
	(In millions)
Prices actively quoted(2)	$	(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 30, 2009, an adverse 10% change in commodity prices would decrease net income by approximately $4million during the next 12 months.

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Forward Starting Swap Agreements - Cash Flow Hedges

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. 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.

	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	)

Equity Price Risk

FirstEnergy provides a noncontributory qualified defined benefit pension plan that covers substantially all of its employees and non-qualified pension plans that cover certain employees. The plan provides defined benefits based on years of service and compensation levels. FirstEnergy also provides health care benefits (which include certain employee contributions, deductibles, and co-payments) upon retirement to employees hired prior to January 1, 2005, their dependents, and under certain circumstances, their survivors. The benefit plan assets and obligations are remeasured annually using a December 31 measurement date. FirstEnergy’s other postretirement benefits plans were remeasured as of May 31, 2009 as a result of a plan amendment announced on June 2, 2009, which reduces future health care coverage subsidies paid by FirstEnergy on behalf of plan participants. The remeasurement and plan amendment will result in a $48 million reduction in FirstEnergy’s net postretirement benefit cost (including amounts capitalized) for the remainder of 2009, including a $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. As of December 31, 2008, the pension plan was underfunded and it remained underfunded after the voluntary contribution and remeasurement on August 31, 2009. FirstEnergy currently estimates that additional cash contributions will be required in 2014 for the 2013 plan year.

Nuclear decommissioning trust funds have been established to satisfy NGC's and the Utilities' nuclear decommissioning obligations. As of September 30, 2009, approximately 15% of the funds were invested in equity securities and 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 million as of September 30, 2009. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of September 30, 2009. The decommissioning trusts of JCP&L and the Pennsylvania Companies are subject to regulatory accounting, with unrealized gains and losses recorded as regulatory assets or liabilities, since the difference between investments held in trust and the decommissioning liabilities will be recovered from or refunded to customers. NGC, OE and TE recognize in earnings the unrealized losses on available-for-sale securities held in their nuclear decommissioning trusts based on the guidance for other-than-temporary impairments. 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 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 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 for the Beaver Valley Power Station in 2009. 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.

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CREDIT RISK

Credit risk is the risk of an obligor's failure to meet the terms of any investment contract, loan agreement or otherwise perform as agreed. Credit risk arises from all activities in which success depends on issuer, borrower or counterparty performance, whether reflected on or off the balance sheet. We engage 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 credit policies with respect to our 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 credit program, we aggressively manage the quality of our portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of September 30, 2009, the largest credit concentration was with JP Morgan, which is currently rated investment grade, representing 10.7% of our total approved credit risk.

OUTLOOK

State Regulatory Matters

In Ohio, New Jersey and Pennsylvania, laws applicable to electric industry restructuring contain similar provisions that are reflected in the Utilities' respective state regulatory plans. These provisions include:

· restructuring the electric generation business and allowing the Utilities' customers to select a competitive electric generation supplier other than the Utilities;

· establishing or defining the PLR obligations to customers in the Utilities' service areas;

· providing the Utilities with the opportunity to recover potentially stranded investment (or transition costs) not otherwise recoverable in a competitive generation market;

· itemizing (unbundling) the price of electricity into its component elements – including generation, transmission, distribution and stranded costs recovery charges;

· continuing regulation of the Utilities' transmission and distribution systems; and

· requiring corporate separation of regulated and unregulated business activities.

The Utilities and ATSI recognize, as regulatory assets, costs which the FERC, the PUCO, the PPUC and the NJBPU have authorized for recovery from customers in future periods or for which authorization is probable. Without the probability of such authorization, costs currently recorded as regulatory assets would have been charged to income as incurred. Regulatory assets that do not earn a current return totaled approximately $172 million as of September 30, 2009 (JCP&L - $42 million, Met-Ed - $102 million and Penelec - $28 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.

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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 

