10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D. C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2011

OR

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

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

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

Indicate by check mark whether the registrant 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 þ	FirstEnergy Corp.
Accelerated Filer o	N/A
Non-accelerated Filer (Do not check if a smaller reporting company) þ	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 o	N/A

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

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

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

	OUTSTANDING
CLASS	AS OF JULY 29, 2011
FirstEnergy Corp., $.10 par value		418,216,437
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		740,905
Pennsylvania Electric Company, $20 par value		4,427,577

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

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

FirstEnergy Web Site

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

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

OMISSION OF CERTAIN INFORMATION

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

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

Actual results may differ materially due to:

• The speed and nature of increased competition in the electric utility industry.

• The impact of the regulatory process on the pending matters in the various states in which we do business including, but not limited to, matters related to rates.

• The status of the PATH project in light of PJM’s direction to suspend work on the project pending review of its planning process, its re-evaluation of the need for the project and the uncertainty of the timing and amounts of any related capital expenditures.

• Business and regulatory impacts from ATSI’s realignment into PJM Interconnection, L.L.C.

• Economic or weather conditions affecting future sales and margins.

• Changes in markets for energy services.

• Changing energy and commodity market prices and availability.

• Financial derivative reforms that could increase our liquidity needs and collateral costs.

• The continued ability of FirstEnergy’s regulated utilities to collect transition and other costs.

• Operation and maintenance costs being higher than anticipated.

• Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water intake and coal combustion residual regulations, the potential impacts of any laws, rules or regulations that ultimately replace CAIR, including the Cross-State Air Pollution Rule (CSAPR), and the effects of the EPA’s recently released MACT proposal to establish certain mercury and other emission standards for electric generating units.

• The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any NSR litigation or potential regulatory initiatives or rulemakings (including that such expenditures could result in our decision to shut down or idle certain generating units).

• Adverse regulatory or legal decisions and outcomes with respect to our nuclear operations (including, but not limited to the revocation or non-renewal of necessary licenses, approvals or operating permits by the NRC including as a result of the incident at Japan’s Fukushima Daiichi Nuclear Plant).

• Adverse legal decisions and outcomes related to Met-Ed’s and Penelec’s ability to recover certain transmission costs through their transmission service charge riders.

• The continuing availability of generating units and changes in their ability to operate at or near full capacity.

• Replacement power costs being higher than anticipated or inadequately hedged.

• The ability to comply with applicable state and federal reliability standards and energy efficiency mandates.

• Changes in customers’ demand for power, including but not limited to, changes resulting from the implementation of state and federal energy efficiency mandates.

• The ability to accomplish or realize anticipated benefits from strategic goals.

• Efforts and our ability to improve electric commodity margins and the impact of, among other factors, the increased cost of coal and coal transportation on such margins.

• The ability to experience growth in the distribution business.

• The changing market conditions that could affect the value of assets held in FirstEnergy’s nuclear decommissioning trusts, pension trusts and other trust funds, and cause us 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, the cost of such capital and overall condition of the capital and credit markets affecting FirstEnergy and its subsidiaries.

• Changes in general economic conditions affecting FirstEnergy and its subsidiaries.

• Interest rates and any actions taken by credit rating agencies that could negatively affect FirstEnergy’s and its subsidiaries’ 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 uncertainty of the national and regional economy and its impact on FirstEnergy’s and its subsidiaries’ major industrial and commercial customers.

• Issues concerning the soundness of financial institutions and counterparties with which FirstEnergy and its subsidiaries do business.

• Issues arising from the recently completed merger of FirstEnergy and Allegheny Energy, Inc. and the ongoing coordination of their combined operations including FirstEnergy’s ability to maintain relationships with customers, employees or suppliers, as well as the ability to successfully integrate the businesses and realize cost savings and any other synergies and the risk that the credit ratings of the combined company or its subsidiaries may be different from what the companies expect.

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

Dividends declared from time to time on FirstEnergy’s common stock during any annual period may in aggregate vary from the indicated amount due to circumstances considered by FirstEnergy’s Board of Directors at the time of the actual declarations. A security rating is not a recommendation to buy, or hold securities and is subject to revision or withdrawal at any time by the assigning rating agency. Each rating should be evaluated independently of any other rating.

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. 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

	Page
Part I. Financial Information
Glossary of Terms		iii
Item 1. Financial Statements
FirstEnergy Corp.
Consolidated Statements of Income		1
Consolidated Statements of Comprehensive Income		2
Consolidated Balance Sheets		3
Consolidated Statements of Cash Flows		4
FirstEnergy Solutions Corp.
Consolidated Statements of Income and Comprehensive Income		5
Consolidated Balance Sheets		6
Consolidated Statements of Cash Flows		7
Ohio Edison Company
Consolidated Statements of Income and Comprehensive Income		8
Consolidated Balance Sheets		9
Consolidated Statements of Cash Flows		10
The Cleveland Electric Illuminating Company
Consolidated Statements of Income and Comprehensive Income		11
Consolidated Balance Sheets		12
Consolidated Statements of Cash Flows		13
The Toledo Edison Company
Consolidated Statements of Income and Comprehensive Income		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		20
Consolidated Balance Sheets		21
Consolidated Statements of Cash Flows		22
Pennsylvania Electric Company
Consolidated Statements of Income and Comprehensive Income		23
Consolidated Balance Sheets		24
Consolidated Statements of Cash Flows		25

i

TABLE OF CONTENTS (Cont’d)

	Page
Combined Notes To Consolidated Financial Statements		27
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries		84
Management’s Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.		131
Ohio Edison Company		134
The Cleveland Electric Illuminating Company		136
The Toledo Edison Company		138
Jersey Central Power & Light Company		140
Metropolitan Edison Company		142
Pennsylvania Electric Company		144
Item 3. Quantitative and Qualitative Disclosures About Market Risk		146
Item 4. Controls and Procedures — FirstEnergy		146
Part II. Other Information
Item 1. Legal Proceedings		147
Item 1A. Risk Factors		147
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		147
Item 5. Other Information		147
Item 6. Exhibits		148
Exhibit 10.1
Exhibit 12
Exhibit 31.1
Exhibit 31.2
Exhibit 32
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

ii

GLOSSARY OF TERMS

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

AE	Allegheny Energy, Inc., a Maryland utility holding company that merged with a subsidiary of FirstEnergy on February 25, 2011
AESC	Allegheny Energy Service Corporation, a subsidiary of AE
AE Supply	Allegheny Energy Supply Company LLC, an unregulated generation subsidiary of AE
AET	Allegheny Energy Transmission, LLC, a parent of TrAIL and PATH
AGC	Allegheny Generating Company, a generation subsidiary of AE
Allegheny	Allegheny Energy, Inc., together with its consolidated subsidiaries
AVE	Allegheny Ventures, Inc.
ATSI	American Transmission Systems, Incorporated, which owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FENOC	FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., which provides energy-related products and services
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FEV	FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FGCO	FirstEnergy Generation Corp., which owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., a public utility holding company
Global Rail	A joint venture between FEV and WMB Loan Ventures II LLC, that owns coal transportation operations near Roundup, Montana
GPU	GPU, Inc., former parent of JCP&L, Met-Ed and Penelec, that merged with FirstEnergy on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
Met-Ed	Metropolitan Edison Company, a Pennsylvania electric utility operating subsidiary
MP	Monongahela Power Company, a West Virginia electric utility operating subsidiary of AE
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
PATH	Potomac-Appalachian Transmission Highline LLC, a joint venture between Allegheny and a subsidiary of American Electric Power Company, Inc.
PATH-VA	PATH Allegheny Virginia Transmission Corporation
PE	The Potomac Edison Company, a Maryland electric operating subsidiary of AE
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, Penn and WP
PNBV	PNBV Capital Trust, a special purpose entity created by OE in 1996
Shippingport	Shippingport Capital Trust, a special purpose entity created by CEI and TE in 1997
Signal Peak	A joint venture between FEV and WMB Loan Ventures LLC, that owns mining operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL	Trans-Allegheny Interstate Line Company
Utilities	OE, CEI, TE, Penn, JCP&L, Met-Ed, Penelec, MP, PE and WP
Utility Registrants	OE, CEI, TE, JCP&L, Met-Ed and Penelec
WP	West Penn Power Company, a Pennsylvania electric utility operating subsidiary of AE
The following abbreviations and acronyms are used to identify frequently used terms in this report:
ALJ	Administrative Law Judge
AOCL	Accumulated Other Comprehensive Loss
AEP	American Electric Power
AQC	Air Quality Control
ARO	Asset Retirement Obligation
ARR	Auction Revenue Rights
BGS	Basic Generation Service
BMP	Bruce Mansfield Plant
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CAMR	Clean Air Mercury Rule
CATR	Clean Air Transport Rule
CBP	Competitive Bid Process

iii

GLOSSARY OF TERMS, Cont’d.

CCB	Coal Combustion By-products
CDWR	California Department of Water Resources
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
CTC	Competitive Transition Charge
CWA	Clean Water Act
CWIP	Construction Work in Progress
DCPD	Deferred Compensation Plan for Outside Directors
DOE	United States Department of Energy
DOJ	United States Department of Justice
DPA	Department of the Public Advocate, Division of Rate Counsel (New Jersey)
DSP	Default Service Plan
EDCP	Executive Deferred Compensation Plan
EE&C	Energy Efficiency and Conservation
EIS	Energy Insurance Services, Inc.
EMP	Energy Master Plan
ENEC	Expanded Net Energy Cost
EPA	United States Environmental Protection Agency
ESOP	Employee Stock Ownership Plan
ESP	Electric Security Plan
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FMB	First Mortgage Bond
FPA	Federal Power Act
FRR	Fixed Resource Requirement
FTRs	Financial Transmission Rights
GAAP	Generally Accepted Accounting Principles in the United States
RGGI	Regional Greenhouse Gas Initiative
GHG	Greenhouse Gases
IRS	Internal Revenue Service
JOA	Joint Operating Agreement
kV	Kilovolt
KWH	Kilowatt-hours
LBR	Little Blue Run
LED	Light-Emitting Diode
LOC	Letter of Credit
LSE	Load Serving Entity
LTIP	Long-Term Incentive Plan
MACT	Maximum Achievable Control Technology
MDE	Maryland Department of the Environment
MDPSC	Maryland Public Service Commission
MEIUG	Met-Ed Industrial Users Group
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MRO	Market Rate Offer
MSHA	Mine Safety and Health Administration
MTEP	MISO Regional Transmission Expansion Plan
MVP	Multi-value Project
MW	Megawatts
MWH	Megawatt-hours
NAAQS	National Ambient Air Quality Standards
NDT	Nuclear Decommissioning Trusts
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NNSR	Non-Attainment New Source Review
NOAC	Northwest Ohio Aggregation Coalition
NOPEC	Northeast Ohio Public Energy Council
NOV	Notice of Violation
NOX	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission

iv

GLOSSARY OF TERMS, Cont’d.

NSR	New Source Review
NUG	Non-Utility Generation
NUGC	Non-Utility Generation Charge
NYSEG	New York State Electric and Gas
OCC	Ohio Consumers’ Counsel
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OSBA	Office of Small Business Advocate
OVEC	Ohio Valley Electric Corporation
PA DEP	Pennsylvania Department of Environmental Protection
PCRB	Pollution Control Revenue Bond
PICA	Pennsylvania Intergovernmental Cooperation Authority
PJM	PJM Interconnection L. L. C.
POLR	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
PSCWV	Public Service Commission of West Virginia
PSA	Power Supply Agreement
PSD	Prevention of Significant Deterioration
PUCO	Public Utilities Commission of Ohio
PURPA	Public Utility Regulatory Policies Act of 1978
RECs	Renewable Energy Credits
RFP	Request for Proposal
RGGI	Regional Greenhouse Gas Initiative
RPM	Reliability Pricing Model
RTEP	Regional Transmission Expansion Plan
RTC	Regulatory Transition Charge
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	U.S. Securities and Exchange Commission
SIP	State Implementation Plan(s) Under the Clean Air Act
SMIP	Smart Meter Implementation Plan
SNCR	Selective Non-Catalytic Reduction
SO2	Sulfur Dioxide
SOS	Standard Offer Service
TBC	Transition Bond Charge
TDS	Total Dissolved Solid
TMDL	Total Maximum Daily Load
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity
VSCC	Virginia State Corporation Commission
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia

v

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME
(Unaudited)

	Three Months						Six Months
	Ended June 30						Ended June 30
In millions, except per share amounts	2011			2010			2011			2010
REVENUES:
Electric utilities	$	2,590		$	2,373		$	4,925		$	4,916
Unregulated businesses		1,470			766			2,711			1,522
Total revenues*		4,060			3,139			7,636			6,438
EXPENSES:
Fuel		635			350			1,088			684
Purchased power		1,220			1,063			2,406			2,301
Other operating expenses		1,105			673			2,138			1,374
Provision for depreciation		282			190			502			383
Amortization of regulatory assets		90			161			222			373
General taxes		242			176			479			381
Total expenses		3,574			2,613			6,835			5,496
OPERATING INCOME		486			526			801			942
OTHER INCOME (EXPENSE):
Investment income		31			31			52			47
Interest expense		(265	)		(207	)		(496	)		(420	)
Capitalized interest		20			40			38			81
Total other expense		(214	)		(136	)		(406	)		(292	)
INCOME BEFORE INCOME TAXES		272			390			395			650
INCOME TAXES		101			134			179			245
NET INCOME		171			256			216			405
Loss attributable to noncontrolling interest		(10	)		(9	)		(15	)		(15	)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	181		$	265		$	231		$	420
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$	0.43		$	0.87		$	0.61		$	1.38
Diluted	$	0.43		$	0.87		$	0.61		$	1.37
AVERAGE SHARES OUTSTANDING:
Basic		418			304			380			304
Diluted		420			305			382			305
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK		—			—		$	0.55		$	0.55

* Includes excise tax collections of $116 million and $99 million in the three months ended June 30, 2011 and 2010, respectively, and $235 million and $208 million in the six months ended June 30, 2011 and 2010, respectively.

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

1

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)

	Three Months						Six Months
	Ended June 30						Ended June 30
(In millions)	2011			2010			2011			2010
NET INCOME	$	171		$	256		$	216		$	405
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		111			17			130			30
Unrealized gain on derivative hedges		17			6			11			10
Change in unrealized gain on available-for-sale securities		10			6			19			12
Other comprehensive income		138			29			160			52
Income tax expense related to other comprehensive income		53			9			54			16
Other comprehensive income, net of tax		85			20			106			36
COMPREHENSIVE INCOME		256			276			322			441
COMPREHENSIVE LOSS ATTRIBUTABLE
TO NONCONTROLLING INTEREST		(10	)		(9	)		(15	)		(15	)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	266		$	285		$	337		$	456

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

2

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
(In millions)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	476		$	1,019
Receivables-
Customers, net of allowance for uncollectible accounts of $35 in 2011 and $36 in 2010		1,578			1,392
Other, net of allowance for uncollectible accounts of $8 in 2011 and 2010		256			176
Materials and supplies, at average cost		866			638
Prepaid taxes		474			199
Derivatives		265			182
Other		203			92
		4,118			3,698
PROPERTY, PLANT AND EQUIPMENT:
In service		39,568			29,451
Less — Accumulated provision for depreciation		11,593			11,180
		27,975			18,271
Construction work in progress		1,465			1,517
Property, plant and equipment held for sale, net		502			—
		29,942			19,788
INVESTMENTS:
Nuclear plant decommissioning trusts		2,051			1,973
Investments in lease obligation bonds		414			476
Nuclear fuel disposal trust		212			208
Other		479			345
		3,156			3,002
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		6,456			5,575
Regulatory assets		2,182			1,826
Intangible assets		973			256
Other		769			660
		10,380			8,317
	$	47,596		$	34,805
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	2,058		$	1,486
Short-term borrowings		656			700
Accounts payable		1,122			872
Accrued taxes		399			326
Accrued compensation and benefits		331			315
Derivatives		287			266
Other		691			733
		5,544			4,698
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 and 375,000,000 shares, respectively- 418,216,437 and 304,835,407 shares outstanding, respectively		42			31
Other paid-in capital		9,782			5,444
Accumulated other comprehensive loss		(1,433	)		(1,539	)
Retained earnings		4,607			4,609
Total common stockholders’ equity		12,998			8,545
Noncontrolling interest		(48	)		(32	)
Total equity		12,950			8,513
Long-term debt and other long-term obligations		16,491			12,579
		29,441			21,092
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		5,219			2,879
Retirement benefits		2,134			1,868
Asset retirement obligations		1,459			1,407
Deferred gain on sale and leaseback transaction		942			959
Adverse power contract liability		649			466
Other		2,208			1,436
		12,611			9,015
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	47,596		$	34,805

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

3

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30
(In millions)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	216		$	405
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		502			383
Amortization of regulatory assets		222			373
Nuclear fuel and lease amortization		92			76
Deferred purchased power and other costs		(168	)		(146	)
Deferred income taxes and investment tax credits, net		552			159
Deferred rents and lease market valuation liability		(61	)		(62	)
Accrued compensation and retirement benefits		49			(27	)
Commodity derivative transactions, net		(21	)		(29	)
Pension trust contribution		(262	)		—
Asset impairments		41			21
Cash collateral paid, net		(31	)		(63	)
Interest rate swap transactions		—			43
Decrease (increase) in operating assets-
Receivables		199			(156	)
Materials and supplies		24			(17	)
Prepayments and other current assets		(268	)		(81	)
Increase (decrease) in operating liabilities-
Accounts payable		(28	)		18
Accrued taxes		(66	)		(58	)
Accrued interest		(4	)		10
Other		43			9
Net cash provided from operating activities		1,031			858
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		503			—
Short-term borrowings, net		—			281
Redemptions and Repayments-
Long-term debt		(1,002	)		(407	)
Short-term borrowings, net		(44	)		—
Common stock dividend payments		(420	)		(335	)
Other		(76	)		(23	)
Net cash used for financing activities		(1,039	)		(484	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(1,018	)		(997	)
Proceeds from asset sales		—			116
Sales of investment securities held in trusts		1,703			1,915
Purchases of investment securities held in trusts		(1,807	)		(1,934	)
Customer acquisition costs		(2	)		(105	)
Cash investments		50			59
Cash received in Allegheny merger		590			—
Other		(51	)		(21	)
Net cash used for investing activities		(535	)		(967	)
Net change in cash and cash equivalents		(543	)		(593	)
Cash and cash equivalents at beginning of period		1,019			874
Cash and cash equivalents at end of period	$	476		$	281
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: merger with Allegheny, common stock issued	$	4,354		$	—

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

4

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In millions)	2011			2010			2011			2010
STATEMENTS OF INCOME
REVENUES:
Electric sales to non-affiliates	$	1,052		$	729		$	2,097		$	1,397
Electric sales to affiliates		170			539			431			1,146
Other		70			58			156			171
Total revenues		1,292			1,326			2,684			2,714
EXPENSES:
Fuel		316			343			659			671
Purchased power from affiliates		65			69			134			130
Purchased power from non-affiliates		329			310			626			760
Other operating expenses		429			304			910			608
Provision for depreciation		68			63			136			126
General taxes		30			22			60			49
Impairment of long-lived assets		7			—			20			2
Total expenses		1,244			1,111			2,545			2,346
OPERATING INCOME		48			215			139			368
OTHER INCOME (EXPENSE):
Investment income		16			13			22			14
Miscellaneous income (expense)		4			4			8			7
Interest expense — affiliates		(2	)		(2	)		(3	)		(5	)
Interest expense — other		(52	)		(51	)		(105	)		(101	)
Capitalized interest		10			24			20			44
Total other expense		(24	)		(12	)		(58	)		(41	)
INCOME BEFORE INCOME TAXES		24			203			81			327
INCOME TAXES		4			69			25			113
NET INCOME	$	20		$	134		$	56		$	214
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	20		$	134		$	56		$	214
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1			1			3			(9	)
Unrealized gain on derivative hedges		14			3			5			4
Change in unrealized gain on available-for-sale securities		8			6			15			11
Other comprehensive income		23			10			23			6
Income taxes related to other comprehensive income		10			4			8			2
Other comprehensive income, net of tax		13			6			15			4
COMPREHENSIVE INCOME	$	33		$	140		$	71		$	218

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

5

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
(In millions)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	6		$	9
Receivables-
Customers, net of allowance for uncollectible accounts of $18 in 2011 and $17 in 2010		450			366
Associated companies		490			478
Other, net of allowances for uncollectible accounts of $3 in 2011 and $7 in 2010		51			90
Notes receivable from associated companies		490			397
Materials and supplies, at average cost		499			545
Derivatives		221			182
Prepayments and other		49			59
		2,256			2,126
PROPERTY, PLANT AND EQUIPMENT:
In service		11,455			11,321
Less — Accumulated provision for depreciation		4,206			4,024
		7,249			7,297
Construction work in progress		694			1,063
Property, plant and equipment held for sale, net		487			—
		8,430			8,360
INVESTMENTS:
Nuclear plant decommissioning trusts		1,184			1,146
Other		10			12
		1,194			1,158
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles		129			134
Goodwill		24			24
Property taxes		41			41
Unamortized sale and leaseback costs		76			73
Derivatives		135			98
Other		75			48
		480			418
	$	12,360		$	12,062
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,088		$	1,132
Short-term borrowings-
Associated companies		541			12
Other		1			—
Accounts payable-
Associated companies		393			467
Other		191			241
Derivatives		242			266
Other		262			322
		2,718			2,440
CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding		1,488			1,490
Accumulated other comprehensive loss		(105	)		(120	)
Retained earnings		2,474			2,418
Total common stockholder’s equity		3,857			3,788
Long-term debt and other long-term obligations		3,000			3,181
		6,857			6,969
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		942			959
Accumulated deferred income taxes		216			58
Asset retirement obligations		875			892
Retirement benefits		295			285
Lease market valuation liability		194			217
Derivatives		85			81
Other		178			161
		2,785			2,653
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	12,360		$	12,062

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

6

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30
(In millions)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	56		$	214
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		136			126
Nuclear fuel and lease amortization		92			78
Deferred rents and lease market valuation liability		(58	)		(59	)
Deferred income taxes and investment tax credits, net		126			114
Asset impairments		28			21
Accrued compensation and retirement benefits		8			7
Commodity derivative transactions, net		(60	)		(29	)
Cash collateral paid, net		(40	)		(38	)
Decrease (increase) in operating assets-
Receivables		(36	)		(193	)
Materials and supplies		50			(29	)
Prepayments and other current assets		12			25
Decrease in operating liabilities-
Accounts payable		(124	)		(32	)
Accrued taxes		(29	)		(8	)
Other		21			21
Net cash provided from operating activities		182			218
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt		247			—
Short-term borrowings, net		530			76
Redemptions and repayments-
Long-term debt		(472	)		(295	)
Other		(11	)		(1	)
Net cash provided from (used for) financing activities		294			(220	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(334	)		(566	)
Proceeds from asset sales		—			116
Sales of investment securities held in trusts		513			957
Purchases of investment securities held in trusts		(545	)		(979	)
Loans to associated companies, net		(93	)		631
Customer acquisition costs		(2	)		(105	)
Leasehold improvement payments to associated companies		—			(51	)
Other		(18	)		(1	)
Net cash provided from (used for) investing activities		(479	)		2
Net change in cash and cash equivalents		(3	)		—
Cash and cash equivalents at beginning of period		9			—
Cash and cash equivalents at end of period	$	6		$	—

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

7

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	360,203		$	415,437		$	724,034		$	895,362
Excise and gross receipts tax collections		24,941			23,949			53,136			52,424
Total revenues		385,144			439,386			777,170			947,786
EXPENSES:
Purchased power from affiliates		69,134			134,050			162,396			287,727
Purchased power from non-affiliates		62,667			78,826			123,046			173,057
Other operating expenses		110,778			88,275			212,240			177,130
Provision for depreciation		22,470			22,014			44,346			43,894
Amortization of regulatory assets, net		2,405			9,424			3,179			38,769
General taxes		45,592			43,362			95,018			90,854
Total expenses		313,046			375,951			640,225			811,431
OPERATING INCOME		72,098			63,435			136,945			136,355
OTHER INCOME (EXPENSE):
Investment income		5,043			6,309			9,351			11,553
Miscellaneous income (expense)		(477	)		1,295			(187	)		1,003
Interest expense		(22,011	)		(22,155	)		(44,156	)		(44,465	)
Capitalized interest		510			295			841			503
Total other expense		(16,935	)		(14,256	)		(34,151	)		(31,406	)
INCOME BEFORE INCOME TAXES		55,163			49,179			102,794			104,949
INCOME TAXES		16,538			11,856			34,029			31,465
NET INCOME		38,625			37,323			68,765			73,484
Income attributable to noncontrolling interest		114			130			230			262
EARNINGS AVAILABLE TO PARENT	$	38,511		$	37,193		$	68,535		$	73,222
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	38,625		$	37,323		$	68,765		$	73,484
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1,122			322			1,461			4,337
Increase in unrealized gain on available-for-sale securities		1,591			520			1,569			811
Other comprehensive income		2,713			842			3,030			5,148
Income tax expense (benefit) related to other
comprehensive income		386			(26	)		(1,110	)		667
Other comprehensive income, net of tax		2,327			868			4,140			4,481
COMPREHENSIVE INCOME		40,952			38,191			72,905			77,965
COMPREHENSIVE INCOME ATTRIBUTABLE TO
NONCONTROLLING INTEREST		114			130			230			262
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	40,838		$	38,061		$	72,675		$	77,703

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

8

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
(In thousands)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	176		$	420,489
Receivables-
Customers, net of allowance for uncollectible accounts of $3,564 in 2011 and $4,086 in 2010		159,393			176,591
Associated companies		68,709			118,135
Other		32,798			12,232
Notes receivable from associated companies		95,884			16,957
Prepayments and other		35,339			6,393
		392,299			750,797
UTILITY PLANT:
In service		3,176,455			3,136,623
Less — Accumulated provision for depreciation		1,230,570			1,207,745
		1,945,885			1,928,878
Construction work in progress		66,656			45,103
		2,012,541			1,973,981
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds		177,835			190,420
Nuclear plant decommissioning trusts		133,354			127,017
Other		92,440			95,563
		403,629			413,000
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets		392,580			400,322
Pension assets		62,612			28,596
Property taxes		71,331			71,331
Unamortized sale and leaseback costs		27,628			30,126
Other		19,041			17,634
		573,192			548,009
	$	3,381,661		$	3,685,787
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,429		$	1,419
Short-term borrowings-
Associated companies		—			142,116
Other		166			320
Accounts payable-
Associated companies		94,821			99,421
Other		41,417			29,639
Accrued taxes		69,364			78,707
Accrued interest		25,374			25,382
Other		79,795			74,947
		312,366			451,951
CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding		783,871			951,866
Accumulated other comprehensive loss		(174,936	)		(179,076	)
Retained earnings		110,156			141,621
Total common stockholder’s equity		719,091			914,411
Noncontrolling interest		5,313			5,680
Total equity		724,404			920,091
Long-term debt and other long-term obligations		1,151,720			1,152,134
		1,876,124			2,072,225
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		749,687			696,410
Accumulated deferred investment tax credits		9,439			10,159
Retirement benefits		183,345			183,712
Asset retirement obligations		69,164			74,456
Other		181,536			196,874
		1,193,171			1,161,611
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	3,381,661		$	3,685,787

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

9

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30
(In thousands)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	68,765		$	73,484
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		44,346			43,894
Amortization of regulatory assets, net		3,179			38,769
Purchased power cost recovery reconciliation		(8,584	)		(1,514	)
Amortization of lease costs		(4,696	)		(4,619	)
Deferred income taxes and investment tax credits, net		62,216			4,964
Accrued compensation and retirement benefits		(8,328	)		(16,154	)
Accrued regulatory obligations		(3,309	)		(2,309	)
Cash collateral from (to) suppliers, net		(850	)		1,215
Pension trust contribution		(27,000	)		—
Decrease (increase) in operating assets-
Receivables		80,968			49,250
Prepayments and other current assets		(28,947	)		5,072
Decrease in operating liabilities-
Accounts payable		(22,253	)		(57,208	)
Accrued taxes		(9,360	)		(25,685	)
Other		4,261			(114	)
Net cash provided from operating activities		150,408			109,045
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(707	)		(2,957	)
Short-term borrowings, net		(142,270	)		(93,017	)
Common stock dividend payments		(268,000	)		(250,000	)
Other		(2,340	)		(881	)
Net cash used for financing activities		(413,317	)		(346,855	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(78,894	)		(71,698	)
Leasehold improvement payments from associated companies		—			18,375
Sales of investment securities held in trusts		19,595			59,804
Purchases of investment securities held in trusts		(25,547	)		(64,063	)
Loans to associated companies, net		(78,927	)		12,420
Cash investments		11,962			11,774
Other		(5,593	)		(1,298	)
Net cash used for investing activities		(157,404	)		(34,686	)
Net change in cash and cash equivalents		(420,313	)		(272,496	)
Cash and cash equivalents at beginning of period		420,489			324,175
Cash and cash equivalents at end of period	$	176		$	51,679

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

10

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	202,148		$	280,180		$	408,890		$	592,677
Excise tax collections		15,706			15,495			33,851			33,068
Total revenues		217,854			295,675			442,741			625,745
EXPENSES:
Purchased power from affiliates		36,040			99,422			82,208			208,815
Purchased power from non-affiliates		23,099			32,651			41,319			70,049
Other operating expenses		31,625			28,937			66,661			60,172
Provision for depreciation		18,488			18,336			36,914			36,447
Amortization of regulatory assets, net		18,166			30,807			41,536			75,946
General taxes		36,954			28,840			77,166			67,329
Total expenses		164,372			238,993			345,804			518,758
OPERATING INCOME		53,482			56,682			96,937			106,987
OTHER INCOME (EXPENSE):
Investment income		5,637			6,605			12,234			14,152
Miscellaneous income		1,038			675			1,674			1,257
Interest expense		(32,135	)		(33,262	)		(65,213	)		(66,883	)
Capitalized interest		36			7			63			33
Total other expense		(25,424	)		(25,975	)		(51,242	)		(51,441	)
INCOME BEFORE INCOME TAXES		28,058			30,707			45,695			55,546
INCOME TAXES		6,209			8,785			10,645			19,628
NET INCOME		21,849			21,922			35,050			35,918
Income attributable to noncontrolling interest		309			366			675			785
EARNINGS AVAILABLE TO PARENT	$	21,540		$	21,556		$	34,375		$	35,133
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	21,849		$	21,922		$	35,050		$	35,918
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and other postretirement benefits (charges)		2,975			3,228			5,942			(19,357	)
Income tax expense (benefit) related to other comprehensive income		860			976			398			(7,301	)
Other comprehensive income (loss), net of tax		2,115			2,252			5,544			(12,056	)
COMPREHENSIVE INCOME		23,964			24,174			40,594			23,862
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		309			366			675			785
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	23,655		$	23,808		$	39,919		$	23,077