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

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

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

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

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

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Ohio

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

SB221, which became effective on July 31, 2008, required all electric utilities to file an ESP, and permitted the filing of an MRO. On July 31, 2008, the Ohio Companies filed with the PUCO a comprehensive ESP and a separate MRO. The PUCO denied the MRO application; however, the PUCO later granted the Ohio Companies’ application for rehearing for the purpose of further consideration of the matter, which is still pending. The ESP proposed to phase in new generation rates for customers beginning in 2009 for up to a three-year period and resolve the Ohio Companies’ collection of fuel costs deferred in 2006 and 2007, and the distribution rate request described above. In response to the PUCO’s December 19, 2008 order, which significantly modified and approved the ESP as modified, the Ohio Companies notified the PUCO that they were withdrawing and terminating the ESP application in addition to continuing their 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 at an overall average rate of $.002 per KWH for the period of April 1, 2009 through December 31, 2011. The Amended ESP also addressed a number of other issues, including but not limited to, rate design for various customer classes, and resolution of the prudence review and the collection of deferred costs that were approved in prior proceedings. On February 26, 2009, the Ohio Companies filed a Supplemental Stipulation, which was signed or not opposed by virtually all of the parties to the proceeding, that supplemented and modified certain provisions of the February 19, 2009 Stipulation and Recommendation. Specifically, the Supplemental Stipulation modified the provision relating to governmental aggregation and the Generation Service Uncollectible Rider, provided further detail on the allocation of the economic development funding contained in the Stipulation and Recommendation, and proposed additional provisions related to the collaborative process for the development of energy efficiency programs, among other provisions. The PUCO adopted and approved certain aspects of the Stipulation and Recommendation on March 4, 2009, and adopted and approved the remainder of the Stipulation and Recommendation and Supplemental Stipulation without modification on March 25, 2009. Certain aspects of the Stipulation and Recommendation and Supplemental Stipulation took effect on April 1, 2009 while the remaining provisions took effect on June 1, 2009.

On July 27, 2009, the Ohio Companies filed applications with the PUCO to recover three different categories of deferred distribution costs on an accelerated basis. In the Ohio Companies' Amended ESP, the PUCO approved the recovery of these deferrals, with collection originally set to begin in January 2011 and to continue over a 5 or 25 year period. The principal amount plus carrying charges through August 31, 2009 for these deferrals was a total of $305.1 million. The applications were approved 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.

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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. The Ohio Companies asked the Commission to issue a ruling on or before December 2, 2009.

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 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

Pennsylvania

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

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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.

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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 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, 2009, Met-Ed and Penelec submitted their 5-year NUG Statement Compliance filing to the PPUC in accordance with their 1998 Restructuring Settlement. Met-Ed proposed to reduce its CTC rate for the residential class with a corresponding increase in the generation rate and the shopping credit, and Penelec proposed to reduce its CTC rate to zero for all classes with a corresponding increase in the generation rate and the shopping credit. While these changes would result in additional annual generation revenue (Met-Ed - $27 million and Penelec - $59 million), overall rates would remain unchanged. On July 30, 2009, the PPUC entered an order approving the 5-year NUG Statement, approving the reduction of the CTC, and directing Met-Ed and Penelec to file a tariff supplement implementing this change. On July 31, 2009, Met-Ed and Penelec filed tariff supplements decreasing the CTC rate in compliance with the July 30, 2009 order, and increasing the generation rate in compliance with the companies’ Restructuring Orders of 1998. On August 14, 2009, the PPUC issued Secretarial Letters approving Met-Ed and Penelec’s compliance filings. By Tentative Order entered September 17, 2009, the PPUC provided for an additional 30 day comment period on whether “the Restructuring Settlement allows NUG over collection for select and isolated months to be used to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists.”   In response to the Tentative Order 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 filed reply comments on October 26, 2009, and await the decision of the PPUC.

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 30, 2009, the accumulated deferred cost balance totaled approximately $102 million.

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

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

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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 to be filed with the BPU by July 1, 2010. At this time, FirstEnergy cannot determine the impact, if any, the EMP may have on their operations.

In support of the New Jersey Governor's Economic Assistance and Recovery Plan, JCP&L announced a proposal to spend approximately $98 million on infrastructure and energy efficiency projects in 2009. Under the proposal, an estimated $40 million would be spent on infrastructure projects, including substation upgrades, new transformers, distribution line re-closers and automated breaker operations. 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 on August 19, 2009, and implementation will begin in 2009. Implementation of the remaining projects is dependent upon resolution of regulatory issues including recovery of the costs associated with the proposal.

FERC Matters

Transmission Service between MISO and PJM

On November 18, 2004, the FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. The FERC’s intent was to eliminate multiple transmission charges for a single transaction between the MISO and PJM regions. The FERC also ordered MISO, PJM and the transmission owners within MISO and PJM to submit compliance filings containing a rate mechanism to recover lost transmission revenues created by elimination of this charge (referred to as the Seams Elimination Cost Adjustment or SECA) during a 16-month transition period. The FERC issued orders in 2005 setting the SECA for hearing. The presiding judge issued an initial decision on August 10, 2006, rejecting the compliance filings made by MISO, PJM, and the transmission owners, and directing new compliance filings. This decision is 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.