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

11

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
(In thousands)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	244		$	238
Receivables-
Customers, net of allowance for uncollectible accounts of $2,801 in 2011 and $4,589 in 2010		97,997			183,744
Associated companies		32,348			77,047
Other		13,476			11,544
Notes receivable from associated companies		71,911			23,236
Materials and supplies, at average cost		13,784			398
Prepayments and other		6,431			3,258
		236,191			299,465
UTILITY PLANT:
In service		2,417,031			2,396,893
Less — Accumulated provision for depreciation		944,379			932,246
		1,472,652			1,464,647
Construction work in progress		59,281			38,610
		1,531,933			1,503,257
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		286,745			340,029
Other		10,048			10,074
		296,793			350,103
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,688,521			1,688,521
Regulatory assets		320,337			370,403
Pension assets		14,652			—
Property taxes		80,614			80,614
Other		12,884			11,486
		2,117,008			2,151,024
	$	4,181,925		$	4,303,849
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	188		$	161
Short-term borrowings from associated companies		23,303			105,996
Accounts payable-
Associated companies		51,001			32,020
Other		18,700			14,947
Accrued taxes		83,265			84,668
Accrued interest		18,551			18,555
Other		38,685			44,569
		233,693			300,916
CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 105,000,000 shares, 67,930,743 shares outstanding		887,053			887,087
Accumulated other comprehensive loss		(147,643	)		(153,187	)
Retained earnings		539,280			568,906
Total common stockholder’s equity		1,278,690			1,302,806
Noncontrolling interest		15,195			18,017
Total equity		1,293,885			1,320,823
Long-term debt and other long-term obligations		1,831,023			1,852,530
		3,124,908			3,173,353
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		640,059			622,771
Accumulated deferred investment tax credits		10,574			10,994
Retirement benefits		76,010			95,654
Other		96,681			100,161
		823,324			829,580
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	4,181,925		$	4,303,849

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

12

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30
(In thousands)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	35,050		$	35,918
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		36,914			36,447
Amortization of regulatory assets, net		41,536			75,946
Deferred income taxes and investment tax credits, net		17,221			(18,083	)
Accrued compensation and retirement benefits		5,421			5,421
Accrued regulatory obligations		(2,001	)		(444	)
Cash collateral from suppliers, net		—			685
Pension trust contribution		(35,000	)		—
Decrease (increase) in operating assets-
Receivables		140,455			51,757
Prepayments and other current assets		(17,469	)		5,392
Increase (decrease) in operating liabilities-
Accounts payable		10,135			(34,488	)
Accrued taxes		(346	)		(11,317	)
Other		(4,436	)		2,023
Net cash provided from operating activities		227,480			149,257
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(74	)		(54	)
Short-term borrowings, net		(104,228	)		(136,013	)
Common stock dividend payments		(64,000	)		(100,000	)
Other		(5,239	)		(3,367	)
Net cash used for financing activities		(173,541	)		(239,434	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(52,743	)		(44,373	)
Loans to associated companies, net		(48,676	)		2,322
Redemptions of lessor notes		53,283			48,608
Other		(5,797	)		(2,365	)
Net cash provided from (used for) investing activities		(53,933	)		4,192
Net change in cash and cash equivalents		6			(85,985	)
Cash and cash equivalents at beginning of period		238			86,230
Cash and cash equivalents at end of period	$	244		$	245

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

13

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	93,048		$	114,691		$	199,373		$	240,122
Excise tax collections		6,270			6,059			13,572			13,100
Total revenues		99,318			120,750			212,945			253,222
EXPENSES:
Purchased power from affiliates		17,037			47,106			52,554			101,725
Purchased power from non-affiliates		16,114			15,223			30,102			33,713
Other operating expenses		32,549			25,499			69,136			51,044
Provision for depreciation		7,959			8,013			15,890			15,963
Deferral of regulatory assets, net		(7,054	)		(1,800	)		(18,532	)		(10,299	)
General taxes		12,438			12,282			26,890			25,743
Total expenses		79,043			106,323			176,040			217,889
OPERATING INCOME		20,275			14,427			36,905			35,333
OTHER INCOME (EXPENSE):
Investment income		2,599			5,057			5,521			8,857
Miscellaneous income (expense)		396			(945	)		(1,233	)		(2,351	)
Interest expense		(10,415	)		(10,455	)		(20,858	)		(20,942	)
Capitalized interest		135			80			237			158
Total other expense		(7,285	)		(6,263	)		(16,333	)		(14,278	)
INCOME BEFORE INCOME TAXES		12,990			8,164			20,572			21,055
INCOME TAXES		1,429			948			3,164			6,330
NET INCOME		11,561			7,216			17,408			14,725
Income attributable to noncontrolling interest		2			2			4			5
EARNINGS AVAILABLE TO PARENT	$	11,559		$	7,214		$	17,404		$	14,720
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	11,561		$	7,216		$	17,408		$	14,725
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		575			714			1,167			1,010
Increase (decrease) in unrealized gain on available-for-sale securities		754			(330	)		2,059			39
Other comprehensive income		1,329			384			3,226			1,049
Income tax expense related to other comprehensive income		351			65			685			235
Other comprehensive income, net of tax		978			319			2,541			814
COMPREHENSIVE INCOME		12,539			7,535			19,949			15,539
COMPREHENSIVE INCOME ATTRIBUTABLE TO NONCONTROLLING INTEREST		2			2			4			5
COMPREHENSIVE INCOME AVAILABLE TO PARENT	$	12,537		$	7,533		$	19,945		$	15,534

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

14

THE TOLEDO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
(In thousands)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	12		$	149,262
Receivables-
Customers, net of allowance for uncollectible accounts of $1,142 in 2011 and $1 in 2010		45,931			29
Associated companies		48,340			31,777
Other, net of allowance for uncollectible accounts of $339 in 2011 and $330 in 2010		5,272			18,464
Notes receivable from associated companies		128,815			96,765
Prepayments and other		12,052			2,306
		240,422			298,603
UTILITY PLANT:
In service		955,002			947,203
Less — Accumulated provision for depreciation		453,517			446,401
		501,485			500,802
Construction work in progress		17,386			12,604
		518,871			513,406
OTHER PROPERTY AND INVESTMENTS:
Investment in lessor notes		82,153			103,872
Nuclear plant decommissioning trusts		79,018			75,558
Other		1,448			1,492
		162,619			180,922
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		500,576			500,576
Regulatory assets		89,112			72,059
Pension assets		24,603			—
Property taxes		24,990			24,990
Other		42,341			23,750
		681,622			621,375
	$	1,603,534		$	1,614,306
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	188		$	199
Accounts payable-
Associated companies		22,144			17,168
Other		12,524			7,351
Accrued taxes		23,699			24,401
Accrued interest		5,933			5,931
Lease market valuation liability		36,900			36,900
Other		18,060			23,145
		119,448			115,095
CAPITALIZATION:
Common stockholder’s equity-
Common stock, $5 par value, authorized 60,000,000 shares, 29,402,054 shares outstanding		147,010			147,010
Other paid-in capital		178,157			178,182
Accumulated other comprehensive loss		(46,642	)		(49,183	)
Retained earnings		100,937			117,534
Total common stockholder’s equity		379,462			393,543
Noncontrolling interest		2,593			2,589
Total equity		382,055			396,132
Long-term debt and other long-term obligations		600,524			600,493
		982,579			996,625
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		168,429			132,019
Accumulated deferred investment tax credits		5,715			5,930
Retirement benefits		51,764			71,486
Asset retirement obligations		29,737			28,762
Lease market valuation liability		180,850			199,300
Other		65,012			65,089
		501,507			502,586
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	1,603,534		$	1,614,306

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

15

THE TOLEDO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30
(In thousands)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	17,408		$	14,725
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		15,890			15,963
Deferral of regulatory assets, net		(18,532	)		(10,299	)
Deferred rents and lease market valuation liability		(43,851	)		(42,264	)
Deferred income taxes and investment tax credits, net		41,457			16,503
Accrued compensation and retirement benefits		1,085			2,600
Accrued regulatory obligations		(1,193	)		(632	)
Pension trust contribution		(45,000	)		—
Cash collateral from (to) suppliers, net		(14	)		343
Increase (decrease) in operating assets-
Receivables		(48,807	)		52,754
Prepayments and other current assets		(9,758	)		3,608
Increase (decrease) in operating liabilities-
Accounts payable		3,661			(61,195	)
Accrued taxes		(701	)		(4,007	)
Other		5,771			(8,960	)
Net cash used for operating activities		(82,584	)		(20,861	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt		(105	)		(111	)
Short-term borrowings, net		—			(225,975	)
Common stock dividend payments		(34,000	)		(130,000	)
Other		(1,742	)		(112	)
Net cash used for financing activities		(35,847	)		(356,198	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(17,386	)		(20,237	)
Leasehold improvement payments from associated companies		—			32,829
Loans to associated companies, net		(32,050	)		(10,818	)
Redemptions of lessor notes		21,739			20,485
Sales of investment securities held in trusts		28,401			106,814
Purchases of investment securities held in trusts		(30,050	)		(107,978	)
Other		(1,473	)		(2,905	)
Net cash provided from (used for) investing activities		(30,819	)		18,190
Net change in cash and cash equivalents		(149,250	)		(358,869	)
Cash and cash equivalents at beginning of period		149,262			436,712
Cash and cash equivalents at end of period	$	12		$	77,843

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

16

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	576,977		$	709,606		$	1,211,000		$	1,400,998
Excise tax collections		11,120			11,012			23,607			23,364
Total revenues		588,097			720,618			1,234,607			1,424,362
EXPENSES:
Purchased power		328,463			410,470			698,631			824,486
Other operating expenses		78,603			75,177			164,682			170,837
Provision for depreciation		26,773			27,093			52,087			55,064
Amortization of regulatory assets, net		40,046			81,326			121,633			150,774
General taxes		15,115			14,902			32,526			31,338
Total expenses		489,000			608,968			1,069,559			1,232,499
OPERATING INCOME		99,097			111,650			165,048			191,863
OTHER INCOME (EXPENSE):
Miscellaneous income		3,554			1,649			5,464			3,482
Interest expense		(31,125	)		(30,041	)		(61,782	)		(59,464	)
Capitalized interest		618			156			1,045			289
Total other expense		(26,953	)		(28,236	)		(55,273	)		(55,693	)
INCOME BEFORE INCOME TAXES		72,144			83,414			109,775			136,170
INCOME TAXES		30,383			33,521			48,461			57,051
NET INCOME	$	41,761		$	49,893		$	61,314		$	79,119
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	41,761		$	49,893		$	61,314		$	79,119
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		4,290			4,135			8,511			20,063
Unrealized gain on derivative hedges		69			69			138			138
Other comprehensive income		4,359			4,204			8,649			20,201
Income tax expense related to other comprehensive income		1,612			1,441			3,202			7,999
Other comprehensive income, net of tax		2,747			2,763			5,447			12,202
COMPREHENSIVE INCOME	$	44,508		$	52,656		$	66,761		$	91,321

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

17

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS
(Unaudited)

	June 30,			December 31,
(In thousands)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	42		$	4
Receivables-
Customers, net of allowance for uncollectible accounts of $3,306 in 2011 and $3,769 in 2010		259,313			323,044
Associated companies		66,069			53,780
Other		25,580			26,119
Notes receivable — associated companies		16,288			177,228
Prepaid taxes		135,679			10,889
Other		15,421			12,654
		518,392			603,718
UTILITY PLANT:
In service		4,589,369			4,562,781
Less — Accumulated provision for depreciation		1,682,577			1,656,939
		2,906,792			2,905,842
Construction work in progress		112,573			63,535
		3,019,365			2,969,377
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		212,419			207,561
Nuclear plant decommissioning trusts		190,422			181,851
Other		2,118			2,104
		404,959			391,516
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,810,936			1,810,936
Regulatory assets		469,490			513,395
Other		34,028			27,938
		2,314,454			2,352,269
	$	6,257,170		$	6,316,880
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	33,315		$	32,402
Short-term borrowings-
Associated companies		360,917			—
Other		50,000			—
Accounts payable-
Associated companies		56,544			28,571
Other		159,720			158,442
Accrued compensation and benefits		35,578			35,232
Customer deposits		23,684			23,385
Accrued taxes		1,346			2,509
Accrued interest		18,059			18,111
Other		13,487			22,263
		752,650			320,915
CAPITALIZATION:
Common stockholder’s equity-
Common stock, $10 par value, authorized 16,000,000 shares- 13,628,447 shares outstanding		136,284			136,284
Other paid-in capital		2,008,847			2,508,874
Accumulated other comprehensive loss		(248,095	)		(253,542	)
Retained earnings		288,484			227,170
Total common stockholder’s equity		2,185,520			2,618,786
Long-term debt and other long-term obligations		1,754,582			1,769,849
		3,940,102			4,388,635
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		761,844			715,527
Power purchase contract liability		239,943			233,492
Nuclear fuel disposal costs		196,868			196,768
Retirement benefits		71,711			182,364
Asset retirement obligations		111,831			108,297
Other		182,221			170,882
		1,564,418			1,607,330
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	6,257,170		$	6,316,880

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

18

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)

	Six Months Ended
	June 30
(In thousands)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	61,314		$	79,119
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		52,087			55,064
Amortization of regulatory assets, net		121,633			150,774
Deferred purchased power and other costs		(70,998	)		(67,664	)
Deferred income taxes and investment tax credits, net		51,222			(1,425	)
Accrued compensation and retirement benefits		1,319			2,608
Cash collateral paid, net		(235	)		(23,400	)
Pension trust contribution		(105,000	)		—
Decrease (increase) in operating assets-
Receivables		58,466			(46,788	)
Prepaid taxes		(124,790	)		(111,968	)
Increase (decrease) in operating liabilities-
Accounts payable		13,856			11,924
Accrued taxes		(1,167	)		10,368
Other		612			(6,446	)
Net cash provided from operating activities		58,319			52,166
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		410,917			57,850
Redemptions and Repayments-
Long-term debt		(14,671	)		(13,830	)
Common stock dividend payments		—			(90,000	)
Equity payment to parent		(500,000	)		—
Other		(1,452	)		—
Net cash used for financing activities		(105,206	)		(45,980	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(98,153	)		(80,727	)
Loans to associated companies, net		160,940			85,049
Sales of investment securities held in trusts		375,885			281,242
Purchases of investment securities held in trusts		(385,448	)		(289,454	)
Other		(6,299	)		(2,224	)
Net cash provided from (used for) investing activities		46,925			(6,114	)
Net change in cash and cash equivalents		38			72
Cash and cash equivalents at beginning of period		4			27
Cash and cash equivalents at end of period	$	42		$	99

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

19

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010
REVENUES:
Electric sales	$	265,363		$	422,030		$	603,779		$	873,590
Gross receipts tax collections		14,601			20,629			33,401			42,196
Total revenues		279,964			442,659			637,180			915,786
EXPENSES:
Purchased power from affiliates		34,935			149,000			84,824			310,080
Purchased power from non-affiliates		100,836			85,276			253,879			177,204
Other operating expenses		50,075			90,151			97,307			192,134
Provision for depreciation		12,766			13,440			25,189			26,198
Amortization of regulatory assets, net		22,167			48,589			54,261			97,389
General taxes		17,152			19,894			39,302			41,634
Total expenses		237,931			406,350			554,762			844,639
OPERATING INCOME		42,033			36,309			82,418			71,147
OTHER INCOME (EXPENSE):
Interest income		13			880			106			2,097
Miscellaneous income		915			1,381			1,885			3,554
Interest expense		(13,130	)		(13,002	)		(26,187	)		(26,775	)
Capitalized interest		228			159			375			285
Total other expense		(11,974	)		(10,582	)		(23,821	)		(20,839	)
INCOME BEFORE INCOME TAXES		30,059			25,727			58,597			50,308
INCOME TAXES		13,281			8,618			19,232			20,884
NET INCOME	$	16,778		$	17,109		$	39,365		$	29,424
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	16,778		$	17,109		$	39,365		$	29,424
OTHER COMPREHENSIVE INCOME
Pension and other postretirement benefits		2,227			2,162			4,190			11,871
Unrealized gain on derivative hedges		84			84			168			168
Other comprehensive income		2,311			2,246			4,358			12,039
Income tax expense related to other comprehensive income		869			724			1,632			4,901
Other comprehensive income, net of tax		1,442			1,522			2,726			7,138
COMPREHENSIVE INCOME	$	18,220		$	18,631		$	42,091		$	36,562

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

20

METROPOLITAN EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
(In thousands)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	157		$	243,220
Receivables-
Customers, net of allowance for uncollectible accounts of $3,087 in 2011 and $3,868 in 2010		143,820			178,522
Associated companies		12,849			24,920
Other		16,437			13,007
Notes receivable from associated companies		10,432			11,028
Prepaid taxes		27,083			343
Other		1,443			2,289
		212,221			473,329
UTILITY PLANT:
In service		2,266,437			2,247,853
Less — Accumulated provision for depreciation		859,055			846,003
		1,407,382			1,401,850
Construction work in progress		42,604			23,663
		1,449,986			1,425,513
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		301,188			289,328
Other		840			884
		302,028			290,212
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		416,499			416,499
Regulatory assets		341,488			295,856
Power purchase contract asset		65,861			111,562
Other		54,587			31,699
		878,435			855,616
	$	2,842,670		$	3,044,670
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	28,760		$	28,760
Short-term borrowings-
Associated companies		238,399			124,079
Other		50,000			—
Accounts payable-
Associated companies		24,377			33,942
Other		48,262			29,862
Accrued taxes		12,844			60,856
Accrued interest		16,011			16,114
Other		29,605			29,278
		448,258			322,891
CAPITALIZATION:
Common stockholder’s equity-
Common stock, without par value, authorized 900,000 shares, 740,905 and 859,500 shares outstanding, respectively		842,023			1,197,076
Accumulated other comprehensive loss		(139,657	)		(142,383	)
Retained earnings		46,772			32,406
Total common stockholder’s equity		749,138			1,087,099
Long-term debt and other long-term obligations		704,486			718,860
		1,453,624			1,805,959
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		494,716			473,009
Accumulated deferred investment tax credits		6,656			6,866
Nuclear fuel disposal costs		44,471			44,449
Asset retirement obligations		199,162			192,659
Retirement benefits		22,276			29,121
Power purchase contract liability		121,924			116,027
Other		51,583			53,689
		940,788			915,820
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	2,842,670		$	3,044,670

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

21

METROPOLITAN EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30
(In thousands)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	39,365		$	29,424
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		25,189			26,198
Amortization of regulatory assets, net		54,261			97,389
Deferred costs recoverable as regulatory assets		(41,699	)		(38,358	)
Deferred income taxes and investment tax credits, net		11,972			(12,079	)
Accrued compensation and retirement benefits		(510	)		(1,573	)
Cash collateral from suppliers, net		174			50
Pension trust contribution		(35,000	)		—
Decrease (increase) in operating assets-
Receivables		46,240			(29,439	)
Prepaid taxes		(26,740	)		(31,246	)
Increase (decrease) in operating liabilities-
Accounts payable		5,148			733
Accrued taxes		(47,676	)		9,519
Accrued interest		(103	)		(1,277	)
Other		10,903			7,553
Net cash provided from operating activities		41,524			56,894
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		164,320			17,898
Redemptions and Repayments-
Common stock		(150,000	)		—
Long-term debt		(14,784	)		(100,000	)
Common stock dividend payments		(80,000	)		—
Equity payment to parent		(150,000	)		—
Net cash used for financing activities		(230,464	)		(82,102	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(46,647	)		(54,405	)
Sales of investment securities held in trusts		501,260			376,610
Purchases of investment securities held in trusts		(506,220	)		(381,219	)
Loans to associated companies, net		596			85,943
Other		(3,112	)		(1,715	)
Net cash provided from (used for) investing activities		(54,123	)		25,214
Net change in cash and cash equivalents		(243,063	)		6
Cash and cash equivalents at beginning of period		243,220			120
Cash and cash equivalents at end of period	$	157		$	126

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

22

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended						Six Months Ended
	June 30						June 30
(In thousands)	2011			2010			2011			2010
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	238,942		$	350,335		$	547,258		$	736,271
Gross receipts tax collections		12,727			16,162			29,256			33,686
Total revenues		251,669			366,497			576,514			769,957
EXPENSES:
Purchased power from affiliates		54,635			152,945			102,119			321,345
Purchased power from non-affiliates		64,459			86,829			205,895			178,252
Other operating expenses		44,570			67,070			85,898			139,464
Provision for depreciation		15,770			16,605			30,343			31,287
Amortization (deferral) of regulatory assets, net		12,608			(10,522	)		25,615			(20,488	)
General taxes		14,665			18,647			35,401			35,181
Total expenses		206,707			331,574			485,271			685,041
OPERATING INCOME		44,962			34,923			91,243			84,916
OTHER INCOME (EXPENSE):
Miscellaneous income		644			1,310			669			2,923
Interest expense		(17,361	)		(17,630	)		(34,595	)		(34,920	)
Capitalized interest		41			183			63			323
Total other expense		(16,676	)		(16,137	)		(33,863	)		(31,674	)
INCOME BEFORE INCOME TAXES		28,286			18,786			57,380			53,242
INCOME TAXES		13,568			5,812			25,356			22,969
NET INCOME	$	14,718		$	12,974		$	32,024		$	30,273
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	14,718		$	12,974		$	32,024		$	30,273
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits		1,890			1,830			3,475			10,377
Unrealized gain on derivative hedges		17			16			33			32
Other comprehensive income		1,907			1,846			3,508			10,409
Income tax expense related to other comprehensive income		678			483			1,233			3,767
Other comprehensive income, net of tax		1,229			1,363			2,275			6,642
COMPREHENSIVE INCOME	$	15,947		$	14,337		$	34,299		$	36,915

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

23

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

	June 30,			December 31,
(In thousands)	2011			2010
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2		$	5
Receivables-
Customers, net of allowance for uncollectible accounts of $2,856 in 2011 and $3,369 in 2010		121,511			148,864
Associated companies		65,989			54,052
Other		11,420			11,314
Notes receivable from associated companies		13,498			14,404
Prepaid taxes		26,372			14,026
Other		1,423			1,592
		240,215			244,257
UTILITY PLANT:
In service		2,552,303			2,532,629
Less — Accumulated provision for depreciation		947,315			935,259
		1,604,988			1,597,370
Construction work in progress		62,592			30,505
		1,667,580			1,627,875
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		162,154			152,928
Non-utility generation trusts		126,786			80,244
Other		292			297
		289,232			233,469
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		768,628			768,628
Regulatory assets		222,804			163,407
Power purchase contract asset		4,000			5,746
Other		15,272			19,287
		1,010,704			957,068
	$	3,207,731		$	3,062,669
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	45,000		$	45,000
Short-term borrowings-
Associated companies		159,902			101,338
Accounts payable-
Associated companies		77,121			35,626
Other		29,217			41,420
Accrued taxes		3,397			5,075
Accrued interest		17,454			17,378
Other		23,280			22,541
		355,371			268,378
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		913,486			913,519
Accumulated other comprehensive loss		(161,251	)		(163,526	)
Retained earnings		23,017			60,993
Total common stockholder’s equity		863,804			899,538
Long-term debt and other long-term obligations		1,072,417			1,072,262
		1,936,221			1,971,800
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		415,899			371,877
Retirement benefits		188,407			187,621
Power purchase contract liability		160,130			116,972
Asset retirement obligations		101,441			98,132
Other		50,262			47,889
		916,139			822,491
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	3,207,731		$	3,062,669

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

24

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Six Months Ended
	June 30
(In thousands)	2011			2010
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	32,024		$	30,273
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation		30,343			31,287
Amortization (deferral) of regulatory assets, net		25,615			(20,488	)
Deferred costs recoverable as regulatory assets		(38,291	)		(38,955	)
Deferred income taxes and investment tax credits, net		46,687			42,943
Accrued compensation and retirement benefits		4,733			4,216
Cash collateral paid, net		(1,276	)		(3,613	)
Decrease (increase) in operating assets-
Receivables		19,561			3,266
Prepaid taxes		(12,346	)		(37,504	)
Increase (decrease) in operating liabilities-
Accounts payable		23,449			(4,603	)
Accrued taxes		(12,373	)		(1,339	)
Other		13,153			10,227
Net cash provided from operating activities		131,279			15,710
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		25,000			—
Short-term borrowings, net		58,564			25,313
Redemptions and Repayments-
Long-term debt		(25,000	)		—
Common stock dividend payments		(70,000	)		—
Other		(1,353	)		5
Net cash provided from (used for) financing activities		(12,789	)		25,318
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(64,177	)		(58,293	)
Loans to associated companies, net		906			498
Sales of investment securities held in trusts		265,223			133,934
Purchases of investment securities held in trusts		(314,738	)		(113,067	)
Other		(5,707	)		(4,104	)
Net cash used for investing activities		(118,493	)		(41,032	)
Net change in cash and cash equivalents		(3	)		(4	)
Cash and cash equivalents at beginning of period		5			14
Cash and cash equivalents at end of period	$	2		$	10

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

25

FIRSTENERGY CORP. AND SUBSIDIARIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note		Page
Number		Number
1	Organization and Basis of Presentation		27
2	Merger		27
3	Earnings Per Share		31
4	Fair Value of Instruments		31
5	Derivative Instruments		45
6	Pension Benefits and Other Postretirement Benefits		50
7	Variable Interest Entities		52
8	Income Taxes		53
9	Commitments, Guarantees and Contingencies		54
10	Regulatory Matters		61
11	Stock-Based Compensation Plans		70
12	New Accounting Standards and Interpretations		72
13	Segment Information		72
14	Impairment of Long-Lived Assets		74
15	Asset Retirement Obligations		75
16	Supplemental Guarantor Information		75

26

COMBINED NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

FirstEnergy is a diversified energy company that holds, directly or indirectly, all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), ATSI, JCP&L, Met-Ed, Penelec, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL), FES and its subsidiaries FGCO and NGC, and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy (See Note 2, Merger).

FirstEnergy and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the NJBPU. These unaudited interim financial statements and notes were prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These unaudited interim financial 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, 2010 for FirstEnergy, FES and the Utility Registrants, as applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 7, Variable Interest Entities). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

2. MERGER

Merger

On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub) and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.

The total consideration in the merger was based on the closing price of a share of FirstEnergy common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):

Shares of Allegheny common stock outstanding on February 24, 2011		170
Exchange ratio		0.667
Number of shares of FirstEnergy common stock issued		113
Closing price of FirstEnergy common stock on February 24, 2011	$	38.16
Fair value of shares issued by FirstEnergy	$	4,327
Fair value of replacement share-based compensation awards relating to pre-merger service		27
Total consideration transferred	$	4,354

27

The allocation of the total consideration transferred to the assets acquired and liabilities assumed includes adjustments for the fair value of coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The preliminary allocation of the purchase price is as follows:

(In millions)
Current assets	$	1,494
Property, plant and equipment		9,656
Investments		138
Goodwill		881
Other noncurrent assets		1,347
Current liabilities		(716	)
Noncurrent liabilities		(3,452	)
Long-term debt and other long-term obligations		(4,994	)
	$	4,354

The allocation of purchase price in the table above reflects a refinement made during the quarter ended June 30, 2011 in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This resulted in an increase in noncurrent assets of approximately $85 million and decreases in current assets and goodwill of $15 million and $71 million, respectively. The impact of the refinements on the amortization of purchase accounting adjustments recorded during the quarter ended March 31, 2011 was not significant. Further modifications to the purchase price allocation may occur as a result of continuing review of the assets acquired and liabilities assumed.

The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The preliminary estimate of goodwill from the merger of $881 million has been assigned to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.

Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:

			Competitive		Regulated
	Regulated		Energy		Independent		Other/
(In millions)	Distribution		Services		Transmission		Corporate		Consolidated
Balance as of December 31, 2010	$	5,551	$	24	$	—	$	—	$	5,575
Merger with Allegheny		—		881		—		—		881
Balance as of June 30, 2011	$	5,551	$	905	$	—	$	—	$	6,456

28

The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:

	Preliminary		Weighted Average
(In millions)	Valuation		Amortization Period
Above market contracts:
Energy contracts	$	189	10 years
NUG contracts		124	25 years
Coal supply contracts		516	8 years
		829
Below market contracts:
NUG contracts		143	13 years
Coal supply contracts		83	7 years
Transportation contract		35	8 years
		261
Net intangible assets	$	568

The fair value measurements of intangible assets and liabilities were based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.

The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.

The fair value of coal supply contracts was determined in a similar manner based on the present value of the above/below market cash flows attributable to the contracts. The fair value adjustment for these contracts is being amortized based on expected deliveries under each contract.

As of June 30, 2011, intangible assets on FirstEnergy’s Consolidated Balance Sheet, including those recorded in connection with the merger, include the following:

	Intangible
(In millions)	Assets
Purchase contract assets
NUG	$	198
OVEC		54
		252
Intangible assets
Coal contracts		487
FES customer intangible assets		129
Energy contracts		105
		721
Total intangible assets	$	973

Acquired land easements and software with a fair value of $169 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of June 30, 2011.

In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $7 million ($5 million net of tax) and $7 million ($5 million net of tax) during the three months ended June 30, 2011 and 2010, respectively and approximately $89 million ($72 million net of tax) and $21 million ($15 million net of tax) during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. Merger transaction costs recognized in the first six months of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.

29

FirstEnergy also recorded approximately $10 million ($6 million net of tax) and $85 million ($66 million net of tax) in merger integration costs during the three and six months ended June 30 2011, respectively, including an inventory valuation adjustment. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review, FirstEnergy management determined that the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ($42 million net of tax) in the first quarter of 2011.

Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statement of Income for the periods subsequent to the February 25, 2011 merger date are as follows:

	April 1 –		February 26 –
(In millions, except per share amounts)	June 30, 2011		June 30, 2011
Total revenues	$	1,181	$	1,618
Earnings available to FirstEnergy Corp.(1)		63		17
Basic Earnings Per Share	$	0.15	$	0.04
Diluted Earnings Per Share	$	0.15	$	0.04

⁽¹⁾ Includes Allegheny’s after-tax merger costs of $4 million and $56 million, respectively.

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with Allegheny had taken place on January 1, 2010. The unaudited pro forma information has been calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010, together with the consequential tax effects.

FirstEnergy and Allegheny both incurred non-recurring costs directly related to the merger that have been included in the pro forma earnings presented below. Combined pre-tax transaction costs incurred were approximately $7 million and $11 million in the three months ended June 30, 2011 and 2010, respectively, and approximately $90 million and $39 million in the six months ended June 30, 2011 and 2010, respectively. In addition, during the six months ended June 30, 2011, $85 million of pre-tax merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.

The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Three Months Ended				Six Months Ended
(Pro forma amounts in millions, except	June 30				June 30
per share amounts)	2011		2010		2011		2010
Revenues	$	4,062	$	4,401	$	8,848	$	9,086
Earnings available to FirstEnergy	$	186	$	389	$	323	$	644
Basic Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.54
Diluted Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.53

30

3. EARNINGS PER SHARE

Basic earnings per share of common stock are computed using the weighted average of actual common shares outstanding during the relevant 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 would be issued if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

	Three Months				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2011		2010		2011		2010
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	181	$	265	$	231	$	420
Weighted average number of basic shares outstanding(1)		418		304		380		304
Assumed exercise of dilutive stock options and awards		2		1		2		1
Weighted average number of diluted shares outstanding(1)		420		305		382		305
Basic earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.38
Diluted earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.37

⁽¹⁾ Includes 113 million shares issued to AE stockholders for the periods subsequent to the merger date. (See Note 2)

4. FAIR VALUE MEASUREMENTS

(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 June 30, 2011 and December 31 2010:

	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy(1)	$	18,371	$	19,436	$	13,928	$	14,845
FES		4,056		4,310		4,279		4,403
OE		1,158		1,367		1,159		1,321
CEI		1,831		2,083		1,853		2,035
TE		600		690		600		653
JCP&L		1,795		2,008		1,810		1,962
Met-Ed		729		828		742		821
Penelec		1,120		1,231		1,120		1,189

⁽¹⁾ Includes debt assumed in the Allegheny merger (See Note 2) with a carrying value and a fair value as of June 30, 2011 of $4,530 million and $4,127 million, respectively.

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those obligations 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 debt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and other subsidiaries.

(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 their cost basis, and the likelihood of recovery of the security’s entire amortized cost basis.

31

Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to 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 because the difference between investments held in the 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 trusts’ 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 funds’ custodian or managers and their parents or subsidiaries.

Available-For-Sale Securities

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

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in NDT, nuclear fuel disposal trusts and NUG trusts as of June 30, 2011 and December 31, 2010:

	June 30, 2011(1)								December 31, 2010(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities
FirstEnergy	$	2,015	$	48	$	—	$	2,063	$	1,699	$	31	$	—	$	1,730
FES		1,023		26		—		1,049		980		13		—		993
OE		128		3		—		131		123		1		—		124
TE		52		1		—		53		42		—		—		42
JCP&L		353		9		—		362		281		9		—		290
Met-Ed		249		5		—		254		127		4		—		131
Penelec		210		4		—		214		145		4		—		149
Equity securities
FirstEnergy	$	187	$	11	$	—	$	198	$	268	$	69	$	—	$	337
FES		90		6		—		96		—		—		—		—
TE		24		2		—		26		—		—		—		—
JCP&L		21		1		—		22		80		17		—		97
Met-Ed		32		1		—		33		125		35		—		160
Penelec		20		1		—		21		63		16		—		79

(1)	Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $130 million; FES – $39 million; OE – $3 million; JCP&L – $19 million; Met-Ed – $14 million and Penelec – $55 million.
(2)	Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $193 million; FES – $153 million; OE – $3 million; TE – $34 million; JCP&L – $3 million; Met-Ed – $(3) million and Penelec – $4 million.

32

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded to earnings and interest and dividend income for the three months and six months ended June 30, 2011 and 2010 were as follows:

Three Months Ended June 30,
								Interest and
2011	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	734	$	22	$	(16	)	$	28
FES		297		10		(7	)		17
OE		12		—		—			1
TE		15		1		(1	)		1
JCP&L		159		4		(2	)		4
Met-Ed		165		4		(3	)		3
Penelec		86		3		(3	)		2

								Interest and
2010	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,183	$	46	$	(36	)	$	16
FES		685		41		(35	)		9
OE		57		2		—			—
TE		76		2		—			—
JCP&L		91		—		—			3
Met-Ed		233		1		(1	)		2
Penelec		41		—		—			2

Six Months Ended June 30,
								Interest and
2011	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,703	$	122	$	(45	)	$	52
FES		513		22		(23	)		32
OE		20		—		—			2
TE		28		1		(2	)		1
JCP&L		376		26		(6	)		8
Met-Ed		501		48		(7	)		5
Penelec		265		25		(7	)		4

								Interest and
2010	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,915	$	83	$	(86	)	$	37
FES		957		54		(58	)		22
OE		60		2		—			1
TE		107		3		—			1
JCP&L		281		9		(9	)		7
Met-Ed		377		9		(12	)		3
Penelec		134		6		(7	)		3

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities as of June 30, 2011 and December 31, 2010:

	June 30, 2011								December 31, 2010
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt Securities
FirstEnergy	$	414	$	84	$	—		498	$	476	$	91	$	—	$	567
OE		178		45		—		223		190		51		—		241
CEI		287		39		—		326		340		41		—		381

Investments in emission allowances, employee benefits and cost and equity method investments totaling $345 million as of June 30, 2011 and $259 million as of December 31, 2010, are not required to be disclosed and are excluded from the amounts reported above.

33

Notes Receivable

The table below provides the approximate fair value and related carrying amounts of notes receivable as of June 30, 2011 and December 31, 2010. 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 2013 to 2021.

	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Notes Receivable
FirstEnergy	$	6	$	7	$	7	$	8
TE		82		94		104		118

34

(C) RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.

The three levels of the fair value hierarchy are as follows:

Level 1	— Quoted prices for identical instruments in active markets.
Level 2	— Quoted prices for similar instruments in active markets;
	— quoted prices for identical or similar instruments in markets that are not active; and
	— model-derived valuations for which all significant inputs are observable market data.
Level 3	— Valuation inputs are unobservable and significant to the fair value measurement.

The following tables set forth financial assets and liabilities measured at fair value on a recurring basis by level within the fair value hierarchy. There were no significant transfers between levels during the three months and six months ended June 30, 2011.

35

FirstEnergy Corp.

The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	868		$	—		$	868
Derivative assets — commodity contracts		—		312			—			312
Derivative assets — FTRs		—		—			13			13
Derivative assets — interest rate swaps		—		4			—			4
Derivative assets — NUG contracts(1)		—		—			75			75
Equity securities(2)		198		—			—			198
Foreign government debt securities		—		206			—			206
U.S. government debt securities		—		673			—			673
U.S. state debt securities		—		306			—			306
Other(4)		—		146			—			146
Total assets	$	198	$	2,515		$	88		$	2,801
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(362	)	$	—		$	(362	)
Derivative liabilities — FTRs		—		—			(7	)		(7	)
Derivative liabilities — interest rate swaps		—		(5	)		—			(5	)
Derivative liabilities — NUG contracts(1)		—		—			(522	)		(522	)
Total liabilities	$	—	$	(367	)	$	(529	)	$	(896	)
Net assets (liabilities)(3)	$	198	$	2,148		$	(441	)	$	1,905

December 31, 2010	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	597		$	—		$	597
Derivative assets — commodity contracts		—		250			—			250
Derivative assets — NUG contracts(1)		—		—			122			122
Equity securities(2)		338		—			—			338
Foreign government debt securities		—		149			—			149
U.S. government debt securities		—		595			—			595
U.S. state debt securities		—		379			—			379
Other(4)		—		219			—			219
Total assets	$	338	$	2,189		$	122		$	2,649
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—		$	(348	)
Derivative liabilities — NUG contracts(1)		—		—			(466	)		(466	)
Total liabilities	$	—	$	(348	)	$	(466	)	$	(814	)
Net assets (liabilities)(3)	$	338	$	1,841		$	(344	)	$	1,835

(1)	NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $6 million and $(7) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(4)	Primarily consists of cash and cash equivalents.

36

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:

	Derivative Asset(1)			Derivative Liability(1)			Net(1)
	(In millions)
January 1, 2011 Balance	$	122		$	(466	)	$	(344	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(40	)		(203	)		(243	)
Purchases		13			(3	)		10
Issuances		—			—			—
Sales		—			—			—
Settlements		(6	)		154			148
Transfers into  Level 3		—			(12	)		(12	)
June 30, 2011 Balance	$	89		$	(530	)	$	(441	)
January 1, 2010 Balance	$	200		$	(643	)	$	(443	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(71	)		(110	)		(181	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(7	)		287			280
Transfers into  Level 3		—			—			—
December 31, 2010 Balance	$	122		$	(466	)	$	(344	)

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

37

FirstEnergy Solutions Corp.

The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2			Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	562		$	—	$	562
Derivative assets — commodity contracts		—		283			—		283
Derivative assets — FTRs		—		—			2		2
Equity securities(3)		96		—			—		96
Foreign government debt securities		—		160			—		160
U.S. government debt securities		—		316			—		316
U.S. state debt securities		—		7			—		7
Other(2)		—		42			—		42
Total assets	$	96	$	1,370		$	2	$	1,468
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(327	)	$	—	$	(327	)
Total liabilities	$	—	$	(327	)	$	—	$	(327	)
Net assets (liabilities)(1)	$	96	$	1,043		$	2	$	1,141

December 31, 2010	Level 1		Level 2			Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	528		$	—	$	528
Derivative assets — commodity contracts		—		241			—		241
Foreign government debt securities		—		147			—		147
U.S. government debt securities		—		308			—		308
U.S. state debt securities		—		6			—		6
Other(2)		—		148			—		148
Total assets	$	—	$	1,378		$	—	$	1,378
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—	$	(348	)
Total liabilities	$	—	$	(348	)	$	—	$	(348	)
Net assets (liabilities)(1)	$	—	$	1,030		$	—	$	1,030

(1)	Excludes $7 million as of December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)	Primarily consists of cash and cash equivalents.
(3)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy during the period ending June 30, 2011:

	Derivative Asset			Derivative Liability		Net
	FTRs			FTRs		FTRs
	(In millions)
January 1, 2011 Balance	$	—		$	—	$	—
Realized gain (loss)		—			—		—
Unrealized gain (loss)		1			—		1
Purchases		2			—		2
Issuances		—			—		—
Sales		—			—		—
Settlements		(1	)		—		(1	)
Transfers in (out) of Level 3		—			—		—
June 30, 2011 Balance	$	2		$	—	$	2

38

Ohio Edison Company

The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	131	$	—	$	131
Other		—		2		—		2
Total assets(1)	$	—	$	133	$	—	$	133

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	124	$	—	$	124
Other		—		2		—		2
Total assets(1)	$	—	$	126	$	—	$	126

⁽¹⁾ Excludes $2 million and $1 million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

The Toledo Edison Company

The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	16	$	—	$	16
Equity securities(3)		26		—		—		26
U.S. government debt securities		—		33		—		33
U.S. state debt securities		—		1		—		1
Other(2)		—		3		—		3
Total assets(1)	$	26	$	53	$	—	$	79

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	7	$	—	$	7
U.S. government debt securities		—		33		—		33
U.S. state debt securities		—		1		—		1
Other(2)		—		35		—		35
Total assets(1)	$	—	$	76	$	—	$	76

(1)	Excludes $(1) million and $2 million as of June 30, 2011 and December 31, 2010, respectively of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)	Primarily consists of cash and cash equivalents.
(3)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

39

Jersey Central Power & Light Company

The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	81	$	—		$	81
Derivative assets — NUG contracts(1)		—		—		5			5
Equity securities(2)		21		—		—			21
Foreign government debt securities		—		13		—			13
U.S. government debt securities		—		54		—			54
U.S. state debt securities		—		215		—			215
Other		—		14		—			14
Total assets	$	21	$	377	$	5		$	403
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(240	)	$	(240	)
Total liabilities	$	—	$	—	$	(240	)	$	(240	)
Net assets (liabilities)(3)	$	21	$	377	$	(235	)	$	163

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	23	$	—		$	23
Derivative assets — commodity contracts		—		2		—			2
Derivative assets — NUG contracts(1)		—		—		6			6
Equity securities(2)		96		—		—			96
U.S. government debt securities		—		33		—			33
U.S. state debt securities		—		236		—			236
Other		—		4		—			4
Total assets	$	96	$	298	$	6		$	400
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(233	)	$	(233	)
Total liabilities	$	—	$	—	$	(233	)	$	(233	)
Net assets (liabilities)(3)	$	96	$	298	$	(227	)	$	167

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $5 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

40

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	6		$	(233	)	$	(227	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(1	)		(71	)		(72	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		—			64			64
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	5		$	(240	)	$	(235	)
January 1, 2010 Balance	$	8		$	(399	)	$	(391	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(1	)		36			35
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(1	)		130			129
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	6		$	(233	)	$	(227	)

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

41

Metropolitan Edison Company

The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	138	$	—		$	138
Derivative assets — NUG contracts(1)		—		—		66			66
Equity securities(2)		33		—		—			33
Foreign government debt securities		—		20		—			20
U.S. government debt securities		—		87		—			87
U.S. state debt securities		—		2		—			2
Other		—		22		—			22
Total assets	$	33	$	269	$	66		$	368
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(122	)	$	(122	)
Total liabilities	$	—	$	—	$	(122	)	$	(122	)
Net assets (liabilities)(3)	$	33	$	269	$	(56	)	$	246

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	32	$	—		$	32
Derivative assets — commodity contracts		—		5		—			5
Derivative assets — NUG contracts(1)		—		—		112			112
Equity securities(2)		160		—		—			160
Foreign government debt securities		—		1		—			1
U.S. government debt securities		—		88		—			88
U.S. state debt securities		—		2		—			2
Other		—		14		—			14
Total assets	$	160	$	142	$	112		$	414
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(116	)	$	(116	)
Total liabilities	$	—	$	—	$	(116	)	$	(116	)
Net assets (liabilities)(3)	$	160	$	142	$	(4	)	$	298

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $(1) million and $(9) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

42

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	112		$	(116	)	$	(4	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(42	)		(36	)		(78	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(4	)		30			26
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	66		$	(122	)	$	(56	)
January 1, 2010 Balance	$	176		$	(143	)	$	33
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(59	)		(38	)		(97	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(5	)		65			60
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	112		$	(116	)	$	(4	)

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

43

Pennsylvania Electric Company

The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	69	$	—		$	69
Derivative assets — NUG contracts(1)		—		—		4			4
Equity securities(2)		20		—		—			20
Foreign government debt securities				12					12
U.S. government debt securities		—		52		—			52
U.S. state debt securities		—		81		—			81
Other		—		53		—			53
Total assets	$	20	$	267	$	4		$	291
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(160	)	$	(160	)
Total liabilities	$	—	$	—	$	(160	)	$	(160	)
Net assets (liabilities)(3)	$	20	$	267	$	(156	)	$	131

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	8	$	—		$	8
Derivative assets — commodity contracts		—		2		—			2
Derivative assets — NUG contracts(1)		—		—		4			4
Equity securities(2)		81		—		—			81
U.S. government debt securities		—		9		—			9
U.S. state debt securities		—		133		—			133
Other		—		5		—			5
Total assets	$	81	$	157	$	4		$	242
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(117	)	$	(117	)
Total liabilities	$	—	$	—	$	(117	)	$	(117	)
Net assets (liabilities)(3)	$	81	$	157	$	(113	)	$	125

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $1 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table.

44

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG and commodity contracts held by Penelec and classified as Level 3 in the fair value hierarchy during the periods ended June 30, 2011 and December 31, 2010:

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	4		$	(117	)	$	(113	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		—			(88	)		(88	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		—			45			45
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	4		$	(160	)	$	(156	)
January 1, 2010 Balance	$	16		$	(101	)	$	(85	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(11	)		(108	)		(119	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(1	)		92			91
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	4		$	(117	)	$	(113	)

⁽¹⁾ Changes in the fair value of NUG contracts are subject to regulatory accounting 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’s Risk Policy Committee, comprised 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 practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualify and are designated as cash flow hedge instruments are recorded in AOCL. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. FirstEnergy has contractual derivative agreements through December 2018.

Cash Flow Hedges

FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating interest rates and commodity prices. The effective portion of gains and losses on the derivative contract are reported as a component of AOCL with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

As of December 31, 2010, commodity derivative contracts designated in cash flow hedging relationships were $104 million of assets and $101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships. Total net unamortized gains included in AOCL associated with dedesignated cash flow hedges totaled $8 million as of June 30, 2011. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expenses totaled $14 million and $19 million during the three months and six months ended June 30, 2011, respectively. Approximately $3 million is expected to be amortized to expense during the next twelve months.

FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of June 30, 2011, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $84 million ($55 million net of tax) as of June 30, 2011. Based on current estimates, approximately $10 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCL into interest expense totaled $3 million during the three months ended June 30, 2011 and 2010 and $6 million during the six months ended June 30, 2011 and 2010.

45

Fair Value Hedges

FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of June 30, 2011, no fixed-for-floating interest rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $113 million ($73 million net of tax) as of June 30, 2011. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $6 million and $2 million during the three months ended June 30, 2011 and 2010, respectively and $11 million and $3 million during the six months ended June 30, 2011 and 2010, respectively.

Commodity Derivatives

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

Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas; primarily natural gas is 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. Interest rate swaps include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.

As of June 30, 2011, FirstEnergy’s net liability position under commodity derivative contracts was $45 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted $81 million and Allegheny posted $2 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $49 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on derivative contracts held as of June 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $31 million ($20 million net of tax) during the next twelve months.

FTRs

FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.

The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.

46

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

Derivatives not designated as hedging instruments as of June 30, 2011:

Derivative Assets
	Fair Value
	June 30,		December 31,
	2011		2010
	(In millions)
Power Contracts
Current Assets	$	210	$	96
Noncurrent Assets		102		40
FTRs
Current Assets		13		—
Noncurrent Assets		—		—
NUGs
Current Assets		4		3
Noncurrent Assets		71		119
Interest Rate Swaps
Current Assets		4		—
Noncurrent Assets		—		—
Other
Current Assets		—		10
Noncurrent Assets		—		—
Total Derivatives	$	404	$	268

Derivative Liabilities
	Fair Value
	June 30,		December 31,
	2011		2010
	(In millions)
Power Contracts
Current Liabilities	$	274	$	209
Noncurrent Liabilities		88		38
FTRs
Current Liabilities		7		—
Noncurrent Liabilities		—		—
NUGs
Current Liabilities		317		229
Noncurrent Liabilities		205		238
Interest Rate Swaps
Current Liabilities		5		—
Noncurrent Liabilities		—		—
Other
Current Liabilities		—		—
Noncurrent Liabilities		—		—
Total Derivatives	$	896	$	714

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2011:

	Purchases		Sales			Net			Units
	(In thousands)
Power Contracts		45,573		(59,549	)		(13,976	)	MWH
FTRs		53,656		—			53,656		MWH
Interest Rate Swaps		200,000		(200,000	)		—		notional dollars
NUGs		26,903		—			26,903		MWH

47

The effect of derivative instruments on the Consolidated Statements of Income during the three months and six months ended June 30, 2011 and 2010, are summarized in the following tables:

	Three Months Ended June 30,
	Power					Interest
	Contracts			FTRs		Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	14		$	—	$	—	$	—		$	14
Effective Gain (Loss) Reclassified to: (1)
Purchase Power Expense		—			—		—		—			—
Revenues		—			—		—		—			—
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	—		$	—	$	—	$	3		$	3
Effective Gain (Loss) Reclassified to:(1)
Purchase Power Expense		(3	)		—		—		—			(3	)
Revenues		(5	)		—		—		—			(5	)
Fuel Expense		—			—		—		(4	)		(4	)

Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	33		$	—		$	—	$	—	$	33
Revenues		(4	)		—			—		—		(4	)
Other Operating Expense		(34	)		13			—		—		(21	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		1			—			—		—		1
Revenues		(39	)		18			—		—		(21	)
Other Operating Expense		—			(59	)		—		—		(59	)
2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	66		$	—		$	—	$	—	$	66
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(26	)		—			—		—		(26	)

Derivatives Not in a Hedging	Three Months Ended June 30,
Relationship with Regulatory Offset(2)	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(147	)	$	2		$	(145	)
Unrealized Gain (Loss) to Regulatory Assets:		147			(2	)		145
Realized Gain (Loss) to Derivative Instrument:		62			—			62
Realized Gain (Loss) to Regulatory Assets:		(62	)		—			(62	)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(35	)		—		$	(35	)
Unrealized Gain (Loss) to Regulatory Assets:		35			—			35
Realized Gain (Loss) to Derivative Instrument:		68			—			68
Realized Gain (Loss) to Regulatory Assets:		(68	)		—			(68	)

48

	Six Months Ended June 30,
	Power						Interest
	Contracts			FTRs			Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	5		$	—		$	—	$	—		$	5
Effective Gain (Loss) Reclassified to: (1)
Purchase Power Expense		16			—			—		—			16
Revenues		(12	)		—			—		—			(12	)
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(2	)	$	—		$	—	$	6		$	4
Effective Gain (Loss) Reclassified to:(1)
Purchase Power Expense		(7	)		—			—		—			(7	)
Revenues		(5	)		—			—		—			(5	)
Fuel Expense		—			—			—		(8	)		(8	)
Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	61		$	—		$	—	$	—		$	61
Revenues		(3	)		—			—		—			(3	)
Other Operating Expense		(54	)		13			1		—			(40	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(36	)		—			—		—			(36	)
Revenues		(29	)		26			—		—			(3	)
Other Operating Expense		—			(87	)		—		—			(87	)
2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	39		$	—		$	—	$	—		$	39
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(49	)		—			—		—			(49	)

Derivatives Not in a Hedging	Six Months Ended June 30,
Relationship with Regulatory Offset(2)	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(236	)	$	2		$	(234	)
Unrealized Gain (Loss) to Regulatory Assets:		236			(2	)		234
Realized Gain (Loss) to Derivative Instrument:		134			(10	)		124
Realized Gain (Loss) to Regulatory Assets:		(134	)		10			(124	)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(259	)		—		$	(259	)
Unrealized Gain (Loss) to Regulatory Assets:		259			—			259
Realized Gain (Loss) to Derivative Instrument:		146			(9	)		137
Realized Gain (Loss) to Regulatory Assets:		(146	)		9			(137	)

(1)	The ineffective portion was immaterial.
(2)	Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

49

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or refund to) customers during the three months and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other		Total
	(In millions)
Outstanding net asset (liability) as of April 1, 2011	$	(362	)	$	—	$	(362	)
Additions/Change in value of existing contracts		(147	)		2		(145	)
Settled contracts		62			—		62
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	2	$	(445	)
Outstanding net asset (liability) as of April 1, 2010	$	(590	)	$	10	$	(580	)
Additions/Change in value of existing contracts		(35	)		—		(35	)
Settled contracts		68			—		68
Outstanding net asset (liability) as of June 30, 2010	$	(557	)	$	10	$	(547	)

	Six Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts		(236	)		2			(234	)
Settled contracts		134			(10	)		124
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	2		$	(445	)
Outstanding net asset (liability) as of January 1, 2010	$	(444	)	$	19		$	(425	)
Additions/Change in value of existing contracts		(259	)		—			(259	)
Settled contracts		146			(9	)		137
Outstanding net asset (liability) as of June 30, 2010	$	(557	)	$	10		$	(547	)

⁽¹⁾ Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.

50

As result of the merger with Allegheny, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and postretirement benefit plans other than pensions as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny’s pension plans and postretirement benefit plans other than pensions at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s postretirement benefit plans other than pensions.

The components of the consolidated net periodic cost for pension and OPEB benefits (including amounts capitalized) were as follows:

	Three Months Ended						Six Months Ended
	June 30						June 30
Pension Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	34		$	25		$	62		$	49
Interest cost		97			79			181			157
Expected return on plan assets		(115	)		(90	)		(216	)		(181	)
Amortization of prior service cost		4			3			7			6
Recognized net actuarial loss		48			47			97			94
Curtailments(1)		—			—			(2	)		—
Special termination benefits(1)		—			—			9			—
Net periodic cost	$	68		$	64		$	138		$	125

⁽¹⁾ Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger.

	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	3		$	3		$	7		$	5
Interest cost		12			11			23			22
Expected return on plan assets		(10	)		(9	)		(20	)		(18	)
Amortization of prior service cost		(52	)		(48	)		(100	)		(96	)
Recognized net actuarial loss		14			15			28			30
Net periodic cost (credit)	$	(33	)	$	(28	)	$	(62	)	$	(57	)

Pension and OPEB obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic OPEB (including amounts capitalized) recognized by FirstEnergy’s subsidiaries were as follows:

	Three Months Ended				Six Months Ended
	June 30				June 30
Pension Benefit Cost	2011		2010		2011		2010
	(In millions)
FES	$	22	$	22	$	43	$	44
OE		5		6		11		11
CEI		5		5		10		11
TE		2		2		3		4
JCP&L		5		6		11		12
Met-Ed		3		3		5		5
Penelec		4		5		9		9
Other FirstEnergy Subsidiaries		22		15		46		29
	$	68	$	64	$	138	$	125

51

	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefit Credit	2011			2010			2011			2010
	(In millions)
FES	$	(8	)	$	(7	)	$	(14	)	$	(13	)
OE		(5	)		(6	)		(12	)		(12	)
CEI		(2	)		(1	)		(3	)		(3	)
TE		—			—			(1	)		(1	)
JCP&L		(2	)		(2	)		(3	)		(4	)
Met-Ed		(2	)		(2	)		(5	)		(4	)
Penelec		(2	)		(2	)		(5	)		(4	)
Other FirstEnergy Subsidiaries		(12	)		(8	)		(19	)		(16	)
	$	(33	)	$	(28	)	$	(62	)	$	(57	)

7. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries perform qualitative analyses to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

VIEs included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $295 million was outstanding as of June 30, 2011.

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 primarily the result of net losses of the noncontrolling interests ($15 million) and distributions to owners ($4 million) during the six months ended June 30, 2011.

In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance.

PATH-WV

PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.

Because of the nature of PATH-WV’s operations and its FERC approved rate mechanism, FirstEnergy’s maximum exposure to loss, through AE, consists of its equity investment in PATH-WV, which was $27 million at June 30, 2011.

Power Purchase Agreements

FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the Utilities if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. 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 four of these NUG entities, its subsidiaries do not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

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Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended June 30, 2011, were $55 million, $47 million and $21 million for JCP&L, PE and WP, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the three months and six months ended June 30, 2010 were $53 million and $117 million, respectively.

In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity that WP may hold a variable interest, for which WP has taken the scope exception. As of June 30, 2011, WP’s reserve for this adverse purchase power commitment was $59 million, including a current liability of $11 million, and is being amortized over the life of the commitment.

Loss Contingencies

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

FES and the Ohio Companies are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. 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 as of June 30, 2011:

	Maximum		Discounted Lease		Net
	Exposure		Payments, net(1)		Exposure
	(In millions)
FES	$	1,348	$	1,156	$	192
OE		635		445		190
CEI(2)		624		69		555
TE(2)		624		303		321

(1)	The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6 billion.
(2)	CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

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. As a result of the merger with Allegheny in the first quarter of 2011, FirstEnergy’s unrecognized tax benefits increased by $97 million. During the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate for the second quarter and first six months of 2011. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first six months of 2011. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs for tax years 2005-2008, as well as reaching a settlement on an unrelated state tax matter in the second quarter of 2010, FirstEnergy recognized approximately $70 million of net income tax benefits, including $13 million that favorably affected FirstEnergy’s effective tax rate for the second quarter of 2010. The remaining portion of the income tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item.

As of June 30, 2011, it is reasonably possible that approximately $46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $4 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized income tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.

FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The interest associated with the settlement of the claim noted above favorably affected FirstEnergy’s effective tax rate by $6 million in the first half of 2011. During the first six months of 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest as a result of the merger with Allegheny. The reversal of accrued interest associated with the recognized income tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $11 million in the first six months of 2010. The net amount of interest accrued as of June 30, 2011 was $10 million, compared with $3 million as of December 31, 2010.

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As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by $28 million in the first six months of 2011.

As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law in March 2010, beginning in 2013 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts under prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. That charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.

Allegheny is currently under audit by the IRS for tax years 2007 and 2008. The 2009 federal return was filed and is subject to review. State tax returns for tax years 2006 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. Tax returns for all state jurisdictions are open from 2006-2009. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and the 2010 tax year audit began in February 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

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 June 30, 2011, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.6 billion), and surety bonds and LOCs ($0.4 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. FirstEnergy believes the likelihood is remote that such parental guarantees of $0.2 billion (included in the $0.8 billion discussed above) as of June 30, 2011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $625 million, consisting of $522 million due to a below investment grade credit rating (of which $265 million is due to an acceleration of payment or funding obligation) and $103 million due to “material adverse event” contractual clauses. 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 $666 million.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $136 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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolios as of June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $138 million and $2 million, respectively. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one-year time horizon), FES would be required to post an additional $17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.

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FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.

Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy 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.

CAA Compliance

FirstEnergy is required to meet federally-approved SO₂ and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂ and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.

In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on coal-fired Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these three complaints.

The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, 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. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the Portland coal-fired plant based on “modifications” dating back to 1986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of Keystone, and Penelec, as former owner and operator of Shawville, are unable to predict the outcome of this matter.

In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City’s air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. Mission is seeking indemnification from Penelec, the co-owner and operator of Homer City prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claims and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. The scope of Penelec’s indemnity obligation to and from Mission is under dispute and Penelec is unable to predict the outcome of this matter.

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In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired 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. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.

In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired plants: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.

In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants in West Virginia.

FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.

State Air Quality Compliance

In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO₂ and NO_X, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NO_X, SO₂ and mercury, based on a PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NO_X and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.

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In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.

National Ambient Air Quality Standards

The EPA’s CAIR requires reductions of NOx and SO₂ emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court 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. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the Federal Register). CSAPR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. FGCO’s future cost of compliance may be substantial and changes to FirstEnergy’s operations may result. Management is currently assessing the impact of CSAPR, other environmental proposals and other factors on FirstEnergy’s competitive fossil generating facilities, including but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operations of its coal-fired plants.

Hazardous Air Pollutant Emissions

On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Depending on the action taken by the EPA and how any future regulations are ultimately implemented, FirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FirstEnergy’s operations may result.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2) effective January 2, 2011 for existing facilities under the CAA’s PSD program. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO₂ pollutants.

At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO₂, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

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In 2009, the U.S. Court of Appeals for the Second Circuit and 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. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy received notice of a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.

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 of its 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, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.

In 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 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). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore Plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

In April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer 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. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.

FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.

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Monongahela River Water Quality

In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry coal-fired plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP’s recommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy’s future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

The Little Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.

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The Utility Registrants 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 June 30, 2011, based on estimates of the total costs of cleanup, the Utility Registrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $133 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $61 million) have been accrued through June 30, 2011. Included in the total are accrued liabilities of approximately $63 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. 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. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class action attempt, and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have yet to take any affirmative steps to pursue their individual claims.

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2011, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.

On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.

In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the DOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.

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ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. The parties expect a ruling sometime in the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.

Other Legal Matters

In February 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.

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.

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

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards 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 implemented and enforced by the ReliabilityFirst Corporation.

FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirst and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 resulting in customers losing power for up to eleven hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

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On August 23, 2010, FirstEnergy self-reported to ReliabilityFirst a vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirst issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirst on September 27, 2010. In March 2011, ReliabilityFirst submitted its proposed findings and settlement, although a final determination has not yet been made by FERC.

Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting certain investigations with regard to certain matters of compliance by Allegheny.

(B) MARYLAND

By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below.

In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.

In March 2009, the MDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

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On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules, with proposed rules to be filed by September 15, 2011. Separately, on April 7, 2011, the MDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the MDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.

(C) NEW JERSEY

In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). In its order of June 15, 2011, the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and the Division of Rate Counsel which resolved both Petitions, resulting in a net reduction in recovery of $0.8 million annually for all components of the SBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).

(D) OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI’s integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to 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 were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.

Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy

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requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. The PUCO has not yet acted on that application.

In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed applications for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO has not yet acted on the applications for rehearing.

(E) PENNSYLVANIA

The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds will continue over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately $254 million ($189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).

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The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.

WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates, which the PPUC granted in part by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.

In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s OCA filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.

In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.

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By Tentative Order entered in September 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.

(F) VIRGINIA

In September 2010, PATH-VA filed an application with the VSCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.

(G) WEST VIRGINIA

In August 2009, MP and PE filed with the WVPSC a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:

• a $40 million annualized base rate increase effective June 29, 2010;

• a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective in January 2011;

• a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and

• a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.

In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.

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(H) FERC MATTERS

Rates for Transmission Service Between MISO and PJM

In November 2004, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. 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 SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.

PJM Transmission Rate

In April 2007, 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, 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 based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing"— meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit study analysis as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing, are currently pending before FERC.

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From late April 2011 through June 2011, FERC issued other orders that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement between ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreement of ATSI’s responsibility for certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI’s move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs — are a class of transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.

As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost- benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.

FirstEnergy cannot predict the outcome of these proceedings at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge’s ruling.

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In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. FirstEnergy cannot predict the outcome of this matter.

Transmission Expansion

TrAIL Project. TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.

PATH Project. The PATH Project is comprised of a 765 kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.

Seneca Pumped Storage Project Relicensing

The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’s regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD) in the license docket.

On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PAD documents necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’ to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps. of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’s petition, including motions to dismiss FirstEnergy’s petition. The “project boundary” issue is pending before FERC.

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The next steps in the relicensing process are for FirstEnergy and the Seneca Nation to define and perform certain environmental and operational studies to support their respective applications. These steps are expected to run through approximately November of 2013. FirstEnergy cannot predict the outcome of these proceedings at this time.

11. STOCK-BASED COMPENSATION PLANS

FirstEnergy has four types of stock-based compensation programs — LTIP, EDCP, ESOP and DCPD, as described below.

Allegheny’s stock-based awards were converted into FirstEnergy stock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and, where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of Allegheny common stock.

(A) LTIP

FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.

Under FirstEnergy’s LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to be settled in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. There were 5.6 million shares available for future awards as of June 30, 2011.

Restricted Stock and Restricted Stock Units

Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:

	Six Months
	Ended
	June 30, 2011
Restricted stock and stock units outstanding as of January 1, 2011		1,878,022
Granted		891,881
Converted Allegheny restricted stock		645,197
Exercised		(428,686	)
Forfeited		(71,775	)
Restricted stock and stock units outstanding as of June 30, 2011		2,914,639

The 891,881 shares of restricted common stock granted during the six months ended June 30, 2011 had a grant-date fair value of $33.2 million and a weighted-average vesting period of 2.74 years.

Restricted stock units include awards that will be settled in a specific number of shares of common stock after the service condition has been met. Restricted stock units also include performance-based awards that will be settled after the service condition has been met in a specified number of shares of common stock based on FirstEnergy’s performance compared to annual target performance metrics.

Compensation expense recognized during the six months ended June 30, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $27 million and $20 million, respectively.

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Stock Options

Stock option activity for the six months ended June 30, 2011 was as follows:

				Weighted
				Average
	Number of			Exercise
Stock Option Activities	Shares			Price
Stock options outstanding as of January 1, 2011 (all exercisable)		2,889,066		$	35.18
Options granted		662,122			37.75
Converted Allegheny options		1,805,811			41.75
Options exercised		(691,304	)		31.38
Options forfeited/expired		(78,978	)		71.71
Stock options outstanding as of June 30, 2011		4,586,717		$	38.09
(3,924,595 options exercisable)

Compensation expense recognized for stock options during the six months ended June 30, 2011 was $0.3 million. No expense was recognized during the six months ended June 30, 2010. Options granted during the six months ended June 30, 2011 had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.

Options outstanding by exercise price as of June 30, 2011 were as follows:

			Weighted		Remaining
	Shares Under		Average		Contractual
Exercise Prices	Options		Exercise Price		Life in Years
$20.02 – $30.74		1,045,122	$	26.54		2.02
$30.89 – $40.93		3,160,440		37.30		4.17
$42.72 – $51.82		3,883		51.02		0.70
$53.06 – $62.97		54,559		56.15		3.02
$64.52 – $71.82		9,042		67.50		5.24
$73.39 – $80.47		311,003		80.17		3.81
$81.19 – $89.59		2,668		85.39		6.09
Total		4,586,717	$	38.08		3.64

Performance Shares

Performance shares will be settled in cash and are accounted for as liability awards. Compensation expense (income) recognized for performance shares during the six months ended June 30, 2011 and 2010, net of amounts capitalized, totaled $2 million and $(6) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the six months ended June 30, 2011 and 2010.

(B) ESOP

During 2011, shares of FirstEnergy common stock were purchased on the open market and contributed to participants’ accounts. Total ESOP-related compensation expense for the six months ended June 30, 2011 and 2010, net of amounts capitalized and dividends on common stock, were $19 million and $10 million, respectively.

(C) EDCP

There was no material compensation expense recognized on EDCP stock units during the six months ended June 30, 2011 and 2010.

(D) DCPD

DCPD expenses recognized during the six months ended June 30, 2011 and 2010 were approximately $2 million in each period. The net liability recognized for DCPD of approximately $6 million as of June 30, 2011 is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.

Of the 1.7 million stock units authorized under the EDCP and DCPD, 1,076,779 stock units were available for future awards as of June 30, 2011.

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12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective for FirstEnergy in the first quarter of 2012. FirstEnergy does not expect this amendment to have a material effect on its financial statements.

In June 2011, the FASB issued new accounting guidance that revises the manner in which entities presents comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is effective for FirstEnergy in the first quarter of 2012. This amendment will not have a material effect on FirstEnergy’s financial statements.

13. SEGMENT INFORMATION

With the completion of the Allegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” segment consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.

The changes in FirstEnergy’s reportable segments during 2011 consisted primarily of the following:

• Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.

• A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.

• AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.

The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

72

The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.

The Competitive Energy Services segment, through FES, supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.

This business segment controls approximately 20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.

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

Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.

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Segment Financial Information

			Competitive		Regulated
	Regulated		Energy		Independent		Other/			Reconciling
Three Months Ended	Distribution		Services		Transmission		Corporate			Adjustments			Consolidated
	(In millions)
June 30, 2011
External revenues	$	2,485	$	1,495	$	105	$	(30	)	$	(7	)	$	4,048
Internal revenues		—		318		—		—			(306	)		12
Total revenues		2,485		1,813		105		(30	)		(313	)		4,060
Depreciation and amortization		240		107		18		7			—			372
Investment income (loss), net		27		15		—		1			(12	)		31
Net interest charges		145		67		11		21			1			245
Income taxes		108		7		18		(30	)		(2	)		101
Net income (loss)		184		12		31		(51	)		(5	)		171
Total assets		26,932		17,146		2,339		1,179			—			47,596
Total goodwill		5,551		905		—		—			—			6,456
Property additions		302		197		45		25			—			569
June 30, 2010
External revenues	$	2,314	$	795	$	59	$	(21	)	$	(8	)	$	3,139
Internal revenues		19		539		—		—			(558	)		—
Total revenues		2,333		1,334		59		(21	)		(566	)		3,139
Depreciation and amortization		264		71		13		3			—			351
Investment income (loss), net		28		13		—		—			(10	)		31
Net interest charges		124		33		5		9			(4	)		167
Income taxes		81		75		7		(12	)		(17	)		134
Net income (loss)		132		121		11		(20	)		12			256
Total assets		21,457		11,102		993		914			—			34,466
Total goodwill		5,551		24		—		—			—			5,575
Property additions		157		290		15		27			—			489
Six Months Ended
June 30, 2011
External revenues	$	4,753	$	2,736	$	172	$	(53	)	$	(16	)	$	7,592
Internal revenues		—		661		—		—			(617	)		44
Total revenues		4,753		3,397		172		(53	)		(633	)		7,636
Depreciation and amortization		485		195		31		13			—			724
Investment income (loss), net		52		21		—		1			(22	)		52
Net interest charges		276		122		20		40			—			458
Income taxes		164		10		25		(50	)		30			179
Net income (loss)		280		17		44		(86	)		(39	)		216
Total assets		26,932		17,146		2,339		1,179			—			47,596
Total goodwill		5,551		905		—		—			—			6,456
Property additions		479		411		72		56			—			1,018
June 30, 2010
External revenues	$	4,798	$	1,514	$	116	$	(43	)	$	(14	)	$	6,371
Internal revenues		19		1,213		—		—			(1,165	)		67
Total revenues		4,817		2,727		116		(43	)		(1,179	)		6,438
Depreciation and amortization		577		148		25		6			—			756
Investment income (loss), net		54		14		—		1			(22	)		47
Net interest charges		248		66		10		22			(7	)		339
Income taxes		143		117		14		(24	)		(5	)		245
Net income (loss)		235		190		23		(39	)		(4	)		405
Total assets		21,457		11,102		993		914			—			34,466
Total goodwill		5,551		24		—		—			—			5,575
Property additions		309		619		29		40			—			997

Reconciling adjustments primarily consist of elimination of intersegment transactions.

14. IMPAIRMENT OF LONG-LIVED ASSETS

FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. The following events described in the sections below occurred during for the first six months of 2011 that indicated the carrying value of certain assets may not be recoverable.

74

Fremont Energy Center

On March 11, 2011, FirstEnergy and American Municipal Power, Inc., entered into an agreement for the sale of Fremont Energy Center, which 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. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income during the quarter ended March 31, 2011. On July 28, 2011, FirstEnergy closed the sale of Fremont Energy Center to American Municipal Power, Inc.

Peaking Facilities

During the first six months of 2011, FirstEnergy assessed the carrying values of certain peaking facilities that will more likely than not be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market. The result of this evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. FirstEnergy recorded impairment charges of $7 million and $21 million during the three months and six months ended June 30, 2011, respectively, as a result of the recoverability evaluation.

15. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of sludge disposal ponds and closure of coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).

The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES, OE, JCP&L, Met-Ed and Penelec use an expected cash flow approach to measure the fair value of their nuclear decommissioning ARO.

During the first quarter of 2011, studies were completed to update the estimated cost of decommissioning the Perry nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and OE and reduced the liability for each subsidiary in the amounts of $40 million and $6 million, respectively.

During the second quarter of 2011, studies were completed to update the estimated cost of decommissioning the Davis-Besse nuclear facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and reduced the liability for FES in the amount of $5 million.

The revisions to the estimated cash flows had no significant impact on accretion of the obligation during the three months and six months ended June 30, 2011 when compared to the same periods of 2010.

16. SUPPLEMENTAL GUARANTOR INFORMATION

In 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 six month periods ended June 30, 2011 and 2010, consolidating balance sheets as of June 30, 2011 and December 31, 2010 and consolidating statements of cash flows for the three months ended June 30, 2011 and 2010 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.

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	1,275		$	535		$	393		$	(911	)	$	1,292
EXPENSES:
Fuel		6			266			44			—			316
Purchased power from affiliates		902			9			65			(911	)		65
Purchased power from non-affiliates		332			(3	)		—			—			329
Other operating expenses		159			115			143			12			429
Provision for depreciation		1			32			36			(1	)		68
General taxes		16			8			6			—			30
Impairment of long-lived assets		—			7			—			—			7
Total expenses		1,416			434			294			(900	)		1,244
OPERATING INCOME (LOSS)		(141	)		101			99			(11	)		48
OTHER INCOME (EXPENSE):
Investment income		—			1			15			—			16
Miscellaneous income (expense), including net income from equity investees		123			1			—			(120	)		4
Interest expense — affiliates		—			(1	)		(1	)		—			(2	)
Interest expense — other		(24	)		(28	)		(16	)		16			(52	)
Capitalized interest		—			5			5			—			10
Total other income (expense)		99			(22	)		3			(104	)		(24	)
INCOME (LOSS) BEFORE INCOME TAXES		(42	)		79			102			(115	)		24
INCOME TAXES (BENEFITS)		(62	)		25			38			3			4
NET INCOME	$	20		$	54		$	64		$	(118	)	$	20

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	2,642		$	1,278		$	862		$	(2,098	)	$	2,684
EXPENSES:
Fuel		7			560			92			—			659
Purchased power from affiliates		2,087			11			134			(2,098	)		134
Purchased power from non-affiliates		629			(3	)		—			—			626
Other operating expenses		321			233			331			25			910
Provision for depreciation		2			63			74			(3	)		136
General taxes		27			19			14			—			60
Impairment charges of long-lived assets		—			20			—			—			20
Total expenses		3,073			903			645			(2,076	)		2,545
OPERATING INCOME (LOSS)		(431	)		375			217			(22	)		139
OTHER INCOME (EXPENSE):
Investment income		1			1			20			—			22
Miscellaneous income, including net income from equity investees		356			2			—			(350	)		8
Interest expense — affiliates		(1	)		(1	)		(1	)		—			(3	)
Interest expense — other		(48	)		(56	)		(33	)		32			(105	)
Capitalized interest		—			10			10			—			20
Total other income (expense)		308			(44	)		(4	)		(318	)		(58	)
INCOME (LOSS) BEFORE INCOME TAXES		(123	)		331			213			(340	)		81
INCOME TAXES (BENEFITS)		(179	)		119			80			5			25
NET INCOME	$	56		$	212		$	133		$	(345	)	$	56

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	1,307		$	581		$	339		$	(901	)	$	1,326
EXPENSES:
Fuel		7			302			34			—			343
Purchased power from affiliates		913			8			49			(901	)		69
Purchased power from non-affiliates		310			—			—			—			310
Other operating expenses		81			94			117			12			304
Provision for depreciation		1			27			36			(1	)		63
General taxes		6			9			7			—			22
Total expenses		1,318			440			243			(890	)		1,111
OPERATING INCOME (LOSS)		(11	)		141			96			(11	)		215
OTHER INCOME (EXPENSE):
Investment income		2			—			11			—			13
Miscellaneous income, including net income from equity investees		151			1			—			(148	)		4
Interest expense — affiliates		—			(2	)		—			—			(2	)
Interest expense — other		(24	)		(28	)		(15	)		16			(51	)
Capitalized interest		—			20			4			—			24
Total other income (expense)		129			(9	)		—			(132	)		(12	)
INCOME BEFORE INCOME TAXES		118			132			96			(143	)		203
INCOME TAXES (BENEFITS)		(16	)		48			34			3			69
NET INCOME	$	134		$	84		$	62		$	(146	)	$	134

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	2,674		$	1,149		$	765		$	(1,874	)	$	2,714
EXPENSES:
Fuel		12			582			77			—			671
Purchased power from affiliates		1,881			12			111			(1,874	)		130
Purchased power from non-affiliates		760			—			—			—			760
Other operating expenses		134			194			256			24			608
Provision for depreciation		2			54			73			(3	)		126
General taxes		11			24			14			—			49
Impairment of long-lived assets		—			2			—			—			2
Total expenses		2,800			868			531			(1,853	)		2,346
OPERATING INCOME (LOSS)		(126	)		281			234			(21	)		368
OTHER INCOME (EXPENSE):
Investment income		4			—			10			—			14
Miscellaneous income, including net income from equity investees		317			1			—			(311	)		7
Interest expense to affiliates		—			(4	)		(1	)		—			(5	)
Interest expense — other		(48	)		(54	)		(31	)		32			(101	)
Capitalized interest		—			36			8			—			44
Total other income (expense)		273			(21	)		(14	)		(279	)		(41	)
INCOME BEFORE INCOME TAXES		147			260			220			(300	)		327
INCOME TAXES (BENEFITS)		(67	)		97			78			5			113
NET INCOME	$	214		$	163		$	142		$	(305	)	$	214

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of June 30, 2011	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	6	$	—	$	—		$	6
Receivables-
Customers		450		—		—		—			450
Associated companies		481		425		263		(679	)		490
Other		24		23		4		—			51
Notes receivable from associated companies		6		410		74		—			490
Materials and supplies, at average cost		54		253		192		—			499
Derivatives		221		—		—		—			221
Prepayments and other		34		14		1		—			49
		1,270		1,131		534		(679	)		2,256
PROPERTY, PLANT AND EQUIPMENT:
In service		101		6,105		5,634		(385	)		11,455
Less — Accumulated provision for depreciation		19		2,067		2,298		(178	)		4,206
		82		4,038		3,336		(207	)		7,249
Construction work in progress		10		198		486		—			694
Property, plant and equipment held for sale, net		—		487		—		—			487
		92		4,723		3,822		(207	)		8,430
INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,184		—			1,184
Investment in associated companies		5,302		—		—		(5,302	)		—
Other		1		9		—		—			10
		5,303		9		1,184		(5,302	)		1,194
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		18		344		—		(362	)		—
Customer intangibles		129		—		—		—			129
Goodwill		24		—		—		—			24
Property taxes		—		16		25		—			41
Unamortized sale and leaseback costs		—		6		—		70			76
Derivatives		135		—		—		—			135
Other		39		97		7		(68	)		75
		345		463		32		(360	)		480
	$	7,010	$	6,326	$	5,572	$	(6,548	)	$	12,360
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	436	$	671	$	(20	)	$	1,088
Short-term borrowings-
Associated companies		453		88		—		—			541
Other		—		1		—		—			1
Accounts payable-
Associated companies		665		231		165		(668	)		393
Other		80		111		—		—			191
Derivatives		242		—		—		—			242
Other		69		137		46		10			262
		1,510		1,004		882		(678	)		2,718
CAPITALIZATION:
Total equity		3,858		2,728		2,556		(5,285	)		3,857
Long-term debt and other long-term obligations		1,483		2,050		706		(1,239	)		3,000
		5,341		4,778		3,262		(6,524	)		6,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		942			942
Accumulated deferred income taxes		—		—		504		(288	)		216
Asset retirement obligations		—		28		847		—			875
Retirement benefits		50		245		—		—			295
Lease market valuation liability		—		194		—		—			194
Derivatives		85		—		—		—			85
Other		24		77		77		—			178
		159		544		1,428		654			2,785
	$	7,010	$	6,326	$	5,572	$	(6,548	)	$	12,360

80

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of December 31, 2010	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	9	$	—	$	—		$	9
Receivables-
Customers		366		—		—		—			366
Associated companies		333		357		126		(338	)		478
Other		21		56		13		—			90
Notes receivable from associated companies		34		189		174		—			397
Materials and supplies, at average cost		41		276		228		—			545
Derivatives		182		—		—		—			182
Prepayments and other		48		10		1		—			59
		1,025		897		542		(338	)		2,126
PROPERTY, PLANT AND EQUIPMENT:
In service		96		6,198		5,412		(385	)		11,321
Less — Accumulated provision for depreciation		17		2,020		2,162		(175	)		4,024
		79		4,178		3,250		(210	)		7,297
Construction work in progress		9		520		534		—			1,063
		88		4,698		3,784		(210	)		8,360
INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,146		—			1,146
Investment in associated companies		4,942		—		—		(4,942	)		—
Other		—		12		—		—			12
		4,942		12		1,146		(4,942	)		1,158
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		43		412		—		(455	)		—
Customer intangibles		134		—		—		—			134
Goodwill		24		—		—		—			24
Property taxes		—		16		25		—			41
Unamortized sale and leaseback costs		—		10		—		63			73
Derivatives		98		—		—		—			98
Other		21		71		14		(58	)		48
		320		509		39		(450	)		418
	$	6,375	$	6,116	$	5,511	$	(5,940	)	$	12,062
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	101	$	419	$	632	$	(20	)	$	1,132
Short-term borrowings-
Associated companies		—		12		—		—			12
Accounts payable-
Associated companies		351		213		250		(347	)		467
Other		139		102		—		—			241
Derivatives		266		—		—		—			266
Other		56		183		46		37			322
		913		929		928		(330	)		2,440
CAPITALIZATION:
Common stockholder’s equity		3,788		2,515		2,414		(4,929	)		3,788
Long-term debt and other long-term obligations		1,519		2,119		793		(1,250	)		3,181
		5,307		4,634		3,207		(6,179	)		6,969
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		959			959
Accumulated deferred income taxes		—		—		448		(390	)		58
Asset retirement obligations		—		27		865		—			892
Retirement benefits		48		237		—		—			285
Lease market valuation liability		—		217		—		—			217
Derivatives		81		—		—		—			81
Other		26		72		63		—			161
		155		553		1,376		569			2,653
	$	6,375	$	6,116	$	5,511	$	(5,940	)	$	12,062

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(329	)	$	321		$	200		$	(10	)	$	182
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			140			107			—			247
Short-term borrowings, net		453			77			—			—			530
Redemptions and Repayments-
Long-term debt		(135	)		(192	)		(155	)		10			(472	)
Other		(9	)		(1	)		(1	)		—			(11	)
Net cash provided from (used for) financing activities		309			24			(49	)		10			294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(6	)		(109	)		(219	)		—			(334	)
Sales of investment securities held in trusts		—			—			513			—			513
Purchases of investment securities held in trusts		—			—			(545	)		—			(545	)
Loans to associated companies, net		28			(221	)		100			—			(93	)
Customer acquisition costs		(2	)		—			—			—			(2	)
Other		—			(18	)		—			—			(18	)
Net cash provided from (used for) investing activities		20			(348	)		(151	)		—			(479	)
Net change in cash and cash equivalents		—			(3	)		—			—			(3	)
Cash and cash equivalents at beginning of period		—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	6		$	—		$	—		$	6

82

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(223	)	$	163		$	287		$	(9	)	$	218
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		—			76			—			—			76
Redemptions and Repayments-
Long-term debt		—			(261	)		(43	)		9			(295	)
Other		(1	)		—			—			—			(1	)
Net cash used for financing activities		(1	)		(185	)		(43	)		9			(220	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(4	)		(333	)		(229	)		—			(566	)
Proceeds from asset sales		—			116			—			—			116
Sales of investment securities held in trusts		—			—			957			—			957
Purchases of investment securities held in trusts		—			—			(979	)		—			(979	)
Loans to associated companies, net		332			241			58			—			631
Customer acquisition costs		(105	)		—			—			—			(105	)
Leasehold improvement payments to associated companies		—			—			(51	)		—			(51	)
Other		1			(2	)		—			—			(1	)
Net cash provided from (used for) investing activities		224			22			(244	)		—			2
Net change in cash and cash equivalents		—			—			—			—			—
Cash and cash equivalents at beginning of period		—			—			—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—		$	—		$	—

83

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

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS

EXECUTIVE SUMMARY

Earnings available to FirstEnergy Corp. were $181 million, or basic and diluted earnings of $0.43 per share of common stock, compared with $265 million, or basic and diluted earnings of $0.87 per share of common stock in the second quarter of 2010. Earnings available to FirstEnergy Corp. in the first six months of 2011 were $231 million or basic and diluted earnings of $0.61 per share of common stock, compared with $420 million or basic earnings of $1.38 ($1.37 diluted) per share of common stock in the first six months of 2010. The principal reasons for the decreases are summarized below.

	Three Months			Six Months
Change In Basic Earnings Per Share From Prior Year(1)	Ended June 30			Ended June 30
Basic Earnings Per Share - 2010	$	0.87		$	1.38
Non-core asset sales/impairments		(0.01	)		(0.04	)
Trust securities impairments		0.01			0.02
Mark-to-market adjustments		(0.10	)		(0.02	)
Income tax charge from healthcare legislation - 2010		—			0.04
Regulatory charges - 2011		(0.01	)		(0.05	)
Regulatory charges - 2010		—			0.08
Litigation resolution		(0.06	)		(0.07	)
Merger related costs		(0.02	)		(0.31	)
Segment operating results - (2)
Regulated Distribution		0.02			—
Competitive Energy Services		(0.15	)		(0.24	)
Interest expense, net of amounts capitalized		(0.04	)		(0.08	)
Merger accounting — commodity contracts		(0.08	)		(0.12	)
Net merger accretion(3)		0.02			0.06
Settlement of uncertain tax positions		(0.03	)		(0.05	)
Other expenses		0.01			0.01
Basic Earnings Per Share - 2011	$	0.43		$	0.61

(1)	Amounts shown are net of income tax effect
(2)	Excludes amounts that are shown separately
(3)	Excludes merger accounting — commodity contracts, regulatory charges, mark-to-market adjustments and merger-related costs that are shown separately

Merger

On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger between FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub) and AE, Merger Sub merged with and into AE with AE continuing as the surviving corporation and a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each AE share outstanding as of the merger completion date and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.

In connection with the merger, FirstEnergy recorded approximately $7 million of merger transaction costs during each of the second quarter of 2011 and 2010, and approximately $89 million and $21 million of merger transaction costs during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. FirstEnergy’s consolidated financial statements include Allegheny’s results of operations and financial position effective February 25, 2011. In addition, during the three months ended June 30, 2011, $10 million of merger integration costs and $8 million of charges from merger settlements approved by regulatory agencies were recognized. In the first six months of 2011, $85 million of merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.

FirstEnergy expects to achieve the 2011 merger benefits target resulting from the merger with Allegheny. Through June 2011, FirstEnergy has taken actions and completed savings initiatives that will allow the company to capture merger benefits of approximately $132 million pre-tax on an annual basis, or 63% of the $210 million annual target. The $132 million realized from savings initiatives completed through June, along with the impact of initiatives still underway, will be reflected in earnings throughout 2011.

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Operational Matters

TrAIL

On May 19, 2011, TrAIL’s 500-kV transmission line, spanning more than 150 miles from southwestern Pennsylvania through West Virginia to northern Virginia, was completed and energized.

ATSI Integrated into PJM

On June 1, 2011, ATSI successfully integrated into PJM. With this transition, all of FirstEnergy’s generation, transmission and distribution facilities are now in PJM.

Perry Refueling

On June 7, 2011, the Perry Plant returned to service following a scheduled shutdown for refueling and maintenance which began on April 18, 2011. During the outage, 248 of the 748 fuel assemblies were replaced and safety inspections were successfully conducted. Additionally, numerous preventative maintenance activities and improvement projects were completed that we believe will result in continued safe and reliable operations, including replacement of several control rod blades, rewind of the generator, and routine work on more than 150 valves, pumps and motors.

New Nuclear Emergency Operations Facilities

In June 2011, FENOC broke ground for new Emergency Operations Facilities for the Beaver Valley Power Station and Perry Nuclear Power Plant. Each of the 12,000 square-foot facilities will house activities related to maintaining public health and safety during the unlikely event of an emergency at the plant and allow for improved coordination between the plant, state and local emergency management agencies. FENOC is expected to break ground for a similar facility for the Davis-Besse Nuclear Power Station in August 2011.

Fremont Energy Center

On July 28, 2011, FirstEnergy closed on the previously announced sale of Fremont Energy Center to American Municipal Power, Inc. for $510 million based on 685 MW of output. The purchase price can be incrementally increased, not to exceed an additional $16 million, to reflect additional transmission export capacity up to 707 MW.

Financial Matters

On April 29, 2011, Met-Ed redeemed $13.69 million of pollution control revenue bonds at par value.

On May 4, 2011, AE terminated its $250 million credit facility due to other available funding sources following completion of the merger with FirstEnergy.

On May 31, 2011, JCP&L and Met-Ed repurchased $500 million and $150 million, respectively, of their equity from FirstEnergy to maintain an appropriate capital structure.

On June 1, 2011, FGCO repurchased $40 million of pollution control revenue bonds and is holding those bonds for future remarketing or refinancing.

On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two 5-year revolving credit facilities with a total borrowing capacity of $4.5 billion. These facilities consist of a $2 billion revolving credit facility for FirstEnergy and its regulated entities and a $2.5 billion revolving credit facility for FES and AE Supply. Prior separate facilities ($2.75 billion at FirstEnergy, $1 billion at AE Supply, $110 million at MP, $150 million at PE and $200 million at WP) were terminated.

On July 29, 2011, FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and $98.9 million aggregate principal amount of FMBs previously delivered to certain of the LOC providers by FGCO and NGC, respectively, will be cancelled in connection with the mandatory purchases.

Regulatory Matters

NYSEG Ruling

On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites in New York. As a result, FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.