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") finding that the PJM transmission owners’ existing “license plate” or zonal rate design was just and reasonable and ordered that the current license plate rates for existing transmission facilities be retained. On the issue of rates for new transmission facilities, the FERC directed that costs for new transmission facilities that are rated at 500 kV or higher are to be collected from all transmission zones throughout the PJM footprint by means of a postage-stamp rate. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a “beneficiary pays” basis. The FERC found that PJM’s current beneficiary-pays cost allocation methodology is not sufficiently detailed and, in a related order that also was issued on April 19, 2007, directed that hearings be held for the purpose of establishing a just and reasonable cost allocation methodology for inclusion in PJM’s tariff.

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

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, on behalf of its affiliated operating utility companies, filed a motion to intervene on March 10, 2009. The Seventh Circuit Court of Appeals has held this appeal in abeyance pending resolution of the Order 494 appeal discussed above.

RTO Consolidation

On August 17, 2009, FirstEnergy filed an application with the FERC requesting to consolidate its transmission assets and operations into PJM. Currently, FirstEnergy’s transmission assets and operations are divided between PJM and MISO. The consolidation would make the transmission assets that are part of ATSI, whose footprint includes the Ohio Companies and Penn, part of PJM. Most of FirstEnergy’s transmission assets in Pennsylvania and all of the transmission assets in New Jersey already operate as a part of PJM.

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.

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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 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 PJM Reliability Pricing Model (RPM) Auction

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

On March 26, 2009, the FERC accepted in part, and rejected in part, tariff provisions submitted by PJM, revising certain parts of its RPM. Ordered changes included making incremental improvements to RPM;   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, 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.

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On October 20, 2008, the FERC issued three orders essentially permitting the MISO Resource Adequacy program to proceed with some modifications. First, the FERC accepted MISO's financial settlement approach for enforcement of Resource Adequacy subject to a compliance filing modifying the cost of new entry penalty. Second, the FERC conditionally accepted MISO's compliance filing on the qualifications for purchased power agreements to be capacity resources, load forecasting, loss of load expectation, and planning reserve zones. Additional compliance filings were directed on accreditation of load modifying resources and price responsive demand. Finally, the FERC largely denied rehearing of its March 26 order with the exception of issues related to behind the meter resources and certain ministerial matters. On November 19, 2008, MISO made various compliance filings pursuant to these orders. Issuance of orders on rehearing and two of the compliance filings occurred on February 19, 2009. No material changes were made to MISO’s Resource Adequacy program. On April 16, 2009, the FERC issued an additional order on rehearing and compliance, approving MISO’s proposed financial settlement provision for Resource Adequacy. The MISO Resource Adequacy process was implemented as planned on June 1, 2009, the beginning of the MISO planning year. On June 17, 2009, MISO submitted a compliance filing in response to the FERC’s April 16, 2009 order directing it to address, among others, various market monitoring and mitigation issues. On July 8, 2009, various parties submitted comments on and protests to MISO’s compliance filing. FirstEnergy submitted comments identifying specific aspects of the MISO’s and Independent Market Monitor’s proposals for market monitoring and mitigation and other issues that it believes the FERC should address and clarify.

FES Sales to Affiliates

FES supplied all of the power requirements for the Ohio Companies pursuant to a Power Supply Agreement that ended on December 31, 2008. On January 2, 2009, FES signed an agreement to provide 75% of the Ohio Companies’ power requirements for the period January 5, 2009 through March 31, 2009. Subsequently, FES signed an agreement to provide 100% of the Ohio Companies’ power requirements for the period April 1, 2009 through May 31, 2009. On March 4, 2009, the PUCO issued an order approving these two affiliate sales agreements. FERC authorization for these affiliate sales was by means of a December 23, 2008 waiver of restrictions on affiliate sales without prior approval of the FERC.

On May 13-14, 2009, the Ohio Companies held an auction to secure generation supply for their PLR obligation. The results of the auction were accepted by the PUCO on May 14, 2009. Twelve bidders qualified to participate in the auction with nine successful bidders each securing a portion of the Ohio Companies' total supply needs. FES was the successful bidder for 51 tranches, and subsequently purchased 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 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 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.

Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. The effects of compliance on FirstEnergy with regard to environmental matters could have a material adverse effect on FirstEnergy's earnings and competitive position to the extent that it competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. FirstEnergy estimates capital expenditures for environmental compliance of approximately $800 million for the period 2009-2013.