85

Marginal transmission loss recovery

On March 3, 2010, the PPUC issued an order denying Met-Ed and Penelec the ability to recover marginal transmission losses through the transmission service charge riders in their respective tariffs which applies to the periods including June 1, 2008 through December 31, 2010. Subsequently, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania (Commonwealth Court) appealing the PPUC’s order. On June 14, 2011, the Commonwealth Court affirmed the PPUC’s decision that marginal transmission losses are not recoverable as transmission costs. On July 13, 2011, Met-Ed and Penelec filed a federal complaint with the United States District Court for the Eastern District of Pennsylvania and on the following day, filed a Petition for Allowance of Appeal to the Pennsylvania Supreme Court. Met-Ed and Penelec believe the Commonwealth Court’s decision contradicts federal law and is inconsistent with prior PPUC and court decisions and therefore expect to fully recover the related regulatory assets ($189 million for Met-Ed and $65 million for Penelec). In January 2011 and continuing for 29 months, pursuant to a related PPUC order, Met-Ed and Penelec began crediting customers for the amounts at issue pending outcome of the court appeals.

FIRSTENERGY’S BUSINESS

With the completion of the Allegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment included FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other” segment consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.

The changes in FirstEnergy’s reportable segments during the first quarter of 2011 consisted primarily of the following:

• Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.

• A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.

• AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.

Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.

The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

86

The Regulated Independent Transmission segment transmits electricity through transmission lines. Its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.

The Competitive Energy Services segment, through FES, supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.

This business segment controls approximately 20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.

The Other and Reconciling Adjustments segment contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment as well as reconciling adjustments for the elimination of intersegment transactions.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. Results from the pre-merged companies have been segregated from the Allegheny companies for variance reporting and analysis. A reconciliation of segment financial results is provided in Note 13 to the consolidated financial statements. Earnings available to FirstEnergy by business segment were as follows:

	Three Months Ended								Six Months Ended
	June 30								June 30
						Increase									Increase
	2011			2010		(Decrease)			2011			2010			(Decrease)
	(In millions, except per share data)
Earnings (Loss) By Business Segment:
Regulated Distribution	$	184		$	132	$	52		$	280		$	235		$	45
Competitive Energy Services		12			121		(109	)		17			190			(173	)
Regulated Independent Transmission		31			11		20			44			23			21
Other and reconciling adjustments*		(46	)		1		(47	)		(110	)		(28	)		(82	)
Earnings available to FirstEnergy Corp.	$	181		$	265	$	(84	)	$	231		$	420		$	(189	)
Basic Earnings Per Share	$	0.43		$	0.87	$	(0.44	)	$	0.61		$	1.38		$	(0.77	)
Diluted Earnings Per Share	$	0.43		$	0.87	$	(0.44	)	$	0.61		$	1.37		$	(0.76	)

* Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

87

Summary of Results of Operations — Second Quarter 2011 Compared with Second Quarter 2010

Financial results for FirstEnergy’s business segments in the second quarter of 2011 and 2010 were as follows:

				Competitive			Regulated			Other and
	Regulated			Energy			Independent			Reconciling			FirstEnergy
Second Quarter 2011 Financial Results	Distribution			Services			Transmission			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,352		$	1,394		$	—		$	—		$	3,746
Other		133			101			105			(37	)		302
Internal		—			318			—			(306	)		12
Total Revenues		2,485			1,813			105			(343	)		4,060
Expenses:
Fuel		73			562			—			—			635
Purchased power		1,144			382			—			(306	)		1,220
Other operating expenses		438			640			19			8			1,105
Provision for depreciation		153			107			15			7			282
Amortization of regulatory assets		87			—			3			—			90
General taxes		180			51			8			3			242
Total Expenses		2,075			1,742			45			(288	)		3,574
Operating Income		410			71			60			(55	)		486
Other Income (Expense):
Investment income		27			15			—			(11	)		31
Interest expense		(148	)		(79	)		(12	)		(26	)		(265	)
Capitalized interest		3			12			1			4			20
Total Other Expense		(118	)		(52	)		(11	)		(33	)		(214	)
Income Before Income Taxes		292			19			49			(88	)		272
Income taxes		108			7			18			(32	)		101
Net Income (Loss)		184			12			31			(56	)		171
Loss attributable to noncontrolling interest		—			—			—			(10	)		(10	)
Earnings (loss) available to FirstEnergy Corp.	$	184		$	12		$	31		$	(46	)	$	181

88

				Competitive			Regulated			Other and
	Regulated			Energy			Independent			Reconciling			FirstEnergy
Second Quarter 2010 Financial Results	Distribution			Services			Transmission			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	2,243		$	739		$	—		$	—		$	2,982
Other		71			56			59			(29	)		157
Internal		19			539			—			(558	)		—
Total Revenues		2,333			1,334			59			(587	)		3,139
Expenses:
Fuel		—			350			—			—			350
Purchased power		1,291			330			—			(558	)		1,063
Other operating expenses		331			340			16			(14	)		673
Provision for depreciation		106			71			10			3			190
Amortization of regulatory assets		158			—			3			—			161
General taxes		138			27			7			4			176
Total Expenses		2,024			1,118			36			(565	)		2,613
Operating Income		309			216			23			(22	)		526
Other Income (Expense):
Investment income		28			13			—			(10	)		31
Interest expense		(125	)		(57	)		(6	)		(19	)		(207	)
Capitalized interest		1			24			1			14			40
Total Other Expense		(96	)		(20	)		(5	)		(15	)		(136	)
Income Before Income Taxes		213			196			18			(37	)		390
Income taxes		81			75			7			(29	)		134
Net Income (Loss)		132			121			11			(8	)		256
Loss attributable to noncontrolling interest		—			—			—			(9	)		(9	)
Earnings available to FirstEnergy Corp.	$	132		$	121		$	11		$	1		$	265

89

Changes Between Second Quarter 2011				Competitive			Regulated			Other and
and Second Quarter 2010 Financial	Regulated			Energy			Independent			Reconciling			FirstEnergy
Results Increase (Decrease)	Distribution			Services			Transmission			Adjustment			Consolidated
	(In millions)
Revenues:
External
Electric	$	109		$	655		$	—		$	—		$	764
Other		62			45			46			(8	)		145
Internal		(19	)		(221	)		—			252			12
Total Revenues		152			479			46			244			921
Expenses:
Fuel		73			212			—			—			285
Purchased power		(147	)		52			—			252			157
Other operating expenses		107			300			3			22			432
Provision for depreciation		47			36			5			4			92
Amortization of regulatory assets		(71	)		—			—			—			(71	)
General taxes		42			24			1			(1	)		66
Total Expenses		51			624			9			277			961
Operating Income		101			(145	)		37			(33	)		(40	)
Other Income (Expense):
Investment income		(1	)		2			—			(1	)		—
Interest expense		(23	)		(22	)		(6	)		(7	)		(58	)
Capitalized interest		2			(12	)		—			(10	)		(20	)
Total Other Expense		(22	)		(32	)		(6	)		(18	)		(78	)
Income Before Income Taxes		79			(177	)		31			(51	)		(118	)
Income taxes		27			(68	)		11			(3	)		(33	)
Net Income		52			(109	)		20			(48	)		(85	)
Loss attributable to noncontrolling interest		—			—			—			(1	)		(1	)
Earnings available to FirstEnergy Corp.	$	52		$	(109	)	$	20		$	(47	)	$	(84	)

Regulated Distribution — Second Quarter 2011 Compared with Second Quarter 2010

Net income increased by $52 million in the second quarter of 2011 compared to the second quarter of 2010 primarily due to earnings from the Allegheny companies and increased operating margins from the pre-merger companies as a result of reduced purchased power costs, partially offset by reduced revenues.

90

Revenues —

The increase in total revenues resulted from the following sources:

	Three Months
	Ended June 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Pre-merger companies:
Distribution services	$	810	$	851	$	(41	)
Generation sales:
Retail		747		1,097		(350	)
Wholesale		104		180		(76	)
Total generation sales		851		1,277		(426	)
Transmission		51		141		(90	)
Other		66		64		2
Total pre-merger companies		1,778		2,333		(555	)
Allegheny companies		707		—		707
Total Revenues	$	2,485	$	2,333	$	152

The decrease in distribution service revenues for the pre-merger companies reflects lower transition revenues due to the completion of transition cost recovery for CEI in December 2010, partially offset by increased rates associated with the recovery of deferred distribution costs. Distribution deliveries (excluding the Allegheny companies) decreased by 1.1% in the second quarter of 2011 from the second quarter of 2010. The change in distribution deliveries by customer class is summarized in the following table:

					Increase
Electric Distribution KWH Deliveries	2011		2010		(Decrease)
	(in thousands)
Pre-merger companies:
Residential		8,623		8,663		(0.5	)%
Commercial		7,926		8,121		(2.4	)%
Industrial		8,798		8,846		(0.5	)%
Other		126		132		(4.5	)%
Total pre-merger companies		25,473		25,762		(1.1	)%
Allegheny companies		9,527		—		—
Total Electric Distribution KWH Deliveries		35,000		25,762		35.9	%

Lower deliveries to residential and commercial customers reflected decreased weather-related usage in the second quarter of 2011 as cooling degree days decreased by 17.3% from the same period in 2010, and soft economic conditions affecting the commercial sector. In the industrial sector, KWH deliveries decreased by 4% to automotive customers, partially offset by increased deliveries to steel and electrical equipment customers of 11% and 15%, respectively.

The following table summarizes the price and volume factors contributing to the $426 million decrease in generation revenues for the pre-merger companies in the second quarter of 2011 compared to the second quarter of 2010:

	Increase
Source of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(447	)
Change in prices		96
		(351	)
Wholesale:
Effect of decrease in sales volumes		(8	)
Change in prices		(67	)
		(75	)
Net Decrease in Generation Revenues	$	(426	)

91

The decrease in retail generation sales volume was primarily due to increased customer shopping in service territories of the pre-merger companies in the second quarter of 2011, compared with the second quarter of 2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 77% from 61% for the Ohio companies and to 55% from 10% for Met-Ed’s and Penelec’s service areas.

The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market. Transmission revenues decreased $90 million due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.

The Allegheny companies added $707 million of revenues for the second quarter of 2011, including $155 million for distribution services, $486 million for generation sales and $66 million relating to transmission revenues.

Expenses —

Total expenses increased by $51 million due to the following:

• Purchased power costs, excluding the Allegheny companies, were $483 million lower in the second quarter of 2011 due primarily to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $336 million in purchased power costs in the second quarter of 2011.

	Increase
Source of Change in Purchased Power	(Decrease)
	(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs	$	(161	)
Change due to increased volumes		88
		(73	)
Purchases from FES:
Change due to increased unit costs		20
Change due to decreased volumes		(398	)
		(378	)
Increase in costs deferred		(32	)
Total pre-merger companies		(483	)
Purchases by Allegheny companies		336
Net Decrease in Purchased Power Costs	$	(147	)

• Transmission expenses decreased $29 million primarily due to lower PJM network transmission expenses and congestion costs of $70 million for Met-Ed and Penelec, partially offset by transmission expenses for the Allegheny companies of $41 million in the second quarter of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.

• Energy Efficiency program costs, which are also recovered through rates, increased by $43 million.

• The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010.

• Net amortization of regulatory assets decreased $71 million due primarily to reduced transition cost recovery and increased deferral of energy efficiency program costs.

• Fuel expenses for MP were $73 million in the second quarter of 2011.

• Operating expenses for the Allegheny companies were $95 million in the second quarter of 2011.

• Depreciation expense for the Allegheny companies was $48 million in the second quarter of 2011.

92

• Merger-related costs increased $4 million in the second quarter of 2011 compared to the same period of 2010.

• General taxes increased $42 million primarily due to property taxes and gross receipts taxes incurred by the Allegheny companies in the second quarter of 2011.

Other Expense —

Other expense increased $22 million in the second quarter of 2011 due to interest expense on debt of the Allegheny companies.

Regulated Independent Transmission — Second Quarter 2011 Compared with Second Quarter 2010

Net income increased by $20 million in the second quarter of 2011 compared to the second quarter of 2010 due to earnings associated with TrAIL and PATH ($22 million), partially offset by decreased earnings for ATSI ($1 million).

Revenues —

Revenues by transmission asset owner are shown in the following table:

	Three Months
Revenues by	Ended June 30				Increase
Transmission Asset Owner	2011		2010		(Decrease)
	(In millions)
ATSI	$	54	$	59	$	(5	)
TrAIL		46		—		46
PATH		5		—		5
Total Revenues	$	105	$	59	$	46

Expenses —

Total expenses increased by $9 million principally due to TrAIL and PATH operating expenses.

Other Expense —

Other expense increased $6 million in the second quarter of 2011 due to additional interest expense associated with TrAIL.

Competitive Energy Services — Second Quarter 2011 Compared with Second Quarter 2010

Net income decreased by $109 million in the second quarter of 2011, compared to the second quarter of 2010, primarily due to reduced sales margins, non-core asset impairments and the effect of mark-to-market adjustments.

Revenues —

Total revenues increased by $479 million in the second quarter of 2011 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR sales.

93

The increase in total revenues resulted from the following sources:

	Three Months
	Ended June 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	925	$	586	$	339
POLR and Structured Sales		231		615		(384	)
Wholesale		66		77		(11	)
Transmission		30		19		11
RECs		12		—		12
Other		38		37		1
Allegheny Companies		511		—		511
Total Revenues	$	1,813	$	1,334	$	479
Allegheny Companies
Direct and Governmental Aggregation	$	26
POLR and Structured Sales		185
Wholesale		267
Transmission		32
Other		1
Total Revenues	$	511

	Three Months
	Ended June 30				Increase
MWH Sales by Type of Service	2011		2010		(Decrease)
	(In thousands)
Direct		11,547		7,004		64.9	%
Governmental Aggregation		3,970		2,715		46.2	%
POLR and Structured Sales		3,718		11,600		(67.9	)%
Wholesale		395		1,108		(64.4	)%
Allegheny Companies		8,051		—		—
Total Sales		27,681		22,427		23.4	%
Allegheny Companies
Direct		425
POLR		2,169
Structured Sales		846
Wholesale		4,611
Total Sales		8,051

The increase in direct and governmental aggregation revenues of $339 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio, providing generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million at the end of June 2010. Partially offsetting the increase, were sales to residential and small commercial customers that were adversely affected by weather in the market served that was 17% cooler than in 2010.

The decrease in POLR revenues of $384 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for direct retail and aggregation sales.

Wholesale revenues decreased $11 million due to reduced generation available for sale in the wholesale market.

94

The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):

	Increase
Source of Change in Direct and Governmental Aggregation	(Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	267
Change in prices		(13	)
		254
Governmental Aggregation:
Effect of increase in sales volumes		80
Change in prices		5
		85
Net Increase in Direct and Governmental Aggregation Revenues	$	339

	Increase
Source of Change in POLR and Structured Revenues	(Decrease)
	(In millions)
POLR:
Effect of decrease in sales volumes	$	(418	)
Change in prices		34
		(384	)

	Increase
Source of Change in Wholesale Revenues	(Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes		(49	)
Change in prices		38
		(11	)

Transmission revenues increased by $11 million due primarily to higher PJM congestion revenue. The revenues derived from the sale of RECs increased $12 million in the second quarter of 2011.

Expenses —

Total expenses increased by $624 million in the second quarter of 2011 due to the following:

• Fuel costs decreased by $27 million primarily due to decreased volumes ($56 million), partially offset by higher unit prices ($29 million). Volumes decreased due to lower generation at the fossil units. Higher unit prices reflect increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.

• Purchased power costs were unchanged as higher unit costs ($70 million) were offset by lower volumes purchased ($70 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.

• Fossil operating costs increased by $18 million due primarily to higher labor, contractor and materials and equipment costs due to in increase in outages, both planned and unplanned, from the previous year.

• Nuclear operating costs increased by $33 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.

• Transmission expenses increased by $66 million due primarily to increases in PJM of $91 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $25 million due to lower network and line loss costs.

• General taxes increased by $10 million due to an increase in revenue-related taxes.

95

• Other expenses increased by $36 million primarily due to: a $14 million mark-to-market adjustment; a $7 million impairment charge related to non-core assets; and an $8 million increase in intercompany billings. The intercompany billings increased due to merger related costs and increased intersegment billings for leasehold costs from the Ohio Companies.

The inclusion of the Allegheny companies’ operations contributed $488 million to expenses, including a $9 million mark-to-market adjustment relating primarily to power contracts.

Other Expense —

Total other expense in the second quarter of 2011 was $32 million higher than the second quarter of 2010, primarily due to a $34 million increase in net interest expense partially offset by an increase in investment income ($2 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($22 million) and lower capitalized interest ($12 million) associated with the completion of the Sammis AQC project in 2010.

	Increase
Source of Expense Changes	(Decrease)
	(In millions)
Allegheny Companies
Fuel	$	238
Purchased power		53
Fossil		55
Transmission		75
Mark-to-Market		9
General taxes		11
Other		15
Depreciation		32
Total Expense	$	488

Other — Second Quarter of 2011 Compared with Second Quarter of 2010

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 $47 million decrease in earnings available to FirstEnergy in the second quarter of 2011 compared to the same period in 2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($29 million), decreased capitalized interest ($10 million) resulting from completed construction projects and increased interest expense due to the 2010 termination of interest rate swap agreements ($7 million).

96

Summary of Results of Operations — First Six Months of 2011 Compared with the First Six Months of 2010

Financial results for FirstEnergy’s business segments in the first six months of 2011 and 2010 were as follows:

				Competitive			Regulated			Other and
	Regulated			Energy			Independent			Reconciling			FirstEnergy
First Six Months 2011 Financial Results	Distribution			Services			Transmission			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	4,527		$	2,556		$	—		$	—		$	7,083
Other		226			180			172			(69	)		509
Internal		—			661			—			(617	)		44
Total Revenues		4,753			3,397			172			(686	)		7,636
Expenses:
Fuel		97			991			—			—			1,088
Purchased power		2,323			700			—			(617	)		2,406
Other operating expenses		824			1,288			36			(10	)		2,138
Provision for depreciation		269			195			25			13			502
Amortization of regulatory assets		216			—			6			—			222
General taxes		356			95			16			12			479
Total Expenses		4,085			3,269			83			(602	)		6,835
Operating Income		668			128			89			(84	)		801
Other Income (Expense):
Investment income		52			21			—			(21	)		52
Interest expense		(280	)		(144	)		(21	)		(51	)		(496	)
Capitalized interest		4			22			1			11			38
Total Other Expense		(224	)		(101	)		(20	)		(61	)		(406	)
Income Before Income Taxes		444			27			69			(145	)		395
Income taxes		164			10			25			(20	)		179
Net Income (Loss)		280			17			44			(125	)		216
Loss attributable to noncontrolling interest		—			—			—			(15	)		(15	)
Earnings available to FirstEnergy Corp.	$	280		$	17		$	44		$	(110	)	$	231

				Competitive			Regulated			Other and
	Regulated			Energy			Independent			Reconciling			FirstEnergy
First Six Months 2010 Financial Results	Distribution			Services			Transmission			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	4,641		$	1,408		$	—		$	—		$	6,049
Other		157			106			116			(57	)		322
Internal		19			1,213			—			(1,165	)		67
Total Revenues		4,817			2,727			116			(1,222	)		6,438
Expenses:
Fuel		—			684			—			—			684
Purchased power		2,686			780			—			(1,165	)		2,301
Other operating expenses		690			692			30			(38	)		1,374
Provision for depreciation		210			148			19			6			383
Amortization of regulatory assets		367			—			6			—			373
General taxes		292			64			14			11			381
Total Expenses		4,245			2,368			69			(1,186	)		5,496
Operating Income		572			359			47			(36	)		942
Other Income (Expense):
Investment income		54			14			—			(21	)		47
Interest expense		(250	)		(113	)		(11	)		(46	)		(420	)
Capitalized interest		2			47			1			31			81
Total Other Expense		(194	)		(52	)		(10	)		(36	)		(292	)
Income Before Income Taxes		378			307			37			(72	)		650
Income taxes		143			117			14			(29	)		245
Net Income (Loss)		235			190			23			(43	)		405
Loss attributable to noncontrolling interest		—			—			—			(15	)		(15	)
Earnings available to FirstEnergy Corp.	$	235		$	190		$	23		$	(28	)	$	420

97

Changes Between First Six Months 2011 and				Competitive			Regulated			Other and
First Six Months 2010 Financial Results	Regulated			Energy			Independent			Reconciling			FirstEnergy
Increase (Decrease)	Distribution			Services			Transmission			Adjustments			Consolidated
	(In millions)
Revenues:
External
Electric	$	(114	)	$	1,148		$	—		$	—		$	1,034
Other		69			74			56			(12	)		187
Internal		(19	)		(552	)		—			548			(23	)
Total Revenues		(64	)		670			56			536			1,198
Expenses:
Fuel		97			307			—			—			404
Purchased power		(363	)		(80	)		—			548			105
Other operating expenses		134			596			6			28			764
Provision for depreciation		59			47			6			7			119
Amortization of regulatory assets		(151	)		—			—			—			(151	)
General taxes		64			31			2			1			98
Total Expenses		(160	)		901			14			584			1,339
Operating Income		96			(231	)		42			(48	)		(141	)
Other Income (Expense):
Investment income		(2	)		7			—			—			5
Interest expense		(30	)		(31	)		(10	)		(5	)		(76	)
Capitalized interest		2			(25	)		—			(20	)		(43	)
Total Other Expense		(30	)		(49	)		(10	)		(25	)		(114	)
Income Before Income Taxes		66			(280	)		32			(73	)		(255	)
Income taxes		21			(107	)		11			9			(66	)
Net Income		45			(173	)		21			(82	)		(189	)
Loss attributable to noncontrolling interest		—			—			—			—			—
Earnings available to FirstEnergy Corp.	$	45		$	(173	)	$	21		$	(82	)	$	(189	)

Regulated Distribution — First Six Months of 2011 Compared to First Six Months of 2010

Net income increased by $45 million in the first six months of 2011, compared to the first six months of 2010, primarily due to the absence of a $35 million regulatory asset impairment recorded in 2010 and the earnings contribution of the Allegheny companies, partially offset by a favorable property tax settlement recognized in 2010.

Revenues —

The decrease in total revenues resulted from the following sources:

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Pre-merger companies:
Distribution services	$	1,719	$	1,733	$	(14	)
Generation sales:
Retail		1,620		2,272		(652	)
Wholesale		220		397		(177	)
Total generation sales		1,840		2,669		(829	)
Transmission		88		299		(211	)
Other		123		116		7
Total pre-merger companies		3,770		4,817		(1,047	)
Allegheny companies		983		—		983
Total Revenues	$	4,753	$	4,817	$	(64	)

98

The decrease in distribution service revenues for the pre-merger companies primarily reflects lower transition revenues due to the completion of transition cost recovery for CEI in December 2010, partially offset by increased rates associated with the recovery of deferred distribution costs. Distribution deliveries (excluding the Allegheny companies) increased approximately 360,000 KWH (0.7%), primarily driven by an increase of 443,000 KWH (2.6%) in the industrial class. Distribution deliveries by customer class are summarized in the following table:

					Increase
Electric Distribution KWH Deliveries	2011		2010		(Decrease)
	(in thousands)
Pre-merger companies:
Residential		19,261		19,119		0.7	%
Commercial		15,855		16,074		(1.4	)%
Industrial		17,640		17,197		2.6	%
Other		256		262		(2.3	)%
Total pre-merger companies		53,012		52,652		0.7	%
Allegheny companies		13,068		—		—
Total Electric Distribution KWH Deliveries		66,080		52,652		25.5	%

Lower distribution deliveries to commercial customers reflected soft economic conditions in this sector and decreased weather-related usage in the first six months of 2011 as cooling degree days were 17% below the same period in 2010. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in the Utilities’ service territory compared to the first six months of 2010. Industrial deliveries increased by 12% to steel customers, 16% to electrical equipment and component manufacturing customers and 10% to non-metallic mineral customers, partially offset by 2% lower sales to automotive customers.

The following table summarizes the price and volume factors contributing to the $829 million decrease in generation revenues in the first six months of 2011 compared to the same period of 2010:

	Increase
Source of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(826	)
Change in prices		174
		(652	)
Wholesale:
Effect of decrease in sales volumes		(2	)
Change in prices		(175	)
		(177	)
Net Decrease in Generation Revenues	$	(829	)

The decrease in retail generation sales volume was due to increased customer shopping in the Ohio Companies’, Met-Ed’s and Penelec’s service territories in the first six months of 2011 compared to the same period in 2010. Total generation provided by alternative suppliers as a percentage of total KWH deliveries increased to 75% from 57% for the Ohio companies and to 48% from 9% for Met-Ed’s and Penelec’s service areas. The decrease in wholesale generation revenues reflected lower RPM revenues for Met-Ed and Penelec in the PJM market.

Transmission revenues decreased $211 million due to the termination of Met-Ed’s and Penelec’s TSC rates effective January 1, 2011. Transmission costs are now a component of the cost of generation established under Met-Ed’s and Penelec’s generation procurement plan.

The Allegheny companies added $983 million of revenues for the first six months of 2011, including $216 million for distribution services, $676 million from generation sales and $91 million relating to transmission revenues.

99

Expenses —

Total expenses decreased by $160 million due to the following:

• Purchased power costs, excluding the Allegheny companies, were $843 million lower in the first six months of 2011 due to a decrease in volumes required. The decrease in power purchased from FES reflected the increase in customer shopping described above and the termination of Met-Ed’s and Penelec’s partial requirements PSA with FES at the end of 2010. The increase in volumes purchased from non-affiliates under Met-Ed’s and Penelec’s generation procurement plan effective January 1, 2011 was offset by a decrease in RPM expenses in the PJM market. The Allegheny companies added $481 million in purchased power costs in the first six months of 2011.

	Increase
Source of Change in Purchased Power	(Decrease)
	(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs	$	(356	)
Change due to increased volumes		277
		(79	)
Purchases from FES:
Change due to increased unit costs		63
Change due to decreased volumes		(809	)
		(746	)
Increase in costs deferred		(18	)
Total pre-merger companies		(843	)
Purchases by Allegheny companies		481
Net Decrease in Purchased Power Costs	$	(362	)

• Transmission expenses decreased $124 million primarily due to lower PJM network transmission expenses and congestion costs of $177 million for Met-Ed and Penelec, partially offset by transmission expenses for the Allegheny companies of $53 million in the first six months of 2011. Met-Ed and Penelec defer or amortize the difference between revenues from their transmission rider and transmission costs incurred with no material effect on earnings.

• Energy efficiency program costs, which are also recovered through rates, increased $62 million.

• The absence of a $7 million favorable JCP&L labor settlement that occurred in the second quarter of 2010.

• A provision for excess and obsolete material of $13 million was recognized in the first six months of 2011 due to revised inventory practices adopted in conjunction with the Allegheny merger.

• Net amortization of regulatory assets decreased $150 million primarily due to reduced net PJM transmission cost and transition cost recovery and the absence of a $35 million regulatory asset impairment recognized in 2010 associated with the filing of the Ohio ESP on March 23, 2010, partially offset by increased energy efficiency cost recovery.

• Fuel expenses for MP were $97 million in the first six months of 2011.

• Operating expenses for the Allegheny companies were $131 million in the first six months of 2011.

• Merger-related costs increased $46 million in the first six months of 2011 compared to the same period of 2010.

• Depreciation expense for the Allegheny companies was $64 million.

• General taxes increased by $64 million primarily due to taxes incurred by the Allegheny companies and the absence of a favorable property tax settlement recognized in 2010.

Other Expense —

Other expense increased by $30 million in the first six months of 2011 due to interest expense on debt of the Allegheny companies.

Regulated Independent Transmission — First Six Months 2011 Compared with First Six Months 2010

Net income increased by $21 million in the first six months of 2011 compared to the first six months of 2010 due to earnings associated with TrAIL and PATH ($27 million), partially offset by decreased earnings for ATSI ($6 million).

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Revenues —

Revenues by transmission asset owner are shown in the following table:

	Six Months
Revenues by	Ended June 30				Increase
Transmission Asset Owner	2011		2010		(Decrease)
	(In millions)
ATSI	$	106	$	116	$	(10	)
TrAIL		61		—		61
PATH		5		—		5
Total Revenues	$	172	$	116	$	56

Expenses —

Total expenses increased by $14 million principally due to TrAIL and PATH operating expenses.

Other Expense —

Other expense increased $10 million in the first six months of 2011 due to interest expense associated with TrAIL.

Competitive Energy Services — First Six Months of 2011 Compared to First Six Months of 2010

Net income decreased by $173 million in the first six months of 2011, compared to the first six months of 2010, primarily due to lower sales margin, an inventory reserve adjustment, non-core asset impairments and the effect of mark-to-market adjustments.

Revenues —

Total revenues increased $670 million in the first six months of 2011 primarily due to growth in direct and governmental aggregation sales and the inclusion of the Allegheny companies, partially offset by a decline in POLR sales.

The increase in total revenues resulted from the following sources:

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	1,765	$	1,097	$	668
POLR and Structured Sales		607		1,315		(708	)
Wholesale		156		142		14
Transmission		56		36		20
RECs		44		67		(23	)
Other		79		70		9
Allegheny Companies		690		—		690
Total Revenues	$	3,397	$	2,727	$	670
Allegheny Companies
Direct and Governmental Aggregation	$	34
POLR and Structured Sales		254
Wholesale		357
Transmission		44
Other		1
Total Revenues	$	690

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	Six Months
	Ended June 30				Increase
MWH Sales by Type of Service	2011		2010		(Decrease)
	(In thousands)
Direct		21,219		12,857		65.0	%
Governmental Aggregation		8,279		5,447		52.0	%
POLR and Structured Sales		9,561		25,344		(62.3	)%
Wholesale		1,380		1,538		(10.3	)%
Allegheny Companies		10,687		—		—
Total Sales		51,126		45,186		13.1	%
Allegheny Companies
Direct		570
POLR		2,981
Structured Sales		1,149
Wholesale		5,987
Total Sales		10,687

The increase in direct and governmental aggregation revenues of $668 million resulted from increased revenue from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio that provided generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million customers at the end of June 2010.

The decrease in POLR revenues of $708 million was due to lower sales volumes to Met-Ed, Penelec and the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for our direct retail and aggregation sales.

Wholesale revenues increased by $14 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by units moved to PJM were partially offset by losses on financially settled sales.

The following tables summarize the price and volume factors contributing to changes in revenues (excluding the Allegheny companies):

	Increase
Source of Change in Direct and Governmental Aggregation	(Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	493
Change in prices		(20	)
		473
Governmental Aggregation:
Effect of increase in sales volumes		176
Change in prices		19
		195
Net Increase in Direct and Governmental Aggregation Revenues	$	668

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	Increase
Source of Change in POLR Revenues	(Decrease)
	(In millions)
POLR:
Effect of decrease in sales volumes	$	(819	)
Change in prices		111
		(708	)

	Increase
Source of Change in Wholesale Revenues	(Decrease)
Wholesale:
Effect of decrease in sales volumes		(15	)
Change in prices		29
		14

Transmission revenues increased by $20 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs declined $23 million in the first six months of 2011.

Expenses —

Total expenses increased by $901 million in the first six months of 2011 due to the following:

• Fuel costs decreased by $13 million primarily due to decreased volumes ($28 million), partially offset by higher unit prices ($15 million). Volumes decreased due to lower generation from the fossil units. Unit prices increased primarily due to increased coal transportation costs and higher nuclear fuel unit prices following the refueling outages that occurred in 2010.

• Purchased power costs decreased by $154 million due primarily to lower volumes purchased ($248 million) partially offset by higher unit costs ($94 million). The decrease in volume primarily relates to the absence in 2011 of a 1,300 MW third party contract associated with serving Met-Ed and Penelec.

• Fossil operating costs increased by $20 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.

• Nuclear operating costs increased by $48 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.

• Transmission expenses increased by $176 million due primarily to increases in PJM of $198 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $22 million.

• General taxes increased by $12 million due to an increase in revenue-related taxes.

• Other expenses increased by $93 million primarily due to: a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger; a $20 million impairment charge related to non-core assets; and a $9 million increase in intercompany billings. The intercompany billings increased due to merger related costs and increased intersegment billings for leasehold costs from the Ohio Companies.

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The inclusion of the Allegheny companies’ operations contributed $719 million to expenses, including a $43 million mark-to-market adjustment relating primarily to power contracts.

	Increase
Source of Expense Changes	(Decrease)
	(In millions)
Allegheny Companies
Fuel	$	320
Purchased power		74
Fossil		82
Transmission		99
Mark-to-Market		43
General taxes		15
Other		43
Depreciation		43
Total Expense	$	719

Other Expense —

Total other expense in the first six months of 2011 was $49 million higher than the first six months of 2010, primarily due to a $56 million increase in net interest expense, partially offset by an increase in nuclear decommissioning trust investment income ($7 million). The increase in interest expense was primarily due to the inclusion of the Allegheny companies ($30 million) and lower capitalized interest ($25 million) associated with the completion of the Sammis AQC project in 2010.

Other — First Six Months of 2011 Compared to First Six Months of 2010

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 an $82 million decrease in earnings available to FirstEnergy in the first six months of 2011 compared to the same period in 2010. The decrease resulted primarily from increased operating expenses resulting from adverse litigation resolution ($29 million), decreased capitalized interest and increased depreciation expense resulting from completed construction projects placed into service ($27 million), an asset impairment charge in the first quarter of 2011 ($12 million) and increased income taxes ($9 million).

Regulatory Assets

FirstEnergy and the Utilities prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent amounts that are expected to be credited to customers through future regulated rates or amounts collected from customers for costs not yet incurred. FirstEnergy and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides the balance of net regulatory assets by company as of June 30, 2011 and December 31, 2010 and changes during the six months then ended:

	June 30,		December 31,		Increase
Regulatory Assets	2011		2010		(Decrease)
	(In millions)
OE	$	393	$	400	$	(7	)
CEI		320		370		(50	)
TE		89		72		17
JCP&L		469		513		(44	)
Met-Ed		341		296		45
Penelec		222		163		59
Other*		348		12		336
Total	$	2,182	$	1,826	$	356

* 2011 includes $337 million related to the Allegheny companies.

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The following tables provide information about the composition of net regulatory assets as of June 30, 2011 and December 31, 2010 and the changes during the six months then ended:

										Amount of
										Increase
										(Decrease)
	June 30,			December 31,			Increase			Attributable
Regulatory Assets by Source	2011			2010			(Decrease)			to AE
	(In millions)
Regulatory transition costs	$	899		$	770		$	129		$	—
Customer receivables for future income taxes		502			326			176			160
Loss on reacquired debt		53			48			5			8
Employee postretirement benefits		11			16			(5	)		—
Nuclear decommissioning and spent fuel disposal costs		(201	)		(184	)		(17	)		—
Asset removal costs		(228	)		(237	)		9			22
MISO/PJM transmission costs		292			184			108			76
Deferred generation costs		454			386			68			15
Distribution costs		284			426			(142	)		—
Other		116			91			25			56
Total	$	2,182		$	1,826		$	356		$	337

FirstEnergy had $385 million of net regulatory liabilities as of June 30, 2011, including $376 million of net regulatory liabilities acquired as part of the merger with AE that are primarily related to customer receivables for future income taxes and asset removal costs.

Regulatory assets that do not earn a current return totaled approximately $345 million as of June 30, 2011, of which $138 million relates to purchase accounting fair value adjustments to corresponding liabilities that do not accrue interest.

Regulatory assets not earning a current return for Met-Ed and Penelec include certain regulatory transition costs and PJM transmission costs of approximately $144 million and $34 million, respectively. The regulatory transition costs are expected to be recovered by 2020.

Regulatory assets not earning a current return for JCP&L include certain storm damage costs and pension and postretirement benefits of approximately $34 million that are expected to be recovered by 2014.

Regulatory assets not earning a current return for FirstEnergy’s other utility subsidiaries include certain deferred generation and other costs of approximately $133 million that are expected to be recovered though 2026.

CAPITAL RESOURCES AND LIQUIDITY

As of June 30, 2011, FirstEnergy had $476 million of cash and cash equivalents available to fund investments, operations and capital expenditures. In addition to internal sources to fund liquidity and capital requirements for 2011 and beyond, FirstEnergy may rely on external sources of funds. Short-term cash requirements not met by cash provided from operations are generally satisfied through short-term borrowings. Long-term cash needs may be met through issuances of debt and/or equity securities.

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. FirstEnergy expects that borrowing capacity under credit facilities will continue to be available to manage working capital requirements along with continued access to long-term capital markets.

A material adverse change in operations, or in the availability of external financing sources, could impact FirstEnergy’s liquidity position and ability to fund its capital resource requirements. To mitigate risk, FirstEnergy’s business strategy stresses financial discipline and a strong focus on execution. Major elements include the expectation of: adequate cash from operations, opportunities for favorable long-term earnings growth in the competitive generation markets, operational excellence, business plan execution, well-positioned generation fleet, no speculative trading operations, appropriate long-term commodity hedging positions, manageable capital expenditure program, adequately funded pension plan, minimal near-term maturities of existing long-term debt, commitment to a secure dividend and a successful merger integration.

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As of June 30, 2011, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to the classification of certain variable interest rate PCRBs as currently payable long-term debt and short-term borrowings. Currently payable long-term debt as of June 30, 2011, included the following (in millions):

Currently Payable Long-term Debt
PCRBs supported by bank LOCs (1)	$	949
AE Supply unsecured note		503
FirstEnergy Corp. unsecured note		250
FGCO and NGC unsecured PCRBs (1)		136
WP unsecured note		80
NGC collateralized lease obligation bonds		59
Sinking fund requirements		50
Other notes		31
	$	2,058

⁽¹⁾ Interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.

Credit Facility Borrowings and Liquidity

FirstEnergy had approximately $656 million and $700 million of short-term borrowings as of June 30, 2011 and December 31, 2010, respectively. FirstEnergy’s available liquidity as of July 29, 2011, is summarized in the following table:

					Available
Company	Type	Maturity	Commitment		Liquidity
			(In millions)
FirstEnergy(1)	Revolving	June 2016	$	2,000	$	1,751
FES / AE Supply	Revolving	June 2016		2,500		2,449
TrAIL	Revolving	Jan. 2013		450		450
AGC	Revolving	Dec. 2013		50		—
		Subtotal	$	5,000	$	4,650
		Cash		—		586
		Total	$	5,000	$	5,236

⁽¹⁾ FirstEnergy Corp. and regulated subsidiary borrowers.

During March 2011, the accounts receivable financing arrangements for OE, TE, Penelec and Met-Ed were terminated in favor of other sources of liquidity that were deemed more economical. In May 2011, AE terminated its $250 million credit facility. AE now participates in the unregulated money pool (see FirstEnergy Money Pools below).

Revolving Credit Facilities

On June 17, 2011, FirstEnergy and certain of its subsidiaries entered into two new five-year syndicated revolving credit facilities with aggregate commitments of $4.5 billion (New Facilities).

An aggregate amount of $2 billion is available to be borrowed under a syndicated revolving credit facility (New FirstEnergy Facility), subject to separate borrowing sublimits for each borrower. The borrowers under the New FirstEnergy Facility are FirstEnergy, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec, PE and WP. An additional $2.5 billion is available to be borrowed by FES and AE Supply under a separate syndicated revolving credit facility (New FES/AESupply Facility).

The New Facilities replaced a FirstEnergy $2.75 billion revolving credit facility, an AE Supply $1 billion revolving credit facility, a MP $110 million revolving credit facility, a PE $150 million revolving credit facility and a WP $200 million revolving credit facility, all of which were terminated as of June 17, 2011. Initial borrowings under the New Facilities were used to pay off outstanding obligations under these prior revolving credit facilities.

Commitments under each of the New Facilities will be available until June 17, 2016, unless the lenders agree, at the request of the applicable borrowers, to up to two additional one-year extensions. Generally, borrowings under each of the New Facilities are available to each borrower separately and will mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended.

Borrowings under each of the New Facilities are subject to acceleration upon the occurrence of events of default that each borrower considers usual and customary, including a cross-default for other indebtedness in excess of $100 million. Defaults by either FES or AE Supply or their respective subsidiaries under the New FES/AESupply Facility or other indebtedness generally will not cross-default to FirstEnergy under the New FirstEnergy Facility.

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The following table summarizes the borrowing sub-limits for each borrower under the facilities, 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 June 30, 2011:

	New Revolving		Regulatory and
	Credit Facility		Other Short-Term
Borrower	Sub-Limit		Debt Limitations
	(In millions)
FirstEnergy	$	2,000		—	(a)
FES	$	1,500		—	(b)
AE Supply	$	1,000		—	(b)
OE	$	500	$	500
CEI	$	500	$	500
TE	$	500	$	500
JCP&L	$	425	$	411	(c)
Met-Ed	$	300	$	300	(c)
Penelec	$	300	$	300	(c)
West Penn	$	200	$	200	(c)
MP	$	150	$	150	(c)
PE	$	150	$	150	(c)
ATSI	$	100	$	100
Penn	$	50	$	33	(c)

(a)	No limitations.
(b)	No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.
(c)	Excluding amounts which may be borrowed under the regulated companies’ money pool.

The entire amount of the New FES/AE Supply Facility and $700 million of the New FirstEnergy Facility, subject to each borrower’s sub-limit, is available for 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 each of the New Facilities and against the applicable borrower’s borrowing sub-limit.

Each of the New Facilities 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 June 30, 2011, FirstEnergy’s and its subsidiaries’ debt to total capitalization ratios (as defined under each of the New Facilities) were as follows:

Borrower
FirstEnergy	56.9	%
FES	54.1	%
OE	56.2	%
Penn	34.4	%
CEI	56.3	%
TE	58.4	%
JCP&L	43.9	%
Met-Ed	53.5	%
Penelec	55.5	%
ATSI	54.9	%
MP	59.3	%
PE	60.1	%
WP	53.9	%
AE Supply	39.4	%

As of June 30, 2011, FirstEnergy could issue additional debt of approximately $7.8 billion, or recognize a reduction in equity of approximately $4.2 billion, and remain within the limitations of the financial covenants required by its credit facility.

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The New Facilities do not contain provisions that restrict the ability to borrow or accelerate payment 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 facilities are related to the credit ratings of the company borrowing the funds.

In addition to the New Facilities, FirstEnergy also has access to an additional $500 million of revolving credit facilities relating to the Allegheny companies (TrAIL — $450 million and AGC $50 million).

Under the terms of its credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. Outstanding debt for TrAIL may not exceed 70% and 65% of the sum of its debt and equity as of the last day of each calendar quarter through June 30, 2011 and December 31, 2012, respectively. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE.

FirstEnergy Money Pools

FirstEnergy’s regulated companies, excluding regulated companies acquired in the Allegheny merger, 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 six months of 2011 was 0.43% per annum for the regulated companies’ money pool and 0.46% per annum for the unregulated companies’ money pool. FirstEnergy and its regulated companies acquired in the Allegheny merger have filed with the appropriate regulatory commissions to receive approval to become part of the FirstEnergy regulated money pool.

Pollution Control Revenue Bonds

As of June 30, 2011, FirstEnergy’s currently payable long-term debt included approximately $949 million (FES — $875 million, Met-Ed — $29 million and Penelec — $45 million) of variable interest rate PCRBs, the bondholders of which are entitled to the benefit of irrevocable direct pay bank LOCs. The interest rates on the PCRBs are reset daily or weekly. Bondholders can tender their PCRBs for mandatory purchase prior to maturity with the purchase price payable from remarketing proceeds or, if the PCRBs are not successfully remarketed, by drawings on the irrevocable direct pay LOCs. The subsidiary obligor is required to reimburse the applicable LOC bank for any such drawings or, if the LOC bank fails to honor its LOC for any reason, must itself pay the purchase price.

The LOCs for FirstEnergy variable interest rate PCRBs were issued by the following banks as of June 30, 2011:

	Aggregate LOC			Reimbursements of
LOC Bank	Amount(1)		LOC Termination Date	LOC Draws Due
	(In millions)
UBS	$	272	April 2014	April 2014
The Bank of Nova Scotia		178	Beginning June 2012	Multiple dates(2)
CitiBank N.A.		165	June 2014	June 2014
Wachovia Bank		153	March 2014	March 2014
The Royal Bank of Scotland		131	June 2012	6 months
US Bank		60	April 2014	6 months
Total	$	959

(1)	Includes approximately $10 million of applicable interest coverage.
(2)	Shorter of 6 months or LOC termination date ($49 million) and shorter of one year or LOC termination date ($129 million).

On March 17, 2011, FES completed the remarketing of $207 million variable rate PCRBs. These PCRBs remained in a variable interest mode, supported by bank LOC’s. Also, on March 1, 2011, FES repurchased $50 million of non-LOC backed fixed rate PCRBs that were subject to purchase on demand by the owner on that date.

On April 1, 2011, FES completed the remarketing of an additional $97 million of non-LOC backed commercial paper rate and fixed rate PCRBs (including the $50 million repurchased on March 1) into variable rate modes with LOC support. Also on April 1, 2011, Penelec completed the remarketing of $25 million of non-LOC backed commercial paper rate PCRBs into a variable rate mode with LOC support.

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In connection with the remarketings, approximately $207 million aggregate principal amount of FMBs previously delivered to LOC providers were cancelled, and approximately $50 million aggregate principal amount of FMBs delivered to secure PCRBs were cancelled on May 31, 2011.

On April 29, Met-Ed redeemed $14 million of PCRBs at par value.

On June 1, 2011, FGCO repurchased $40 million of PCRBs and, subject to market conditions and other considerations, is holding those bonds for future remarketing or refinancing.

On July 29, 2011, FGCO and NGC provided notice to the trustee for $158.1 million and $158.9 million, respectively, of PCRBs of their election to terminate applicable supporting LOCs. As a result, these PCRBs are subject to mandatory purchase on September 1, 2011. Subject to market conditions and other considerations, FGCO and NGC currently expect to hold the bonds for future remarketing or refinancing. Also, approximately $28.5 million and $98.9 million aggregate principal amount of FMBs previously delivered to certain of the LOC providers by FGCO and NGC, respectively, will be cancelled in connection with the mandatory purchases.

Long-Term Debt Capacity

As of June 30, 2011, the Ohio Companies and Penn had the aggregate capability to issue approximately $2.5 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 $100 million and $19 million, respectively. As a result of its indenture provisions, TE cannot incur any additional secured debt. Met-Ed and Penelec had the capability to issue secured debt of approximately $363 million and $365 million, respectively, under provisions of their senior note indentures as of June 30, 2011. In addition, based upon their respective FMB indentures, net earnings and available bondable property additions as of June 30, 2011, MP, PE and WP had the capability to issue approximately $1.0 billion of additional FMBs in the aggregate.

Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as of June 30, 2011, FGCO had the capability to issue $2.5 billion of additional FMBs under the terms of that indenture. Due to the sale of Fremont Energy Center on July 28, 2011, FGCO’s capability to issue additional FMBs was reduced by $510 million. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as of June 30, 2011, NGC had the capability to issue $1.7 billion of additional FMBs as of June 30, 2011 under the terms of that indenture.

FirstEnergy’s access to capital markets and costs of financing are influenced by the ratings of its securities. On February 25, 2011, Moody’s affirmed the ratings and stable outlook of FirstEnergy and its regulated utilities, upgraded AE’s senior unsecured ratings to Baa3 from Ba1 and placed the ratings for FES under review for possible downgrade. On March 1, 2011, Fitch affirmed the ratings and outlook of FirstEnergy and its subsidiaries. The following table displays FirstEnergy’s and its subsidiaries’ securities ratings as of July 29, 2011.

	Senior Secured			Senior Unsecured
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FirstEnergy Corp.	—	—	—	BB+	Baa3	BBB
Allegheny	—	—	—	BB+	Baa3	—
FES	—	—	—	BBB-	Baa2	BBB
AE Supply	BBB	Baa2	BBB	BBB-	Baa3	BBB-
AGC	—	—	—	BBB-	Baa3	BBB+
ATSI	—	—	—	BBB-	Baa1	A-
CEI	BBB	Baa1	BBB	BBB-	Baa3	BBB-
JCP&L	—	—	—	BBB-	Baa2	BBB+
Met-Ed	BBB	A3	A-	BBB-	Baa2	BBB+
MP	BBB+	Baa1	A-	BBB-	Baa3	BBB+
OE	BBB	A3	BBB+	BBB-	Baa2	BBB
Penelec	BBB	A3	BBB+	BBB-	Baa2	BBB
Penn	BBB+	A3	BBB+	—	—	—
PE	BBB+	Baa1	A-	BBB-	Baa3	BBB+
TE	BBB	Baa1	BBB	—	—	—
TrAIL	—	—	—	BBB-	Baa2	A-
WP	BBB+	A3	A-	BBB-	Baa2	BBB+

Changes in Cash Position

As of June 30, 2011, FirstEnergy had $476 million of cash and cash equivalents compared to approximately $1 billion as of December 31, 2010. As of June 30, 2011 and December 31, 2010, FirstEnergy had approximately $78 million and $13 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheet.

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During the first six months of 2011, FirstEnergy received $1.4 billion from cash dividends and equity repurchases by its subsidiaries and paid $420 million in cash dividends to common shareholders, including $20 million paid in March by AE to its former shareholders.

Cash Flows From Operating Activities

FirstEnergy’s consolidated net cash from operating activities is provided primarily by its competitive energy services, energy delivery services and regulated independent transmission businesses (see Results of Operations above). Net cash provided from operating activities increased by $173 million during the first six months of 2011 compared to the same period in 2010, as summarized in the following table:

	Six Months
	Ended June 30						Increase
Operating Cash Flows	2011			2010			(Decrease)
	(In millions)
Net income	$	216		$	405		$	(189	)
Non-cash charges		1,229			789			440
Pension trust contribution		(262	)		—			(262	)
Working capital and other		(152	)		(336	)		184
	$	1,031		$	858		$	173

The increase in non-cash charges and other adjustments is primarily due to increased deferred taxes and investment tax credits driven by bonus depreciation and the 2011 pension contribution ($393 million) and increased depreciation from the acquired Allegheny Companies ($119 million), partially offset by lower amortization of regulatory assets from reduced net PJM transmission cost and transition cost recovery ($151 million).

The increase in cash flows from working capital and other is primarily due to decreased receivables from higher customer collections ($355 million) and decreased materials and supplies from the inventory valuation adjustment in the first quarter of 2011 ($41 million), partially offset by increased prepayments and other current assets driven by higher prepaid taxes ($187 million).

Cash Flows From Financing Activities

In the first six months of 2011, cash used for financing activities was $1,039 million compared to $484 million in the comparable period of 2010. The following table summarizes new debt financing (net of any discounts) and redemptions:

	Six Months
	Ended June 30
Debt Issuances and Redemptions	2011			2010
	(In millions)
New Issues
Pollution control notes	$	272		$	—
Long-term revolving credit		70			—
Unsecured Notes		161			—
	$	503		$	—
Redemptions
Pollution control notes	$	312		$	251
Long-term revolving credit		475			—
Senior secured notes		166			55
First mortgage bonds		14			—
Unsecured notes		35			100
	$	1,002		$	406
Short-term borrowings, net	$	(44	)	$	281

In 2011, FES paid off at maturity a $100 million term loan that was secured by FMBs. In April 2011, FirstEnergy entered into a $150 million unsecured term loan with an April 2013 maturity.

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In 2011 FES repurchased and retired $20 million of its 6.80% unsecured senior notes and $15 million of its 6.05% unsecured senior notes. In April 2011, Met-Ed redeemed approximately $14 million of FMBs securing PCRBs.

During the remainder of 2011 FirstEnergy and its subsidiaries expect to pursue, from time to time, continued reductions in outstanding long-term debt of up to approximately $1.0 to $1.5 billion through redemptions, open market or privately negotiated purchases. Any such transactions will be subject to prevailing market conditions, liquidity requirements, timing of asset sales and other factors.

Cash Flows From Investing Activities

Cash used for investing activities in the first six months of 2011 resulted from cash used for property additions, partially offset by the cash acquired in the Allegheny merger. The following table summarizes investing activities for the first six months of 2011 and the comparable period of 2010 by business segment:

Summary of Cash Flows	Property
Provided from (Used for) Investing Activities	Additions			Investments			Other			Total
	(In millions)
Sources (Uses)
Six Months Ended June 30, 2011
Regulated distribution	$	(479	)	$	(2	)	$	(25	)	$	(506	)
Competitive energy services		(411	)		(32	)		(335	)		(778	)
Regulated independent transmission		(72	)		(1	)		(1	)		(74	)
Cash received in Allegheny merger		—			590			—			590
Other and reconciling items		(56	)		(21	)		310			233
Total	$	(1,018	)	$	534		$	(51	)	$	(535	)
Six Months Ended June 30, 2010
Regulated distribution	$	(309	)	$	87		$	(18	)	$	(240	)
Competitive energy services		(619	)		(11	)		(1	)		(631	)
Regulated independent transmission		(29	)		—			(2	)		(31	)
Other and reconciling items		(40	)		(25	)		—			(65	)
Total	$	(997	)	$	51		$	(21	)	$	(967	)

Net cash used in investing activities during the first six months of 2011 decreased by $432 million compared to the same period of 2010. The decrease was principally due to cash acquired in the Allegheny merger ($590 million), partially offset by a decrease in net proceeds from asset sales and higher property additions ($137 million).

During the second half of 2011, capital requirements for property additions and capital leases are expected to be approximately $1.2 billion, including approximately $122 million for nuclear fuel.

GUARANTEES AND OTHER ASSURANCES

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

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As of June 30, 2011, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $3.8 billion, as summarized below:

	Maximum
Guarantees and Other Assurances	Exposure
	(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts(1)	$	223
OVEC obligations		300
Other(2)		301
		824
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts		155
FES’ guarantee of NGC’s nuclear property insurance		70
FES’ guarantee of FGCO’s sale and leaseback obligations		2,324
Other		19
		2,568
Surety Bonds		136
LOC(3)		269
		405
Total Guarantees and Other Assurances	$	3,797

(1)	Issued for open-ended terms, with a 10-day termination right by FirstEnergy.
(2)	Includes guarantees of $95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $35 million for railcar leases.
(3)	Includes $105 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $122 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $39 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 other 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, an acceleration or funding obligation 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 June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $625 million, as shown below:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade (1)	$	440	$	4	$	78	$	522
Material adverse event (2)		33		57		13		103
Total	$	473	$	61	$	91	$	625

(1)	Includes $206 million and $59 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.
(2)	Includes $32 million that is also considered an acceleration of payment or funding obligation for FES.

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Stress case conditions of a credit rating downgrade or “material adverse event” and hypothetical adverse price movements in the underlying commodity markets would increase the total potential amount to $666 million, as shown below:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade (1)	$	477	$	5	$	78	$	560
Material adverse event (2)		36		57		13		106
Total	$	513	$	62	$	91	$	666

(1)	Includes $206 million and $59 million that is also considered an acceleration of payment or funding obligation for FES and the Utilities, respectively.
(2)	Includes $32 million that is also considered an acceleration of payment or funding obligation for FES.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $136 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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolios as of June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $138 million and $2 million, respectively. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one-year time horizon), FES would be required to post an additional $17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.

Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility.

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, was $1.6 billion as of June 30, 2011.

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 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 established a Risk Policy Committee, comprised of members of senior management, which 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 practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.

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The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 5 to the consolidated financial statements). Sources of information for the valuation of commodity derivative contracts as of June 30, 2011 are summarized by year in the following table:

Source of Information-
Fair Value by Contract Year	2011			2012			2013			2014			2015		Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	—		$	—		$	—		$	—		$	—	$	—	$	—
Other external sources(2)		(287	)		(169	)		(48	)		(38	)		—		—		(542	)
Prices based on models		9			(3	)		—			—			—		44		50
Total(3)	$	(278	)	$	(172	)	$	(48	)	$	(38	)	$	—	$	44	$	(492	)

(1)	Represents exchange traded New York Mercantile Exchange futures and options.
(2)	Primarily represents contracts based on broker and IntercontinentalExchange quotes.
(3)	Includes $445 million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of June 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $31 million ($20 million net of tax) during the next 12 months.

Equity Price Risk

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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

The benefit plan assets and obligations are remeasured annually using a December 31 measurement date or as significant triggering events occur. As of June 30, 2011, the FirstEnergy pension plan was invested in approximately 31% of equity securities, 46% of fixed income securities, 9% of absolute return strategies, 6% of real estate, 4% of private equity and 4% of cash. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011, FirstEnergy made contributions to its qualified pension plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.

NDT funds have been established to satisfy NGC’s and the Utilities’ nuclear decommissioning obligations. As of June 30, 2011, approximately 87% of the funds were invested in fixed income securities, 10% of the funds were invested in equity securities and 3% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,779 million, $197 million and $69 million for fixed income securities, equity securities and short-term investments, respectively, as of June 30, 2011, excluding $6 million of receivables, payables, deferred taxes and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $20 million reduction in fair value as of June 30, 2011. 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 NDT as other-than-temporary impairments. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the first six months of 2011, approximately $1 million, $4 million and $1 million was contributed to NDT of JCP&L, OE and TE, respectively. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of $92 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.

CREDIT RISK

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

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FirstEnergy maintains credit policies with respect to its counterparties to manage overall credit risk. This includes performing independent risk evaluations, actively monitoring portfolio trends and using collateral and contract provisions to mitigate exposure. As part of its credit program, FirstEnergy aggressively manages the quality of its portfolio of energy contracts, evidenced by a current weighted average risk rating for energy contract counterparties of BBB (S&P). As of June 30, 2011, the largest credit concentration was with J.P. Morgan Chase & Co., which is currently rated investment grade, representing 11% of FirstEnergy’s total approved credit risk comprised of 2.4% for FES, 1.6% for JCP&L, 2.0% for Met-Ed, 3.4% for WP and a combined 2.0% for the Ohio Companies.

OUTLOOK

Reliability Initiatives

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards 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 implemented and enforced by the ReliabilityFirst Corporation.

FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirst and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 resulting in customers losing power for up to eleven hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to ReliabilityFirst a vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirst issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirst on September 27, 2010. In March 2011, ReliabilityFirst submitted its proposed findings and settlement, although a final determination has not yet been made by FERC.

Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting certain investigations with regard to certain matters of compliance by Allegheny.

Maryland

By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below.

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In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.

In March 2009, the MDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules, with proposed rules to be filed by September 15, 2011. Separately, on April 7, 2011, the MDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the MDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.

New Jersey

In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). In its order of June 15, 2011, the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and the Division of Rate Counsel which resolved both Petitions, resulting in a net reduction in recovery of $0.8 million annually for all components of the SBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).

Ohio

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI’s integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

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Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to 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 were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.

Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. The PUCO has not yet acted on that application.

In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed applications for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO has not yet acted on the applications for rehearing.

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Pennsylvania

The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds will continue over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately $254 million ($189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.

WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates, which the PPUC granted in part by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.

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In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s OCA filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.

In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.

Virginia

In September 2010, PATH-VA filed an application with the VSCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.

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West Virginia

In August 2009, MP and PE filed with the WVPSC a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:

• a $40 million annualized base rate increase effective June 29, 2010;

• a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective in January 2011;

• a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and

• a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.

In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.

FERC Matters

Rates for Transmission Service Between MISO and PJM

In November 2004, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. 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 SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.

PJM Transmission Rate

In April 2007, 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, 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 based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

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FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing”— meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit study analysis as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement between ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreement of ATSI’s responsibility for certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI’s move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs — are a class of transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

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In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.

As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost-benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.

FirstEnergy cannot predict the outcome of these proceedings at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge’s ruling.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. FirstEnergy cannot predict the outcome of this matter.

Transmission Expansion

TrAIL Project. TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.

PATH Project. The PATH Project is comprised of a 765 kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

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PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.

Seneca Pumped Storage Project Relicensing

The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’s regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD) in the license docket.

On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PAD documents necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’ to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps. of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’s petition, including motions to dismiss FirstEnergy’s petition. The “project boundary” issue is pending before FERC.

The next steps in the relicensing process are for FirstEnergy and the Seneca Nation to define and perform certain environmental and operational studies to support their respective applications. These steps are expected to run through approximately November of 2013. FirstEnergy cannot predict the outcome of these proceedings at this time.

Environmental Matters

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy 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.

CAA Compliance

FirstEnergy is required to meet federally-approved SO₂ and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂ and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.

In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on coal-fired Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these three complaints.

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The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, 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. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the Portland coal-fired plant based on “modifications” dating back to 1986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of Keystone, and Penelec, as former owner and operator of Shawville, are unable to predict the outcome of this matter.