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

Clean Air Act Compliance

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

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

In 1999 and 2000, the EPA issued an NOV and the DOJ filed a civil complaint against OE and Penn based on operation and maintenance of the W. H. Sammis Plant (Sammis NSR Litigation) and filed similar complaints involving 44 other U.S. power plants. This case and seven other similar cases are referred to as the NSR cases. OE’s and Penn’s settlement with the EPA, the DOJ and three states (Connecticut, New Jersey and New York) that resolved all issues related to the Sammis NSR litigation was approved by the Court on July 11, 2005. This settlement agreement, in the form of a consent decree, requires reductions of NOX and SO2 emissions at the Sammis, Burger, Eastlake and Mansfield coal-fired plants through the installation of pollution control devices or repowering and provides for stipulated penalties for failure to install and operate such pollution controls or complete repowering in accordance with that agreement. Capital expenditures necessary to complete requirements of the Sammis NSR Litigation consent decree, including repowering Burger Units 4 and 5 for biomass fuel consumption, are currently estimated to be $706 million for 2009-2012 (with $414 million expected to be spent in 2009).

On May 22, 2007, FirstEnergy and FGCO received a notice letter, required 60 days prior to the filing of a citizen suit under the federal CAA, alleging violations of air pollution laws at the Bruce Mansfield Plant, including opacity limitations. Prior to the receipt of this notice, the Plant was subject to a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection concerning opacity emissions under which efforts to achieve compliance with the applicable laws will continue. On October 18, 2007, PennFuture filed a complaint, joined by three of its members, in the United States District Court for the Western District of Pennsylvania. In July 2008, three additional complaints were filed against FGCO in the United States District Court for the Western District of Pennsylvania seeking damages based on Bruce Mansfield Plant air emissions. In addition to seeking damages, two of the three complaints seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner”, one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint, seeking certification as a class action with the eight named plaintiffs as the class representatives. On October 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 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 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 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 of New Jersey filed a CAA citizen suit alleging NSR violations at the Portland Generation Station against Reliant (the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999), GPU, Inc. and Met-Ed. On October 30, 2008, the state of Connecticut filed a Motion to Intervene, which the Court granted on March 24, 2009. Specifically, Connecticut and New Jersey allege that "modifications" at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. The scope of Met-Ed’s indemnity obligation to and from Sithe Energy is disputed. On December 5, 2008, New Jersey filed an amended complaint, adding claims with respect to alleged modifications that occurred after GPU’s sale of the plant. Met-Ed filed a Motion to Dismiss the claims in New Jersey’s Amended Complaint and Connecticut’s Complaint on February 19, 2009, and on September 30, 2009, respectively. The Court granted Met-Ed's motion to dismiss New Jersey’s and Connecticut’s claims for injunctive relief against Met-Ed, but denied Met-Ed’s motion to dismiss the claims for civil penalties on statute of limitations grounds in order to allow the states to prove either that the application of the discovery rule or the doctrine of equitable tolling bars application of the statute of limitations.

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On January 14, 2009, the EPA issued a NOV to Reliant alleging new source review violations at the Portland Generation Station based on “modifications” dating back to 1986. Met-Ed is unable to predict the outcome of this matter. The EPA’s January 14, 2009, NOV also alleged new source review violations at the Keystone and Shawville Stations based on “modifications” dating back to 1984. JCP&L, as the former owner of 16.67% of the Keystone Station and Penelec, as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter.

On June 11, 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. alleging that "modifications" at the Homer City Power Station occurred since 1988 to the present without preconstruction NSR or permitting under the CAA's prevention of significant deterioration program. Mission Energy is seeking indemnification from Penelec, the co-owner (along with New York State Electric and Gas Company) and operator of the Homer City Power Station prior to its sale in 1999. The scope of Penelec’s indemnity obligation to and from Mission Energy is disputed. Penelec is unable to predict the outcome of this matter.

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. On August 12, 2009, the EPA issued a Finding of Violation and NOV alleging violations of the Clean Air Act and Ohio regulations, including the prevention of significant deterioration (“PSD”), non-attainment new source review (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 request pursuant to Section 114(a) of the Clean Air Act requiring FirstEnergy to submit certain operating and maintenance information and planning information regarding the Eastlake, Lake Shore, Bay Shore and Ashtabula generating plants. On November 3, 2009, FGCO received a letter providing notification that the EPA is evaluating whether certain scheduled maintenance at the Eastlake generating plant may constitute a major modification under the NSR provisions of the CAA. FGCO intends to comply with the CAA, including EPA’s information requests, but, at this time, is unable to predict the outcome of this matter. A June 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. CAIR requires reductions of NOX and SO2 emissions in two phases (Phase I in 2009 for NOX, 2010 for SO2 and Phase II in 2015 for both NOX and SO2), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOX emissions to 1.3 million tons annually. CAIR was challenged in the United States Court of Appeals for the District of Columbia and on July 11, 2008, the Court vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” On September 24, 2008, the EPA, utility, mining and certain environmental advocacy organizations petitioned the Court for a rehearing to reconsider its ruling vacating CAIR. On December 23, 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s July 11, 2008 opinion. On July 10, 2009, the United States Court of Appeals for the District of Columbia ruled in a different case that a cap-and-trade program similar to CAIR, called the “NOX SIP Call,” cannot be used to satisfy certain CAA requirements (known as reasonably available control technology) for areas in non-attainment under the "8-hour" ozone NAAQS. FGCO's future cost of compliance with these regulations may be substantial and will depend, in part, on the action taken by the EPA in response to the Court’s ruling.