In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City’s air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. Mission is seeking indemnification from Penelec, the co-owner and operator of Homer City prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claims and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. The scope of Penelec’s indemnity obligation to and from Mission is under dispute and Penelec is unable to predict the outcome of this matter.

In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired 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. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.

In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired plants: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

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In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.

In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants in West Virginia.

FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.

State Air Quality Compliance

In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO₂ and NO_X, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NO_X, SO₂ and mercury, based on a PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NO_X and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.

In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.

National Ambient Air Quality Standards

The EPA’s CAIR requires reductions of NOx and SO₂ emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court 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. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the Federal Register). CSAPR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. FGCO’s future cost of compliance may be substantial and changes to FirstEnergy’s operations may result. Management is currently assessing the impact of CSAPR, other environmental proposals and other factors on FirstEnergy’s competitive fossil generating facilities, including but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operations of its coal-fired plants.

Hazardous Air Pollutant Emissions

On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Depending on the action taken by the EPA and how any future regulations are ultimately implemented, FirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FirstEnergy’s operations may result.

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Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2) effective January 2, 2011 for existing facilities under the CAA’s PSD program. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO₂ pollutants.

At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO₂, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

In 2009, the U.S. Court of Appeals for the Second Circuit and 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. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy received notice of a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.

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 of its 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, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.

In 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 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). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with

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benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore Plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

In April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer 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. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.

FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.

Monongahela River Water Quality

In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry coal-fired plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP’s recommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

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Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy’s future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

The Little Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.

The Utility Registrants 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 June 30, 2011, based on estimates of the total costs of cleanup, the Utility Registrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $133 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $61 million) have been accrued through June 30, 2011. Included in the total are accrued liabilities of approximately $63 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.

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. 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. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class action attempt, and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have yet to take any affirmative steps to pursue their individual claims.

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2011, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.

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In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.

On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.

In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the DOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. The parties expect a ruling sometime in the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.

Other Legal Matters

In February 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.

129

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.

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

See Note 12 of the Combined Notes to the Consolidated Financial Statements (Unaudited) for discussion of new accounting pronouncements.

130

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, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns FirstEnergy’s nuclear generation facilities, respectively. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities.

FES’ revenues are derived from sales to individual retail customers, sales to communities in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. In 2010, FES also supplied the POLR default service requirements of Met-Ed and Penelec.

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

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

Results of Operations

Net income decreased by $158 million in the first six months of 2011 compared to the same period of 2010. The decrease was primarily due to lower sales margin, an inventory reserve adjustment, non-core asset impairments and the effect of mark-to-market adjustments.

Revenues

Total revenues decreased $30 million, or 1%, in the first six months of 2011, compared to the same period of 2010, primarily due to reduced POLR and structured sales, partially offset by growth in direct and governmental aggregation sales.

The decrease in revenues resulted from the following sources:

	Six Months
	Ended June 30				Increase
Revenues by Type of Service	2011		2010		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	1,765	$	1,097	$	668
POLR and Structured Sales		607		1,315		(708	)
Wholesale		156		142		14
Transmission		56		36		20
RECs		44		67		(23	)
Other		56		57		(1	)
Total Revenues	$	2,684	$	2,714	$	(30	)

	Six Months
	Ended June 30				Increase
MWH Sales by Type of Service	2011		2010		(Decrease)
	(In thousands)
Direct		21,219		12,857		65.0	%
Governmental Aggregation		8,279		5,447		52.0	%
POLR and Structured Sales		9,561		25,344		(62.3	)%
Wholesale		1,380		1,538		(10.3	)%
Total Sales		40,439		45,186		(10.5	)%

131

The increase in direct and governmental aggregation revenues of $668 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio that provided generation to approximately 1.5 million residential and small commercial customers at the end of June 2011 compared to approximately 1.1 million customers at the end of June 2010.

The decrease in POLR revenues of $708 million was due to lower sales volumes to Met-Ed and Penelec, primarily due to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec, and reduced sales to the Ohio Companies, partially offset by increased sales to non-associated companies and higher unit prices to the Pennsylvania Companies consistent with our business strategy. Participation in POLR auctions and RFPs are expected to continue but the proportion of these sales will depend on our hedge positions for direct retail and aggregation sales.

Wholesale revenues increased by $14 million due to higher wholesale prices partially offset by decreased volumes. The lower sales volumes were the result of decreased short-term (net hourly positions) transactions in MISO. Additional capacity revenues earned by generating units were partially offset by losses on financially settled sales.

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

	Increase
Source of Change in Direct and Governmental Aggregation	(Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	493
Change in prices		(20	)
		473
Governmental Aggregation:
Effect of increase in sales volumes		176
Change in prices		19
		195
Net Increase in Direct and Governmental Aggregation Revenues	$	668

	Increase
Source of Change in POLR Revenues	(Decrease)
	(In millions)
POLR:
Effect of decrease in sales volumes	$	(819	)
Change in prices		111
	$	(708	)

	Increase
Source of Change in Wholesale Revenues	(Decrease)
Wholesale:
Effect of increase in sales volumes	$	(15	)
Change in prices		29
	$	14

Transmission revenues increased by $20 million due primarily to higher MISO and PJM congestion revenue. The revenues derived from the sale of RECs declined $23 million in the first six months of 2011.

Expenses

Total operating expenses increased by $199 million in the first six months of 2011, compared with the same period of 2010.

132

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first six months of 2011, compared with the same period last year:

	Increase
Source of Change in Fuel and Purchased Power	(Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	2
Change due to volume consumed		(29	)
		(27	)
Nuclear Fuel:
Change due to increased unit costs		14
Change due to volume consumed		1
		15
Non-affiliated Purchased Power:
Change due to increased unit costs		108
Change due to volume purchased		(242	)
		(134	)
Affiliated Purchased Power:
Change due to increased unit costs		34
Change due to volume purchased		(30	)
		4
Net Decrease in Fuel and Purchased Power Costs	$	(142	)

Total fuel costs decreased by $12 million in the first six months of 2011, compared to the same period of 2010, as a result of reduced generation at the fossil units, partially offset by higher fossil unit costs. Fossil unit prices increased primarily due to increased coal transportation costs. Nuclear fuel expenses increased primarily due to higher unit prices following the refueling outages that occurred in 2010.

Non-affiliated purchased power costs decreased by $134 million in the first six months of 2011, compared to the same period of 2010, due to lower volumes purchased partially offset by higher unit costs. The decrease in volume relates to the absence in 2011 of a 1,300 MW third-party contract associated with serving Met-Ed and Penelec in the first half of 2011. Affiliated purchased power costs increased by $4 million in the first six months of 2011, compared to the same period of 2010, due to higher unit costs, partially offset by decreased volumes purchased.

Other operating expenses increased by $302 million in the first six months of 2011, compared to the same period of 2010 due to the following:

• Transmission expenses increased by $176 million due primarily to increases in PJM of $198 million from higher congestion, network, and line loss expense, partially offset by lower MISO transmission expenses of $22 million.

• Nuclear operating costs increased by $48 million due primarily to having two refueling outages, Perry and Beaver Valley 2, occurring this year. While Davis-Besse had a refueling outage last year, the work performed during the second quarter of 2010 was largely capital-related.

• Fossil operating costs increased by $20 million due primarily to higher labor, contractor and material costs resulting from an increase in planned and unplanned outages.

• A $54 million provision for excess and obsolete material related to revised inventory practices adopted in connection with the Allegheny merger.

Impairment charges of long-lived assets increased by $18 million due to impairments at certain non-core peaking facilities during the first six months of 2011.

General taxes increased by $11 million due to an increase in revenue-related taxes.

Other Expense

Total other expense increased by $17 million in the first six months of 2011, compared to the same period of 2010, primarily due to a decrease in capitalized interest ($24 million) associated with the completion of the Sammis AQC project in 2010, partially offset by increased investment income ($8 million) from higher NDT income.

133

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. OE procures generation services for those franchise customers electing to retain OE and Penn as their power supplier.

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

Results of Operations

Earnings available to parent decreased by $5 million in the first six months of 2011, compared to the same period of 2010. The decrease primarily resulted from lower revenues and higher other operating expenses, partially offset by lower purchased power costs and amortization of regulatory assets.

Revenues

Revenues decreased by $171 million, or 18%, in the first six months of 2011, compared with the same period in 2010, due to a decrease in generation revenues, partially offset by higher distribution and wholesale generation revenues.

Distribution revenues increased by $31 million in the first six months of 2011, compared to the same period in 2010, due to an increase in KWH deliveries in the residential and industrial sectors and higher average prices in all customer classes. The higher KWH deliveries in the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 6% increase in heating degree days. The increase in distribution deliveries to industrial customers was primarily due to recovering economic conditions in OE’s and Penn’s service territory. Higher average prices in all customer classes were principally due to the recovery of deferred distribution costs.

Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period in 2010, are summarized in the following tables:

Distribution KWH Deliveries	Increase
Residential		3.0	%
Commercial		0.2	%
Industrial		3.5	%
Increase in Distribution Deliveries		2.4	%

Distribution Revenues	Increase
	(In millions)
Residential	$	19
Commercial		7
Industrial		5
Increase in Distribution Revenues	$	31

Retail generation revenues decreased by $211 million primarily due to a decrease in KWH sales and lower average prices in all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. OE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales were primarily the result of increased customer shopping, partially offset by increased weather-related usage in the first six months of 2011, as described above. The increase in customer shopping for residential, commercial and industrial customer classes was 23%, 14% and 8%, respectively.

134

Decreases in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period in 2010, are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(30.7	)%
Commercial		(39.0	)%
Industrial		(25.4	)%
Decrease in Retail Generation Sales		(31.2	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(128	)
Commercial		(52	)
Industrial		(31	)
Decrease in Retail Generation Revenues	$	(211	)

Wholesale revenues increased by $15 million in the first six months of 2011, compared to the same period of 2010, due to higher revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.

Expenses

Total expenses decreased by $171 million in the first six months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:

	Increase
Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(175	)
Other operating expenses		36
Amortization of regulatory assets, net		(36	)
General taxes		4
Net Decrease in Expenses	$	(171	)

Purchased power costs decreased in the first six months of 2011, compared to the same period of 2010, due to lower KWH purchases resulting from reduced generation sales requirements in the first six months of 2011 coupled with lower unit costs. The increase in other operating expenses for the first six months of 2011 was principally due to expenses associated with refueling outages at OE’s leased Perry and Beaver Valley Unit 2 that were absent in 2010. The amortization of regulatory assets decreased primarily due to higher deferred residential generation credits in 2011. General taxes increased as a result of higher property taxes.

Other Expense

Other expense increased by $3 million in the first six months of 2011, compared to the same period of 2010 due to lower nuclear decommissioning trust investment income.

135

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS

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

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

Results of Operations

Earnings available to parent decreased slightly in the first six months of 2011, compared to the same period of 2010. The decrease in earnings was due to lower revenues, partially offset by lower purchased power and amortization of regulatory assets.

Revenues

Revenues decreased by $183 million, or 29%, in the first six months of 2011, compared to the same period of 2010, due to lower retail generation and distribution revenues.

Distribution revenues decreased by $14 million in the first six months of 2011, compared to the same period of 2010, due to lower average unit prices for the residential and industrial customer classes, partially offset by increased KWH deliveries to the residential and commercial customer classes. The lower average unit prices were the result of the absence of transition charges in 2011. Higher KWH deliveries to the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 15% increase in heating degree days in CEI’s service territory. Lower distribution deliveries to industrial customers reflected softer economic conditions in this sector.

Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		2.2	%
Commercial		2.9	%
Industrial		(3.1	)%
Increase in Distribution Deliveries		0.6	%

	Increase
Distribution Revenues	(Decrease)
	(In millions)
Residential	$	2
Commercial		17
Industrial		(33	)
Net Decrease in Distribution Revenues	$	(14	)

136

Retail generation revenues decreased by $169 million in the first six months of 2011, compared to the same period of 2010, primarily due to lower KWH sales in all customer classes and lower average unit prices for the commercial and residential customer classes. Customer shopping has increased for residential, commercial and industrial classes by 22%, 13% and 36%, respectively. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. CEI defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Reduced KWH sales were primarily the result of increased customer shopping in the first six months of 2011, partially offset by the impact of increased weather-related usage by residential customers as described above. Lower average unit prices in the residential customer class were the result of generation credits in place for 2011.

Decreases in retail generation sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(46.6	)%
Commercial		(44.2	)%
Industrial		(69.8	)%
Decrease in Retail Generation Sales		(55.0	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(69	)
Commercial		(46	)
Industrial		(54	)
Decrease in Retail Generation Revenues	$	(169	)

Expenses

Total expenses decreased by $173 million in the first six months of 2011, compared to the same period of 2010. The following table presents the change from the prior period by expense category:

	Increase
Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(155	)
Other operating costs		6
Amortization of regulatory assets, net		(34	)
General taxes		10
Net Decrease in Expenses	$	(173	)

Purchased power costs decreased in the first six months of 2011 due to lower KWH purchases resulting from reduced sales requirements in the first six months of 2011. Other operating expenses increased principally due to 2011 inventory valuation adjustments. Decreased amortization of regulatory assets was primarily due to the completion of transition cost recovery at the end of 2010 and deferred residential generation credits in 2011, partially offset by increased recovery of deferred distribution costs and the absence in 2011 of renewable energy credit expenses that were deferred in 2010. General taxes increased in the first six months of 2011 due to increased property taxes as compared to the same period of 2010.

137

THE TOLEDO EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS

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

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

Results of Operations

Earnings available to parent increased by $3 million in the first six months of 2011, compared to the same period of 2010. The increase primarily resulted from lower purchased power costs and higher cost deferrals, partially offset by lower revenues and higher other operating expenses.

Revenues

Revenues decreased by $40 million, or 16%, in the first six months of 2011, compared to the same period of 2010, due to a decrease in retail generation revenues, partially offset by higher distribution revenues and wholesale generation revenues.

Distribution revenues increased by $3 million in the first six months of 2011, compared to the same period of 2010, due to higher residential revenues, partially offset by lower industrial revenues. Residential revenues were the result of higher KWH deliveries and average unit prices. The higher KWH deliveries in the residential class were driven by increased weather-related usage in the first six months of 2011, reflecting a 14% increase in heating degree days, partially offset by a 23% decrease in cooling degree days in TE’s service territory. Industrial revenues were impacted by lower average unit prices, partially offset by higher KWH deliveries from recovering economic conditions.

Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		4.5	%
Commercial		(2.5	)%
Industrial		3.7	%
Net Increase in Distribution Deliveries		2.6	%

	Increase
Distribution Revenues	(Decrease)
	(In millions)
Residential	$	5
Commercial		—
Industrial		(2	)
Net Increase in Distribution Revenues	$	3

Retail generation revenues decreased by $53 million in the first six months of 2011, compared to the same period of 2010, due to lower KWH sales and lower unit prices for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. TE defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings. Lower KWH sales were the result of increased customer shopping, partially offset by increased weather-related usage as described above. Customer shopping has increased for residential, commercial and industrial classes by 16%, 13% and 5%, respectively.

138

Decreases in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(28.3	)%
Commercial		(46.6	)%
Industrial		(11.7	)%
Decrease in Retail Generation Sales		(22.6	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(16	)
Commercial		(13	)
Industrial		(24	)
Decrease in Retail Generation Revenues	$	(53	)

Wholesale revenues increased by $9 million in the first six months of 2011, compared to the same period of 2010, primarily due to higher revenues from sales to NGC from TE’s leasehold interest in Beaver Valley Unit 2.

Expenses

Total expenses decreased by $42 million in the first six months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:

	Increase
Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(53	)
Other operating expenses		18
Deferral of regulatory assets, net		(8	)
General Taxes		1
Net Decrease in Expenses	$	(42	)

Purchased power costs decreased in the first six months of 2011, compared to the same period of 2010, due to lower KWH purchases resulting from reduced generation sales requirements in the first six months of 2011 coupled with lower unit costs. The increase in other operating costs for the first six months of 2011 was primarily due to expenses associated with the 2011 refueling outage at the leased Beaver Valley Unit 2 and an Ohio Supreme Court decision rendered in the second quarter of 2011 favoring a large industrial customer, both of which were absent in 2010. The deferral of regulatory assets reduced expenses due to higher PUCO-approved cost deferrals in the first six months of 2011, compared to the same period of 2010.

Other Expense

Other expense increased by $2 million in the first six months of 2011, compared to the same period of 2010, due to lower nuclear decommissioning trust investment income.

139

JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS

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

As authorized by JCP&L’s Board of Directors, on May 31, 2011 JCP&L returned $500 million of capital to FirstEnergy Corp., the sole owner of all of the shares of JCP&L’s common stock.

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

Results of Operations

Net income decreased by $18 million in the first six months of 2011, compared to the same period of 2010. The decrease was primarily due to lower revenues, partially offset by reductions in purchased power costs, other operating costs and net amortization of regulatory assets.

Revenues

Revenues decreased by $190 million, or 13%, in the first six months of 2011 compared to the same period of 2010. The decrease in revenues was due to lower distribution and retail generation revenues, partially offset by an increase in wholesale generation and other revenues.

Distribution revenues decreased by $71 million in the first six months of 2011, compared to the same period of 2010, primarily due to an NJBPU-approved rate adjustment that became effective March 1, 2011, for all customer classes. The lower KWH deliveries to the residential class were influenced by decreased weather-related usage in the first six months of 2011, reflecting a 16% decrease in cooling degree days offsetting a 7% increase in heating degree days in JCP&L’s service territory. Lower distribution deliveries to commercial and industrial customers reflected soft economic conditions in these sectors.

Decreases in distribution KWH deliveries and revenues in the first six months of 2011 compared to the same period of 2010 are summarized in the following tables:

Distribution KWH Deliveries	Decrease
Residential		(2.5	)%
Commercial		(3.3	)%
Industrial		(1.8	)%
Decrease in Distribution Deliveries		(2.7	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(33	)
Commercial		(31	)
Industrial		(7	)
Decrease in Distribution Revenues	$	(71	)

Retail generation revenues decreased by $132 million due to lower retail generation KWH sales in all customer classes primarily due to an increase in customer shopping. Customer shopping has increased for residential, commercial and industrial classes by 10%, 11% and 4%, respectively. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

140

Decreases in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(12.1	)%
Commercial		(26.2	)%
Industrial		(24.8	)%
Decrease in Retail Generation Sales		(16.7	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(68	)
Commercial		(59	)
Industrial		(5	)
Decrease in Retail Generation Revenues	$	(132	)

Wholesale generation revenues increased by $6 million in the first six months of 2011, compared to the same period of 2010, due to an increase in PJM spot market energy sales.

Other revenues increased by $8 million in the first six months of 2011, compared to the same period of 2010, primarily due to increases in PJM network transmission revenues and transition bond revenues.

Expenses

Total expenses decreased by $163 million in the first six months of 2011, compared to the same period of 2010. The following table presents changes from the prior period by expense category:

	Increase
Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(126	)
Other operating costs		(6	)
Provision for depreciation		(3	)
Amortization of regulatory assets, net		(29	)
General taxes		1
Net Decrease in Expenses	$	(163	)

Purchased power costs decreased by $126 million in the first six months of 2011 due to lower requirements from reduced retail generation sales. Other operating costs decreased by $6 million in the first six months of 2011 principally from lower storm restoration costs. The amortization of regulatory assets decreased by $29 million due to reduced cost recovery under the NJBPU-approved NUG tariffs that became effective March 1, 2011, partially offset by lower storm cost deferrals and the write-off of nonrecoverable NUG costs.

141

METROPOLITAN EDISON COMPANY

MANAGEMENT’S NARRATIVE
ANALYSIS OF RESULTS OF OPERATIONS

Met-Ed is a wholly owned electric utility subsidiary of FirstEnergy. Met-Ed conducts business in eastern Pennsylvania, providing regulated electric transmission and distribution services. Met-Ed also procures generation service for those customers electing to retain Met-Ed as their power supplier. Met-Ed procures power under its Default Service Plan (DSP) in which full requirements products (energy, capacity, ancillary services, and applicable transmission services) are procured through descending clock auctions.

As authorized by Met-Ed’s Board of Directors, Met-Ed returned $150 million of capital to FirstEnergy Corp. on May 31, 2011, the sole owner of all of the shares of Met-Ed’s common stock.

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

Results of Operations

Net income increased by $10 million in the first six months of 2011, compared to the same period of 2010. The increase was primarily due to decreased purchased power, other operating expenses and amortization of net regulatory assets partially offset by decreased revenues.

Revenues

Revenue decreased by $279 million, or 30%, in the first six months of 2011 compared to the same period of 2010, reflecting lower distribution, retail generation, wholesale generation and transmission revenues.

Distribution revenues decreased by $154 million in the first six months of 2011, compared to the same period of 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rate. Slightly higher KWH deliveries reflect increased weather-related usage due to an 8% increase in heating degree days offsetting a 15% decrease in cooling degree days in the first six months of 2011, compared to the same period in 2010.

Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		0.2	%
Commercial		(4.1	)%
Industrial		3.6	%
Net Increase in Distribution Deliveries		0.5	%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(58	)
Commercial		(47	)
Industrial		(49	)
Decrease in Distribution Revenues	$	(154	)

Retail generation revenues decreased by $10 million in the first six months of 2011 compared to the same period of 2010, due to lower KWH sales to all customer classes resulting from increased customer shopping. Customer shopping has increased for residential, commercial and industrial classes by 1%, 42% and 87%, respectively. The impact of increased customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Met-Ed began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

142

Changes in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(1.0	)%
Commercial		(44.7	)%
Industrial		(87.6	)%
Decrease in Retail Generation Sales		(43.1	)%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	88
Commercial		(14	)
Industrial		(84	)
Net Decrease in Retail Generation Revenues	$	(10	)

Wholesale revenues decreased by $105 million in the first six months of 2011 compared to the same period of 2010 primarily due to Met-Ed ending certain capacity purchase for resale contracts.

Transmission revenues decreased by $11 million in the first six months of 2011 compared to the same period of 2010 primarily due to the termination of Met-Ed’s TSC rates effective January 1, 2011. Met-Ed defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total expenses decreased $290 million in the first six months of 2011 compared to the same period of 2010. The following table presents changes from the prior year by expense category:

Expenses - Changes	Decrease
	(In millions)
Purchased power costs	$	(149	)
Other operating costs		(95	)
Provision for depreciation		(1	)
Amortization of regulatory assets, net		(43	)
General taxes		(2	)
Decrease in Expenses	$	(290	)

Purchased power costs decreased by $149 million in the first six months of 2011 due to a decrease in KWH purchased to source generation sales requirements, partially offset by higher unit costs. Other operating costs decreased $95 million in the first six months of 2011 compared to the same period in 2010 due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above) partially offset by increased costs for energy efficiency programs. The amortization of regulatory assets decreased $43 million in the first six months of 2011 primarily due to the termination of transmission and transition tariff riders at the end of 2010. General taxes decreased by $2 million in the first six months of 2011 primarily due to lower gross receipts taxes.

Other Expense

In the first six months of 2011, interest income decreased by $2 million due to reduced CTC stranded asset balances compared to the same period of 2010.

143

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 electric transmission and distribution services. Penelec also procures generation service for those customers electing to retain Penelec as their power supplier. Penelec procures power under its Default Service Plan (DSP) in which full requirements products (energy, capacity, ancillary services and applicable transmission services) are procured through descending clock auctions.

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

Results of Operations

Net income increased by $2 million in the first six months of 2011, compared to the same period of 2010. The increase was primarily due to lower purchased power and other operating costs, partially offset by lower revenues and higher net amortization of regulatory assets.

Revenues

Revenues decreased by $193 million, or 25%, in the first six months of 2011 compared to the same period of 2010. The decrease in revenue was primarily due to lower distribution revenues, retail and wholesale generation revenues, and transmission revenues.

Distribution revenues decreased by $5 million in the first six months of 2011, compared to the same period of 2010, primarily due to lower rates resulting from the DSP that began in 2011 that eliminated the transmission component from the distribution rate, partially offset by a PPUC approved rate adjustment for NUG costs. Higher KWH deliveries to industrial customers were primarily due to recovering economic conditions in Penelec’s service territories, compared to the first six months of 2010. Lower KWH deliveries to residential and commercial customers in the first six months of 2011 reflected lower weather-related usage as cooling degree days were 10% below the same period in 2010.

Changes in distribution KWH deliveries and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

	Increase
Distribution KWH Deliveries	(Decrease)
Residential		(1.2	)%
Commercial		(4.7	)%
Industrial		7.3	%
Net Increase in Distribution Deliveries		1.4	%

	Increase
Distribution Revenues	(Decrease)
	(In millions)
Residential	$	3
Commercial		(14	)
Industrial		6
Net Decrease in Distribution Revenues	$	(5	)

Retail generation revenues decreased by $80 million in the first six months of 2011, compared to the same period of 2010, due to lower KWH sales for all customer classes resulting from increased customer shopping. The increase in customer shopping for residential, commercial and industrial customer classes was 2%, 45% and 81%, respectively. The impact of customer shopping is partially offset by higher generation rates that reflect the inclusion of transmission services under the DSP, effective January 1, 2011, for all customer classes. Retail generation obligations are attributable to non-shopping customers and are procured through full-requirements auctions. In 2011, Penelec began deferring the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

144

Changes in retail generation KWH sales and revenues in the first six months of 2011, compared to the same period of 2010, are summarized in the following tables:

Retail Generation KWH Sales	Decrease
Residential		(2.7	)%
Commercial		(47.1	)%
Industrial		(87.4	)%
Decrease in Retail Generation Sales		(47.5	)%

	Increase
Retail Generation Revenues	(Decrease)
	(In millions)
Residential	$	52
Commercial		(35	)
Industrial		(97	)
Net Decrease in Retail Generation Revenues	$	(80	)

Wholesale generation revenues decreased by $98 million in the first six months of 2011, compared to the same period of 2010, due to Penelec no longer purchasing non-NUG capacity for resale to the PJM market beginning in 2011.

Transmission revenues decreased by $11 million in the first six months of 2011, compared to the same period of 2010, primarily due to the termination of Penelec’s TSC rates effective January 1, 2011. Penelec defers the difference between transmission revenues and transmission costs incurred, resulting in no material effect to current period earnings.

Expenses

Total expenses decreased by $200 million in the first six months of 2011, as compared with the same period of 2010. The following table presents changes from the prior year by expense category:

	Increase
Expenses - Changes	(Decrease)
	(In millions)
Purchased power costs	$	(192	)
Other operating costs		(53	)
Amortization of regulatory assets, net		46
Provision for depreciation		(1	)
Net Decrease in Expenses	$	(200	)

Purchased power costs decreased by $192 million in the first six months of 2011, compared to the same period of 2010, due to decreased KWH purchased to source generation sales requirements. Other operating costs decreased by $53 million in the first six months of 2011, due to lower transmission congestion and transmission loss expenses that are now included in the cost of purchased power (see reference to deferral accounting above). The amortization of net regulatory assets increased by $46 million in the first six months of 2011, primarily due to reduced NUG deferrals as a result of a PPUC approved increase in Penelec’s NUG cost recovery rider in January 2011.

145

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

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

(b) CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

During the quarter ended June 30, 2011, other than changes resulting from the Allegheny merger discussed below, there have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s, FES’, OE’s, CEI’s, TE’s, JCP&L’s, Met-Ed’s and Penelec’s internal control over financial reporting.

On February 25, 2011, the merger between FirstEnergy and Allegheny closed. FirstEnergy is currently in the process of integrating Allegheny’s operations, processes, and internal controls. See Note 2 to the consolidated financial statements in Part I, Item I for additional information relating to the merger.

146

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

For the quarter ended June 30, 2011, there have been no material changes to the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2010, as modified by changes to certain risk factors disclosed in our Quarterly Report on Form 10-Q for the period ended March 31, 2011.

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 second quarter of 2011.

	Period
	April		May		June		Second Quarter
Total Number of Shares Purchased(a)		213,550		367,422		428,966		1,009,938
Average Price Paid per Share	$	38.59	$	42.62	$	44.44	$	42.54
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 for some or all of the following: 2007 Incentive Plan, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 Long-Term Incentive Plan, Allegheny Energy, Inc. 2008 Long-Term Incentive Plan, Allegheny Energy, Inc, Non-Employee Director Stock Plan, Allegheny Energy, Inc, Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.

ITEM 5. OTHER INFORMATION

Signal Peak Mine Safety

FirstEnergy, through its FEV wholly-owned subsidiary, has a 50% interest in Global Mining Group LLC, a joint venture that owns Signal Peak which is a company that constructed and operates the Bull Mountain Mine No. 1 (Mine), an underground coal mine near Roundup, Montana. The operation of the Mine is subject to regulation by the Federal Mine Safety and Health Administration (MSHA) under the Federal Mine Safety and Health Act of 1977 (Mine Act).

Section 1503 of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was enacted on July 21, 2010, contains new reporting requirements regarding mine safety, including, to the extent applicable, disclosing in periodic reports filed under the Securities Exchange Act of 1934 the receipt of certain notifications from the MSHA.

147

Signal Peak received the following notices of violation and proposed assessments for the Mine under the Mine Act during the three months ended June 30, 2011:

	Signal
	Peak
Number of significant and substantial violations of mandatory health or safety standards under 104*		30
Number of orders issued under 104(b)*		—
Number of citations and orders for unwarrantable failure to comply with mandatory health or safety standards under 104(d)*		—
Number of flagrant violations under 110(b)(2)*		—
Number of imminent danger orders issued under 107(a)*		—
MSHA written notices under Mine Act section 104(e)* of a pattern of violation of mandatory health or safety standards or of the potential to have such a pattern		—
Pending Mine Safety Commission legal actions (including any contested citations issued)		8
Number of mining related fatalities		—
Total dollar value of proposed assessments	$	6,989

* References to sections under Mine Act

The inclusion of this information in this report is not an admission by FirstEnergy that it controls Signal Peak or that Signal Peak is FirstEnergy’s subsidiary for purposes of Section 1503 or for any other purpose,

More detailed information about the Mine, including safety-related data, can be found at MSHA’s website, www.MSHA.gov. Signal Peak operates the Mine under the MSHA identification number 2401950.

ITEM 6. EXHIBITS

Exhibit Number
FirstEnergy
	3.1		Amendment to the Amended Articles of Incorporation of FirstEnergy Corp. dated as of February 25, 2011 (incorporated by reference to FirstEnergy’s Form 8-K filed February 25, 2011, Exhibit 3.1, File No. 21011)
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 2011, 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.