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Mercury Emissions

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

Pennsylvania has submitted a new mercury rule for EPA approval that does not provide a cap-and-trade approach as in the CAMR, but rather follows a command-and-control approach imposing emission limits on individual sources. On January 30, 2009, the Commonwealth Court of Pennsylvania declared Pennsylvania’s mercury rule “unlawful, invalid and unenforceable” and enjoined the Commonwealth from continued implementation or enforcement of that rule. It is anticipated that compliance with these regulations, if the Commonwealth Court’s rulings were reversed on appeal and Pennsylvania’s mercury rule was implemented, would not require the addition of mercury controls at 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. State activities, primarily the northeastern states participating in the Regional Greenhouse Gas Initiative and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

On April 2, 2007, the United States Supreme Court found that the EPA has the authority to regulate CO2 emissions from automobiles as “air pollutants” under the CAA. Although this decision did not address CO2 emissions from electric generating plants, the EPA has similar authority under the CAA to regulate “air pollutants” from those and other facilities. On April 17, 2009, the EPA released a “Proposed Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s proposed finding concludes that the atmospheric concentrations of several key greenhouse gases threaten the health and welfare of future generations and that the combined emissions of these gases by motor vehicles contribute to the atmospheric concentrations of these key greenhouse gases and hence to the threat of climate change. Although the EPA’s proposed finding, if finalized, does not establish emission requirements for motor vehicles, such requirements would be expected to occur through further rulemakings. Additionally, while the EPA’s proposed findings do not specifically address stationary sources, including electric generating plants, those findings, if finalized, would be expected to support the establishment of future emission requirements by the EPA for stationary sources, . 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 would be required. EPA is proposing a major source emissions applicability threshold of 25,000 tons per year (tpy) of carbon dioxide equivalents (CO2e) for existing facilities under the Title V operating permits program and the Prevention of Significant Determination (PSD) portion of NSR. EPA is also proposing a significance level between 10,000 and 25,000 tpy CO2e to determine if existing major sources making modifications that result in an increase of emissions above the significance level would be required to obtain a PSD permit.

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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.  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 (5th Cir. 2009)(seeking damages only), respectively.  While FirstEnergy is not a party to either litigation, should the courts of appeals decisions be affirmed, FirstEnergy and/or one or more of its subsidiaries could be named in actions making similar allegations.

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

Clean Water Act

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

On September 7, 2004, the EPA established new performance standards under Section 316(b) of the Clean Water Act for reducing impacts on fish and shellfish from cooling water intake structures at certain existing large electric generating plants. The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system). On January 26, 2007, the United States Court of Appeals for the Second Circuit remanded portions of the rulemaking dealing with impingement mortality and entrainment back to the EPA for further rulemaking and eliminated the restoration option from the EPA’s regulations. On July 9, 2007, the EPA suspended this rule, noting that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures. On April 1, 2009, the Supreme Court of the United States reversed one significant aspect of the Second Circuit Court’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. The EPA will now take up consideration of the rule on remand and take further action 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’ opinions have created significant uncertainty about the specific nature, scope and timing of the final compliance requirements .FirstEnergy is studying various control options and their costs and effectiveness. Depending on the results of such studies and the EPA’s further rulemaking and any action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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

Regulation of Waste Disposal

As a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976, federal and state hazardous waste regulations have been promulgated. Certain fossil-fuel combustion waste products, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation. The EPA subsequently determined that regulation of coal ash as a hazardous waste is unnecessary. In April 2000, the EPA announced that it will develop national standards regulating disposal of coal ash under its authority to regulate non-hazardous waste. In February 2009, the EPA requested comments from the states on options for regulating coal combustion wastes, including regulation as non-hazardous waste or regulation as a hazardous waste. In March and June 2009, 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 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 could have a significant impact on our management, beneficial use, and disposal, of coal ash. FGCO's future cost of compliance with any coal combustion waste 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 states.

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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 30, 2009, based on estimates of the total costs of cleanup, the Utilities' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $104 million (JCP&L - $77 million, TE - $1 million, CEI - $1 million, FGCO - $1 million and FirstEnergy - $24 million) have been accrued through September 30, 2009. Included in the total are accrued liabilities of approximately $68 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC.

Other Legal Proceedings

Power Outages and Related Litigation 

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

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

Nuclear Plant Matters 

In August 2007, FENOC submitted an application to the NRC to renew the operating licenses for the Beaver Valley Power Station (Units 1 and 2) for an additional 20 years. 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.

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of September 30, 2009, 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 the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s nuclear decommissioning trusts fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligations to fund the trusts may increase. The recent disruption in the capital markets and its effects on particular businesses and the economy in general also affects the values of the nuclear decommission trusts. On June 18, 2009, the NRC informed FENOC that its review tentatively concluded that a shortfall ($147.5 million net present value) existed in the value of the decommissioning trust fund for Beaver Valley Unit 1. On July 28, 2009, FENOC submitted a letter to the NRC that stated reasonable assurance of decommissioning funding is provided for Beaver Valley Unit 1 through a combination of the existing trust fund balances, the existing $80 million parental guarantee from FirstEnergy and maintaining the plant in a safe-store configuration, or extended safe shutdown condition, after plant shutdown. 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.

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Other Legal Matters 

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

JCP&L's bargaining unit employees filed a grievance challenging JCP&L's 2002 call-out procedure that required bargaining unit employees to respond to emergency power outages. On May 20, 2004, an arbitration panel concluded that the call-out procedure violated the parties' collective bargaining agreement. On September 9, 2005, the arbitration panel issued an opinion to award approximately $16 million to the bargaining unit employees. A final order identifying the individual damage amounts was issued on October 31, 2007 and the award appeal process was initiated. The union filed a motion with the federal Court to confirm the award and JCP&L filed its answer and counterclaim to vacate the award on December 31, 2007. JCP&L and the union filed briefs in June and July of 2008 and oral arguments were held in the fall. On February 25, 2009, the federal district court denied JCP&L’s motion to vacate the arbitration decision and granted the union’s motion to confirm the award. JCP&L filed a Notice of Appeal to the Third Circuit and a Motion to Stay Enforcement of the Judgment on March 6, 2009. The appeal process could take as long as 24 months. 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.

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

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In 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, the FASB amended the derecognition guidance in the Transfers and Servicing Topic 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 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.

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 NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

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

FES' revenues have been primarily derived from the sale of electricity (provided from FES' generating facilities and through purchased power arrangements) to affiliated utility companies to meet all or a portion of their PLR and default service requirements. These affiliated power sales included a full-requirements PSA with OE, CEI and TE to supply each of their default service obligations through December 31, 2008, at prices that considered their respective PUCO-authorized billing rates. See Regulatory Matters – Ohio 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 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. FES also supplied, through May 31, 2009, a portion of Penn's default service requirements at market-based rates as a result of Penn's 2008 competitive solicitations. FES' revenues also include competitive retail and wholesale sales to non-affiliated customers in Ohio, Pennsylvania, New Jersey, Maryland, Michigan and Illinois. These sales may provide a greater portion of revenues in future years depending upon FES' participation in its Ohio and Pennsylvania utility affiliates' power procurement arrangements.

The demand for electricity produced and sold by FES, along with the 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.

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 $668million from $344million 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 $260million 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 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

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 $28million 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 $156million 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 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

In the first nine months of 2009, net income decreased to $80 million from $166 million in the same period of 2008. The decrease primarily resulted from the completion of the recovery of transition costs at the end of 2008 and accrued obligations principally associated with the implementation of the ESP in 2009.

Revenues

Revenues increased by $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 primarily due to higher average prices across all customer classes and increased KWH sales to residential and commercial customers, reflecting a decrease in customer shopping in those sectors as most of OE’s franchise customers returned to PLR service in December 2008. Reduced industrial KWH sales reflected weakened economic conditions in OE’s service territory. Average prices increased primarily due to an increase in OE's fuel cost recovery rider that was effective from January through May 2009. Effective June 1, 2009, the transmission tariff ended and the recovery of transmission costs is included in the generation rate established under OE’s CBP.

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

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

122

Changes in distribution KWH deliveries and revenues in the first nine 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 compared to the same period in 2008 primarily due to higher interest expense associated with the issuance of $300 million of FMBs by OE in October 2008.

123

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT'S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

CEI is a wholly owned, electric utility subsidiary of FirstEnergy. CEI conducts business in northeastern Ohio, providing regulated electric distribution services. CEI also provides generation services to those customers electing to retain CEI as their power supplier. Until December 31, 2008, CEI purchased power for delivery and resale from a full requirements power sale agreement with its affiliate FES at a fixed price that was reflected in rates approved by the PUCO. See Regulatory Matters – Ohio 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, 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

CEI experienced a net loss of $32 million in the first nine 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 compared to the same period of 2008 primarily due to decreases in distribution revenues ($117 million), transmission revenues ($14 million) and other miscellaneous revenues ($7 million), partially offset by an increase in retail generation revenues ($103 million).

Retail generation revenues increased in the first nine months of 2009 due to higher average unit prices in all customer classes partially offset by decreased sales volume to residential and industrial customers compared to the same period of 2008. Average prices increased due to an increase in CEI’s fuel cost recovery rider that was effective from January through May 2009. In addition, effective 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.

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

	Increase
Retail Generation KWH Sales	(Decrease)
Residential		(2.7	)%
Commercial		4.8	%
Industrial		(14.6	)%
Decrease in Retail Generation Sales		(6.4	)%

Retail Generation Revenues	Increase
	(in millions)
Residential	$	30
Commercial		40
Industrial		33
Increase in Generation Revenues	$	103

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Revenues from distribution throughput decreased by $117 million in the first nine months of 2009 compared to the same period of 2008 due to a decrease in KWH deliveries in all customer classes and lower average unit prices in the residential 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.

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

Distribution KWH Deliveries	Decrease
Residential		(4.0	)%
Commercial		(4.7	)%
Industrial		(18.6	)%
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 $14million from $70million 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 ($143million) and other miscellaneous revenue ($3 million), partially offset by lower distribution revenues ($130million) 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		2.4	%
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	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(31	)
Commercial		(61	)
Industrial		(38	)
Decrease in Distribution Revenues	$	(130	)

Expenses

Total expenses increased $80 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	$	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 $128million from $153million 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 ($208million), 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 $208million 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)
	(In millions)
Purchased power costs	$	(338	)
Other operating costs		7
Provision for depreciation		7
Amortization of regulatory assets		(18	)
General taxes		(4	)
Net decrease in expenses	$	(346	)

Purchased power costs decreased in the first nine months of 2009 primarily due to the lower KWH sales requirements discussed above and lower unit prices due to reduced energy rates. Other operating costs increased in the first nine months of 2009 primarily due to higher expenses related to employee benefits and customer assistance programs. Depreciation expense increased due to an increase in depreciable property since the third quarter of 2008. Amortization of regulatory assets decreased in the first nine months of 2009 primarily due to the full recovery of certain regulatory assets in June 2008. General taxes decreased principally as the result of lower Transitional Energy Facility Assessment (TEFA) and sales taxes.

Other Expenses

Other expenses increased by $9million 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 Division of the Superior Court of New Jersey. On July 10, 2009, the Court upheld the NJBPU’s order and the sale of the plant.

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 generation service to those customers electing to retain Met-Ed as their power supplier. 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 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.

For additional information with respect to Met-Ed, 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 decreased to $37 million in the first nine months of 2009, compared to $64million 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 compared to the same period of 2008 primarily due to higher distribution throughput revenues, partially offset by a decrease in retail generation and wholesale revenues. Wholesale revenues decreased by $7million in the first nine 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 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 $63million primarily due to higher transmission rates, resulting from the annual update to Met-Ed’s TSC rider effective June 1, 2009. Decreased deliveries to commercial and industrial customers reflected the weakened economy, while decreased deliveries to residential customers were a result of the weather conditions described above.

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

Distribution KWH Deliveries	(Decrease)
Residential		(2.0	)%
Commercial		(4.7	)%
Industrial		(11.9	)%
Decrease in Distribution Deliveries		(5.6	)%

Distribution Revenues	Increase
	(In millions)
Residential	$	32
Commercial		20
Industrial		11
Increase in Distribution Revenues	$	63

Transmission service revenues decreased by $22million in the first nine months of 2009 compared to the same period of 2008, primarily due to decreased revenues related to Met-Ed’s Financial Transmission Rights. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses increased by $44 million in the first nine months of 2009 compared to the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses – Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(17	)
Other operating costs		(129	)
Provision for depreciation		5
Amortization of regulatory assets, net		184
General taxes		1
Net Increase in Expenses	$	44

The net amortization of regulatory assets increased by $184 million in the first nine months of 2009 compared to the same period of 2008 primarily due to increased transmission cost recovery reflecting lower PJM transmission service expenses and the increased transmission revenues described above. Other operating costs decreased $129 million in the first nine months of 2009 primarily due to lower transmission expenses as a result of decreased congestion costs and transmission loss expenses. Purchased power costs decreased by $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. Depreciation expense increased primarily due to an increase in depreciable property since the third quarter of 2008.

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

ANALYSIS OF RESULTS OF OPERATIONS

Penelec is a wholly owned electric utility subsidiary of FirstEnergy. Penelec conducts business in northern and south central Pennsylvania, providing regulated transmission and distribution services. Penelec also provides generation services to those customers electing to retain Penelec as their power supplier. 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 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.

For additional information with respect to Penelec, 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 decreased to $49 million in the first nine months of 2009, compared to $62 million in the same period of 2008. The decrease was primarily due to lower revenues, partially offset by lower purchased power costs and decreased amortization of regulatory assets.

Revenues

Revenues decreased by $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, partially offset by higher wholesale generation revenues. Wholesale revenues increased $1 million in the first nine months of 2009, 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 primarily due to lower KWH sales to the commercial and industrial customer classes due to weakened economic conditions; reduced KWH sales to the residential customer class were due to decreased weather-related usage, reflecting a 28.5% 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 compared to the same period of 2008 are summarized in the following tables:

Retail Generation KWH Sales	(Decrease)
Residential		(1.4)	%
Commercial		(3.2)	%
Industrial		(16.2)	%
Decrease in Retail Generation Sales		(6.6)	%

Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	(2)
Commercial		(6)
Industrial		(23)
Decrease in Retail Generation Revenues	$	(31)

132

Revenues from distribution throughput decreased $2 million in the first nine months of 2009 compared to the same period of 2008, primarily due to decreased deliveries to the commercial and industrial sectors reflecting the economic conditions in Penelec's service area. Offsetting this decrease was an increase in residential unit prices due to an increase in transmission rates, resulting from the annual update of Penelec's TSC rider effective June 1, 2009.

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

Distribution KWH Deliveries	(Decrease)
Residential		(1.4)	%
Commercial		(3.2)	%
Industrial		(15.4)	%
Decrease in Distribution Deliveries		(6.6)	%

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

Transmission revenues decreased by $34 million in the first nine months of 2009 compared to the same period of 2008, primarily due to lower revenues related to Penelec’s Financial Transmission Rights. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Operating Expenses

Total operating expenses decreased by $27 million in the first nine months of 2009 as compared with the same period of 2008. The following table presents changes from the prior year by expense category:

Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(11	)
Other operating costs		(5	)
Provision for depreciation		5
Amortization of regulatory assets, net		(11	)
General taxes		(5	)
Net Decrease in Expenses	$	(27	)

Purchased power costs decreased by $11 million, or 1.7%, in the first nine months of 2009 compared to the same period of 2008 due to reduced volume as a result of lower KWH sales requirements, partially offset by increased composite unit prices. Other operating costs decreased by $5 million in the first nine months of 2009 due primarily to reduced labor and transmission expenses and a decrease in contingency reserves based on a favorable legal ruling, partially offset by higher pension and OPEB expenses. Depreciation expense increased 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 million repayment of unsecured notes in April 2009.

133

ITEM 3.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

ITEM 4.   CONTROLS AND PROCEDURES

(a)    EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES – FIRSTENERGY

FirstEnergy's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that the registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b)    CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2009, there were no changes in FirstEnergy's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrant's internal control over financial reporting.

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

(a)    EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Each registrant's chief executive officer and chief financial officer have reviewed and evaluated the effectiveness of such registrant's disclosure controls and procedures as of the end of the period covered by this report. The term disclosure controls and procedures means controls and other procedures of a registrant that are designed to ensure that information required to be disclosed by the registrant in the reports that it files or submits under the Securities Exchange Act of 1934 (15 U.S.C. 78a et seq.) is recorded, processed, summarized and reported, within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under that Act is accumulated and communicated to the registrant's management, including its principal executive and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Based on that evaluation, those officers have concluded that such registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b)    CHANGES IN INTERNAL CONTROLS

During the quarter ended September 30, 2009, there were no changes in the registrants' internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the registrants' internal control over financial reporting.

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 9 and 10 of the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A. RISK FACTORS

FirstEnergy's Annual Report on Form 10-K for the year ended December 31, 2008, and Quarterly Report on Form 10-Q for the quarter ended March 31, 2009 and June 30, 2009, include a detailed discussion of its risk factors. For the quarter ended September 30, 2009, there have been no material changes to these risk factors.

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 quarter of 2009.

	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 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

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
	12	Fixed charge ratios
	15	Letter from independent registered public accounting firm
	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Statements of Income and Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
FES
	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

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

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

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

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SIGNATURES

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

November 6, 2009

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY

Registrant

THE CLEVELAND ELECTRIC

ILLUMINATING COMPANY

Registrant

THE TOLEDO EDISON COMPANY

Registrant

METROPOLITAN EDISON COMPANY

Registrant

PENNSYLVANIA ELECTRIC COMPANY

Registrant

/s/ Harvey L. Wagner

Harvey L. Wagner

Vice President, Controller

and Chief Accounting Officer

JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant

/s/ Kevin R. Burgess

Kevin R. Burgess

Controller

(Principal Accounting Officer)

138