148

Exhibit Number
FES
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Solutions Corp., and Allegheny Energy Supply Company, LLC, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended June 30, 2011, 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.
OE
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of Ohio Edison Company. for the period ended June 30, 2011, 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.
CEI
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of The Cleveland Electric Illuminating Company. for the period ended June 30, 2011, 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.

149

Exhibit Number
TE
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of The Toledo Edison Company. for the period ended June 30, 2011, 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.
JCP&L
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of Jersey Central Power & Light Company. for the period ended June 30, 2011, 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.
Met-Ed
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

150

Exhibit Number
	101	*	The following materials from the Quarterly Report on Form 10-Q of Metropolitan Edison Company. for the period ended June 30, 2011, 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.
Penelec
	10.1		Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
	12		Fixed charge ratios
	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of Pennsylvania Electric Company. for the period ended June 30, 2011, 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.

* Users of these 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 these 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.

151

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.

August 2, 2011

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
 

Harvey L. Wagner 

Vice President, Controller
and Chief Accounting Officer 

JERSEY CENTRAL POWER & LIGHT COMPANY
Registrant
 

K. Jon Taylor 

Controller
(Principal Accounting Officer) 

152

EX-10.1

EXECUTION COPY

U.S. $2,500,000,000

CREDIT AGREEMENT

Dated as of June 17, 2011,

Among

FIRSTENERGY SOLUTIONS CORP.

and

ALLEGHENY ENERGY SUPPLY COMPANY, LLC,
as Borrowers,

THE BANKS NAMED HEREIN,
as Banks,

JPMORGAN CHASE BANK, N.A.,
as Administrative Agent,

THE FRONTING BANKS
PARTY HERETO FROM TIME TO TIME
as Fronting Banks

and

THE SWING LINE LENDERS PARTY
HERETO FROM TIME TO TIME
as Swing Line Lenders

J.P. MORGAN SECURITIES LLC	CITIGROUP GLOBAL MARKETS INC.
BARCLAYS CAPITAL	KEYBANK NATIONAL ASSOCIATION
MERRILL LYNCH, PIERCE, FENNER & SMITH	THE BANK OF NOVA SCOTIA
INCORPORATED	UNION BANK, N.A.
RBS SECURITIES INC.	THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
	WELLS FARGO SECURITIES, LLC

Joint Lead Arrangers

MERRILL LYNCH, PIERCE, FENNER & SMITH
INCORPORATED
BARCLAYS CAPITAL
THE ROYAL BANK OF SCOTLAND PLC
Syndication Agents CITIBANK, N.A.
UNION BANK, N.A.
THE BANK OF NOVA SCOTIA
THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
KEYBANK NATIONAL ASSOCIATION
WELLS FARGO BANK, NATIONAL
ASSOCIATION
Documentation Agents

TABLE OF CONTENTS

	Page
ARTICLE I DEFINITIONS AND ACCOUNTING TERMS
SECTION 1.02. Computation of Time Periods		21
SECTION 1.03. Accounting Terms		22
SECTION 1.04. Terms Generally		22
ARTICLE II AMOUNTS AND TERMS OF THE ADVANCES AND LETTERS OF CREDIT
SECTION 2.01. The Pro-Rata Advances		22
SECTION 2.02. Making the Pro-Rata Advances		23
SECTION 2.03. Swing Line Advances		24
SECTION 2.04. Letters of Credit		27
SECTION 2.05. Fees		35
SECTION 2.06. Adjustment of the Commitments; Borrower Sublimits		36
SECTION 2.07. Repayment of Advances		37
SECTION 2.08. Interest on Advances		37
SECTION 2.09. Additional Interest on Advances		38
SECTION 2.10. Interest Rate Determination		38
SECTION 2.11. Conversion of Advances		39
SECTION 2.12. Prepayments		40
SECTION 2.13. Increased Costs		41
SECTION 2.14. Illegality		42
SECTION 2.15. Payments and Computations		43
SECTION 2.16. Taxes		45
SECTION 2.17. Sharing of Payments, Etc.		47
SECTION 2.18. Noteless Agreement; Evidence of Indebtedness		48
SECTION 2.19. Extension of Termination Date		49
SECTION 2.20. Several Obligations		50
SECTION 2.21. Defaulting Lenders		51
ARTICLE III CONDITIONS OF LENDING AND ISSUING LETTERS OF CREDIT
SECTION 3.01. Conditions Precedent to Initial Extension of Credit		52
SECTION 3.02. Conditions Precedent to Each Extension of Credit		54
ARTICLE IV REPRESENTATIONS AND WARRANTIES
SECTION 4.01. Representations and Warranties of the Borrowers		55
ARTICLE V COVENANTS OF THE BORROWERS
SECTION 5.01. Affirmative Covenants of the Borrowers		58
SECTION 5.02. Debt to Capitalization Ratio		62
SECTION 5.03. Negative Covenants of the Borrowers		62

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	Page
ARTICLE VI EVENTS OF DEFAULT
SECTION 6.01. Events of Default		66
ARTICLE VII THE ADMINISTRATIVE AGENT
SECTION 7.01. Authorization and Action		69
SECTION 7.02. Administrative Agent’s Reliance, Etc.		69
SECTION 7.03. JPMCB and the Fronting Banks and Swing Line Lenders		70
SECTION 7.04. Lender Credit Decision; No Other Duties		70
SECTION 7.05. Indemnification		71
SECTION 7.06. Successor Administrative Agent		71
SECTION 7.07. Delegation of Duties		72
ARTICLE VIII MISCELLANEOUS
SECTION 8.01. Amendments, Etc.		72
SECTION 8.02. Notices, Etc.		73
SECTION 8.03. Electronic Communications		73
SECTION 8.04. No Waiver; Remedies		75
SECTION 8.05. Costs and Expenses; Indemnification		75
SECTION 8.06. Right of Set-off		77
SECTION 8.07. Binding Effect		77
SECTION 8.08. Assignments and Participations		77
SECTION 8.09. Governing Law		82
SECTION 8.10. Consent to Jurisdiction; Waiver of Jury Trial		82
SECTION 8.11. Severability		83
SECTION 8.12. Entire Agreement		83
SECTION 8.13. Execution in Counterparts		83
SECTION 8.14. USA PATRIOT Act Notice		83
SECTION 8.15. No Fiduciary Duty		83

ii

SCHEDULES AND EXHIBITS

Schedule I	-	List of Commitments and Lending Offices
Schedule II	-	List of L/C Fronting Bank Commitments
Schedule III	-	List of Swing Line Commitments
Schedule IV	-	Letters of Credit
Schedule V	-	Existing Facilities
Schedule VI	-	Disclosure Documents
Exhibit A	-	Form of Assignment and Assumption
Exhibit B	-	Form of Note
Exhibit C	-	Form of Notice of Pro-Rata Borrowing
Exhibit D	-	Form of Notice of Swing Line Borrowing
Exhibit E	-	Form of Letter of Credit Request
Exhibit F	-	Form of Opinion of Wendy E. Stark, Associate General Counsel of FE
Exhibit G	-	Form of Opinion of Akin Gump Strauss Hauer & Feld LLP
Exhibit H	-	Form of Opinion of King & Spalding LLP
Exhibit I	-	Form of Affiliate Subordination Provisions

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CREDIT AGREEMENT

CREDIT AGREEMENT, dated as of June 17, 2011, among FIRSTENERGY SOLUTIONS CORP., an Ohio corporation (“FES”), and ALLEGHENY ENERGY SUPPLY COMPANY, LLC, a Delaware limited liability company (“Allegheny”, and together with FES, the “Borrowers”), the banks and other financial institutions (the “Banks”) listed on the signature pages hereof, JPMorgan Chase Bank, N.A. (“JPMCB”), as Administrative Agent (the “Administrative Agent”) for the Lenders hereunder, the fronting banks party hereto from time to time and the swing line lenders party hereto from time to time.

PRELIMINARY STATEMENTS

(1) The Borrowers have requested that the Lenders establish a five-year unsecured revolving credit facility in the amount of $2,500,000,000 in favor of the Borrowers, all of which may be used for general corporate purposes and the entirety of which may be used for the issuance of Letters of Credit.

(2) Subject to the terms and conditions of this Agreement, the Lenders severally, to the extent of their respective Commitments (as defined herein), are willing to establish the requested revolving credit facility in favor of the Borrowers.

NOW, THEREFORE, in consideration of the premises, the parties hereto agree as follows:

ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01. Certain Defined Terms.

As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“Account Party” has the meaning set forth in Section 2.04(a).

“Additional Commitment Lender” has the meaning set forth in Section 2.19(d).

“Additional Lender” has the meaning set forth in Section 2.06(b).

“Administrative Agent” has the meaning set forth in the preamble hereto.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Advance” means a Pro-Rata Advance or a Swing Line Advance.

“Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person.

“Agreement” means this Credit Agreement, as amended, modified and supplemented from time to time.

“Allegheny” has the meaning set forth in the preamble hereto.

“Allegheny FERC Order” means the Order Accepting for Filing Market-Based Rate Tariff, and Granting Waivers and Blanket Authorizations issued by the FERC on September 30, 1999, in Docket Nos. ER99-4020-000, et al., as amended, extended, supplemented, replaced or renewed from time to time.

“Alternate Base Rate” means, for any period, a fluctuating interest rate per annum as shall be in effect from time to time, which rate per annum shall at all times be equal to the highest of (i) the rate of interest per annum announced publicly by JPMCB in New York, New York, from time to time, as its “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum (rounded upwards, if necessary, to the nearest 1/32 of 1%) appearing on Telerate Page 3750 (or any successor page) as displaying the London interbank offered rate for deposits in Dollars at approximately 11:00 a.m. (London time) such day for a term of one month plus 1%; provided, however, if more than one rate is specified on such service, the applicable rate shall be the arithmetic mean of all such rates plus 1%.

“Alternate Base Rate Advance” means an Alternate Base Rate Pro-Rata Advance or a Swing Line Advance.

“Alternate Base Rate Pro-Rata Advance” means a Pro-Rata Advance that bears interest as provided in Section 2.08(a).

“Anniversary Date” has the meaning set forth in Section 2.19(a).

“Applicable Law” means all applicable laws, statutes, treaties, rules, codes, ordinances, regulations, permits, certificates, orders, interpretations, licenses and permits of any Governmental Authority and judgments, decrees, injunctions, writs, orders or like action of any court, arbitrator or other judicial or quasi-judicial tribunal of competent jurisdiction (including those pertaining to health, safety or the environment or otherwise).

“Applicable Lending Office” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of an Alternate Base Rate Advance, and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Advance.

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“Applicable Margin” means, for any Alternate Base Rate Advance or any Eurodollar Rate Advance made to any Borrower, the interest rate per annum set forth in the relevant row of the table below, determined by reference to the Reference Ratings for such Borrower from time to time in effect:

LEVEL 6

Reference

LEVEL 2

LEVEL 3

LEVEL 4

LEVEL 5

Ratings

Reference

Reference

Reference

Reference

lower than

LEVEL 1

Ratings lower

Ratings of

Ratings lower

Ratings

BB+ by S&P

Reference

than Level 1

lower than

than Level 3

lower than

and Ba1 by

Ratings at

but at least

Level 2 but at

but at least

Level 4 but at

Moody’s, or

least A- by

BBB+ by

least BBB by

BBB- by S&P

least BB+ by

no

BASIS FOR

S&P or A3 by

S&P or Baa1

S&P or Baa2

or Baa3 by

S&P or Ba1

Reference

PRICING

Moody’s.

by Moody’s.

by Moody’s.

Moody’s.

by Moody’s.

Ratings.

Applicable Margin for Eurodollar Rate Advances

1.25

%

1.50

%

1.75

%

2.00

%

2.25

%

2.50

%

Applicable Margin for Alternate Base Rate Advances

0.25

%

0.50

%

0.75

%

1.00

%

1.25

%

1.50

%

For purposes of the foregoing, (i) if there is a difference of one level in Reference Ratings of S&P and Moody’s and the higher of such Reference Ratings falls in Level 1, Level 2, Level 3, Level 4 or Level 5, then the higher Reference Rating will be used to determine the pricing level and (ii) if there is a difference of more than one level in Reference Ratings of S&P and Moody’s, the Reference Rating that is one level above the lower of such Reference Ratings will be used to determine the pricing level, unless the lower of such Reference Ratings falls in Level 6, in which case the lower of such Reference Ratings will be used to determine the pricing level. If there exists only one Reference Rating, such Reference Rating will be used to determine the pricing level.

“Approval” means (i) with respect to FES, the FES FERC Order and (ii) with respect to Allegheny, the Allegheny FERC Order.

“Approved Fund” means any Fund that is administered or managed by (i) a Lender, (ii) an Affiliate of a Lender or (iii) an entity or an Affiliate of an entity that administers or manages a Lender.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee of such Lender, and accepted by the Administrative Agent, in substantially the form of Exhibit A hereto.

“Attributable Securitization Obligations” has the meaning set forth in the definition of “Permitted Securitization”.

“Authorized Officer” means, with respect to any notice, certificate or other communication to be delivered by any Borrower hereunder, the chief executive officer, president, chief financial officer, treasurer, assistant treasurer or controller of such Borrower, which officer shall have all necessary corporate or limited liability company authorization to deliver such notice, certificate or other communication.

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“Available Commitment” means, for each Lender, the excess of such Lender’s Commitment over such Lender’s Percentage of the Outstanding Credits. “Available Commitments” shall refer to the aggregate of the Lenders’ Available Commitments hereunder.

“Bankruptcy Code” means the Bankruptcy Reform Act of 1978, as amended from time to time, and any Federal law with respect to bankruptcy, insolvency, reorganization, liquidation, moratorium or similar laws affecting creditors’ rights generally.

“Bankruptcy Event” means, with respect to any Person, such Person has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee, administrator, custodian, assignee for the benefit of creditors or similar Person charged with the reorganization or liquidation of its business appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment, provided that a Bankruptcy Event shall not result solely by virtue of any ownership interest, or the acquisition of any ownership interest, in such Person by a Governmental Authority or instrumentality thereof, provided, further, that such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority or instrumentality) to reject, repudiate, disavow or disaffirm any contracts or agreements made by such Person.

“Banks” has the meaning set forth in the preamble hereto.

“Beneficiary” means any Person designated by an Account Party to whom a Fronting Bank is to make payment, or on whose order payment is to be made, under a Letter of Credit.

“Borrower” has the meaning set forth in the preamble hereto.

“Borrower Extension Notice Date” has the meaning set forth in Section 2.19(a).

“Borrower Sublimit” means: (i) with respect to FES, $1,500,000,000, and (ii) with respect to Allegheny, $1,000,000,000.

“Borrowing” means a Pro-Rata Borrowing or a Swing Line Borrowing.

“Business Day” means a day of the year on which banks are not required or authorized to close in New York City or Akron, Ohio and, if the applicable Business Day relates to any Eurodollar Rate Advances, a day on which dealings are carried on in the London interbank market.

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“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (i) the adoption or taking effect of any law, rule, regulation or treaty, (ii) any change (other than any change by way of imposition or increase of reserve requirements included in the Eurodollar Rate Reserve Percentage) in any law, rule, regulation or treaty or in the administration, interpretation or application thereof by any Governmental Authority or (iii) the making or issuance of any request, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided, however, the Dodd-Frank Wall Street Reform and Consumer Protection Act, and all requests, rules, guidelines and directives promulgated thereunder, and all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to have been introduced or adopted after the date of this Agreement, regardless of the date enacted or adopted.

“Change of Control” has the meaning set forth in Section 6.01(j).

“Code” means the United States Internal Revenue Code of 1986, as amended from time to time, and the applicable regulations thereunder.

“Commitment” means, as to any Lender, the amount set forth opposite such Lender’s name on Schedule I hereto or, if such Lender has entered into any Assignment and Assumption, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 8.08(c), as such amount may be reduced pursuant to Section 2.06(a) or increased pursuant to Section 2.06(b).

“Commitment Increase” has the meaning set forth in Section 2.06(b).

“Commodity Trading Obligations” means the obligations of any Person under any commodity swap agreement, commodity future agreement, commodity option agreement, commodity cap agreement, commodity floor agreement, commodity collar agreement, commodity hedge agreement, commodity forward contract or derivative transaction and any put, call or other agreement, arrangement or transaction, including natural gas, power, emissions forward contracts, renewable energy credits, or any combination of any such arrangements, agreements and/or transactions, employed in the ordinary course of such Person’s business, including such Person’s energy marketing, trading and asset optimization business. The term “commodity” shall include electric energy and/or capacity, transmission rights, coal, petroleum, natural gas, fuel transportation rights, emissions allowances, weather derivatives and related products and by-products and ancillary services.

“Communications” has the meaning set forth in Section 8.03(a).

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“Consolidated Debt” means, with respect to any Borrower at any date of determination the aggregate Indebtedness of such Borrower and its Consolidated Subsidiaries determined on a consolidated basis in accordance with GAAP, but shall not include (i) Nonrecourse Indebtedness of such Borrower and any of its Subsidiaries, (ii) obligations under leases that shall have been or should be, in accordance with GAAP, recorded as operating leases in respect of which such Borrower or any of its Consolidated Subsidiaries is liable as a lessee, (iii) the aggregate principal and/or face amount of Attributable Securitization Obligations of such Borrower and its Consolidated Subsidiaries and (iv) the aggregate principal amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Obligations not exceeding 15% of the Total Capitalization of such Borrower and its Consolidated Subsidiaries (determined, for purposes of such calculation, without regard to the amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Debt Obligations outstanding of such Borrower); provided that the amount of any mandatory principal amortization or defeasance of Trust Preferred Securities or Junior Subordinated Deferred Interest Debt Obligations prior to the Termination Date shall be included in this definition of Consolidated Debt.

“Consolidated Subsidiary” means, as to any Person, any Subsidiary of such Person the accounts of which are or are required to be consolidated with the accounts of such Person in accordance with GAAP.

“Controlled Group” means all members of a controlled group of corporations and all trades or businesses (whether or not incorporated) under common control that, together with any Borrower and its Subsidiaries, are treated as a single employer under Section 414(b), (c) or (m) or 414(o) of the Code.

“Convert”, “Conversion” and “Converted” each refers to a conversion of Pro-Rata Advances of one Type into Pro-Rata Advances of another Type or the selection of a new, or the renewal of the same, Interest Period for Eurodollar Rate Advances pursuant to Section 2.10 or 2.11.

“Credit Parties” has the meaning set forth in Section 8.15 hereto.

“Cross-Default Provision” has the meaning set forth in Section 5.03(f) hereto.

“Date of Issuance” means the date of issuance by a Fronting Bank of a Letter of Credit under this Agreement.

“Debt to Capitalization Ratio” means, for any Borrower, the ratio of Consolidated Debt of such Borrower to Total Capitalization of such Borrower.

“Defaulting Lender” means any Lender that (i) has failed, within three Business Days of the date required to be funded or paid, to (A) fund any portion of its Advances, (B) fund any portion of its participations in Letters of Credit or Swing Line Advances or (C) pay over to the Administrative Agent, any Fronting Bank or any Swing Line Lender any other amount required to be paid by it hereunder, unless, in the case of clause (A) or (B) above, such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that a condition precedent to funding (specifically identified and including the particular default, if any) has not been satisfied, (ii) has notified any Borrower or the Administrative Agent, any Fronting Bank or any Swing Line Lender in writing, or has made a public statement to the effect, that it does not

6

intend or expect to comply with any of its funding obligations under this Agreement (unless such writing or public statement indicates that such position is based on such Lender’s good faith determination that a condition precedent (specifically identified and including the particular default, if any) to funding a loan under this Agreement cannot be satisfied) or generally under other agreements in which it commits to extend credit, (iii) has failed, within three Business Days after written request by the Administrative Agent, any Fronting Bank or any Swing Line Lender, acting in good faith, to provide a certification in writing from an authorized officer of such Lender that it will comply with its obligations to fund prospective Advances and participations in then outstanding Letters of Credit and Swing Line Advances under this Agreement, provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (iii) upon the Administrative Agent’s, such Fronting Bank’s or such Swing Line Lender’s (as applicable) receipt of such certification in form and substance reasonably satisfactory to it and the Administrative Agent, or (iv) has become the subject of a Bankruptcy Event.

“Disclosure Documents” means (i) with respect to any Borrower that is required to file reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, such Borrower’s Annual Report on Form 10-K for the year ended December 31, 2010, Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 and Current Reports on Form 8-K filed in 2011 prior to the date hereof and (ii) with respect to any Borrower that is not required to file reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, (A) such Borrower’s consolidated balance sheets as of December 31, 2010, and the related consolidated statements of income, retained earnings and cash flows for the fiscal year then ended, certified by PricewaterhouseCoopers LLP or Deloitte & Touche LLP, as applicable, and unaudited consolidated balance sheets as of March 31, 2011 and related consolidated statements of income, retained earnings and cash flows for the three-month period then ended, with, in each case, any accompanying notes, all prepared in accordance with GAAP, and (B) the matters described in the portion of Schedule VI hereto applicable to such Borrower as indicated thereon.

“Dollars” and “$” each means lawful currency of the United States of America.

“Domestic Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Domestic Lending Office” opposite its name on Schedule I hereto or in the Assignment and Assumption pursuant to which it became a Lender, or such other office of such Lender as such Lender may from time to time specify to the Administrative Agent.

“Drawing” means a drawing by a Beneficiary under any Letter of Credit.

“Environmental Laws” means any federal, state or local laws, ordinances or codes, rules, orders, or regulations relating to pollution or protection of the environment, including, without limitation, laws relating to hazardous substances, laws relating to reclamation of land and waterways and laws relating to emissions, discharges, releases or threatened releases of pollutants, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes into the environment (including, without limitation, ambient air, surface water, ground water, land surface or subsurface strata) or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollution, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes.

7

“ERISA” means the Employee Retirement Income Security Act of 1974, and the regulations promulgated and rulings issued thereunder, each as amended, modified and in effect from time to time.

“Eurocurrency Liabilities” has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“Eurodollar Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Eurodollar Lending Office” opposite its name on Schedule I hereto or in the Assignment and Assumption pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify to the Administrative Agent.

“Eurodollar Rate” means, for the Interest Period for any Eurodollar Rate Advance made in connection with any Borrowing, the rate of interest per annum (rounded upward to the nearest 1/32 of 1%) appearing on Telerate Page 3750 (or any successor page) as the London interbank offered rate for deposits in Dollars at approximately 11:00 a.m. (London time) two Business Days before the first day of such Interest Period for a period equal to such Interest Period. If, for any reason, such rate is not available, the term “Eurodollar Rate” for such Interest Period shall mean an interest rate per annum equal to the average rate per annum (rounded upward to the nearest 1/32 of 1%) at which deposits in Dollars are offered by the Reference Banks to prime banks in the London interbank eurodollar market at 11:00 a.m. (London time) two Business Days before the first day of such Interest Period in an amount substantially equal to the Reference Banks’ respective Percentages of such Borrowing to be outstanding during such Interest Period and for a period equal to such Interest Period.

“Eurodollar Rate Advance” means an Advance that bears interest as provided in Section 2.08(b).

“Eurodollar Rate Reserve Percentage” of any Lender for the Interest Period for any Eurodollar Rate Advance means the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) for such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period.

“Event of Default” has the meaning set forth in Section 6.01.

8

“Exchange Act” means the Securities Exchange Act of 1934, and the regulations promulgated thereunder, in each case as amended and in effect from time to time.

“Excluded Taxes” means, with respect to any Recipient of any payment to be made by or on account of any obligation of any Borrower hereunder, (i) income or franchise taxes imposed on (or measured by) the Recipient’s net income by the United States, or by the jurisdiction under the laws of which such Recipient is organized or in which its principal office is located or, in the case of any Lender, in which its Applicable Lending Office is located, (ii) any branch profits taxes imposed by the United States or any similar tax imposed by any other jurisdiction in which such Recipient is located, and (iii) any withholding taxes that (A) are imposed on amounts payable to such Recipient at the time such Recipient becomes a Recipient under this Agreement or designates a new lending office, except in each case to the extent that amounts with respect to such taxes were payable either (i) to such Recipient’s assignor immediately before such Recipient became a Recipient under this Agreement, or (ii) to such Recipient immediately before it designated a new lending office, (B) are attributable to such Recipient’s failure to comply with Section 2.16(e), or (C) are imposed as a result of a failure by such Recipient to satisfy the conditions for avoiding withholding under FATCA.

“Existing Facilities” means the credit facilities listed on Schedule V hereto.

“Existing Termination Date” has the meaning set forth in Section 2.19(a).

“Expiration Date” means, with respect to a Letter of Credit, its stated expiration date.

“Extension of Credit” means the making of any Advance or the issuance, extension or renewal, or any amendment that increases the Stated Amount, of a Letter of Credit.

“FATCA” means Sections 1471 through 1474 of the Code as of the date of this Agreement and any current or future regulations or official interpretations thereof.

“FE” means FirstEnergy Corp., an Ohio corporation.

“Federal Funds Rate” means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upward to the nearest whole multiple of 1/100 of 1% per annum, if such average is not such a multiple) of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

9

“Fee Letters” means (i) the letter agreement, dated as of April 27, 2011, among the Borrowers and JPMCB, (ii) the letter agreement, dated as of April 27, 2011, among the Borrowers, JPMCB, J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Bank of America, N.A., Barclays Bank PLC, The Royal Bank of Scotland plc and RBS Securities Inc., and (iii) the letter agreement, dated as of May 2, 2011, among the Borrowers, Citigroup Global Markets Inc., KeyBank National Association, The Bank of Nova Scotia, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Bank, National Association and Wells Fargo Securities, LLC, in each case, as amended, modified or supplemented from time to time.

“FERC” means the Federal Energy Regulatory Commission or successor organization.

“FES” has the meaning set forth in the preamble hereto.

“FES FERC Order” means the Order Accepting for Filing Market-Based Rate Tariff, and Granting Waivers and Blanket Authorizations issued by the FERC on January 24, 2001, in Docket Nos. ER01-103-000, et al., as amended, extended, supplemented, replaced or renewed from time to time.

“FES’s Mark-to-Market Obligations” means any of FES’s mark-to-market obligations under master standard service offer supply agreements or similar agreements between FES and any of FE’s regulated utility subsidiaries entered into from time to time as a result of FES’s participation in state public utility commission-approved competitive bid processes to provide retail electric generation supply.

“FES-FGC Guaranty” means the Guaranty, dated as of March 26, 2007, of FES with respect to certain indebtedness of FGC.

“FES-NGC Guaranty” means the Guaranty, dated as of March 26, 2007, of FES with respect to certain indebtedness of NGC.

“FGC” means FirstEnergy Generation Corp., an Ohio corporation.

“FGC-FES Guaranty” means the Guaranty, dated as of March 26, 2007, of FGC with respect to certain indebtedness of FES

“First Mortgage Bonds” means the bonds, notes or similar instruments issued under any FMB Mortgage.

“FMB Mortgage” means (i) with respect to FGC, the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008, between FGC and The Bank of New York Trust Company, N.A., as trustee, as amended, restated, supplemented or otherwise modified from time to time (except as expressly provided otherwise herein), together with any supplemental indentures issued pursuant thereto, (ii) with respect to NGC, the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009, between NGC and The Bank of New York Mellon Trust Company, N.A., as trustee, as amended, restated, supplemented or otherwise modified from time to time (except as expressly provided otherwise herein), and (iii), with respect to Allegheny, a first mortgage indenture pursuant to which Allegheny may issue bonds, notes or similar instruments secured by a lien on all or substantially all of its fixed assets, in each case of clauses (i), (ii) and (ii), together with any supplemental indentures issued pursuant thereto.

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“Foreign Lender” means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrowers are resident for tax purposes. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Fraction” means, for any Borrower at any time, a fraction, the numerator of which shall be the Borrower Sublimit of such Borrower at such time, and the denominator of which shall be the sum of the Borrower Sublimits of all Borrowers at such time.

“Fronting Bank” means each Lender identified as a “Fronting Bank” on Schedule II and any other Lender (in each case, acting directly or through an Affiliate) that delivers an instrument in form and substance satisfactory to the Borrowers and the Administrative Agent whereby such other Lender (or its Affiliate) agrees to act as “Fronting Bank” hereunder and that specifies the maximum aggregate Stated Amount of Letters of Credit that such other Lender (or its Affiliates) will agree to issue hereunder.

“Fronting Bank Fee Letter” has the meaning set forth in Section 3.01(b).

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” means generally accepted accounting principles in the United States in effect from time to time.

“Genco” means each of FGC and NGC.

“Genco Guarantees” means the FES-FGC Guaranty, the FES-NGC Guaranty, the FGC-FES Guaranty and the NGC-FES Guaranty.

“Governmental Action” means all authorizations, consents, approvals, waivers, exceptions, variances, orders, licenses, exemptions, publications, filings, notices to and declarations of or with any Governmental Authority (other than requirements the failure to comply with which will not affect the validity or enforceability of any Loan Document or have a material adverse effect on the transactions contemplated by any Loan Document or any material rights, power or remedy of any Person thereunder or any other action in respect of any Governmental Authority).

“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank) and any group or body charged with setting financial accounting or regulatory capital rules or standards (including, without limitation, the Financial Accounting Standards Board, the Bank for International Settlements or the Basel Committee on Banking Supervision or any successor or similar authority to any of the foregoing).

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“Hedging Obligations” mean, with respect to any Person, the obligations of such Person under any interest rate or currency swap agreement, interest rate or currency future agreement, interest rate collar agreement, interest rate or currency hedge agreement, and any put, call or other agreement or arrangement designed to protect such Person against fluctuations in interest rates or currency exchange rates.

“Hostile Acquisition” means any Target Acquisition (as defined below) involving a tender offer or proxy contest that has not been recommended or approved by the board of directors (or similar governing body) of the Person that is the subject of such Target Acquisition. As used in this definition, the term “Target Acquisition” means any transaction, or any series of related transactions, by which any Person directly or indirectly (i) acquires all or substantially all of the assets or ongoing business of any other Person, whether through purchase of assets, merger or otherwise, (ii) acquires (in one transaction or as the most recent transaction in a series of transactions) control of at least a majority in ordinary voting power of the securities of any such Person that have ordinary voting power for the election of directors or (iii) otherwise acquires control of more than a 50% ownership interest in any such Person.

“Increasing Lender” has the meaning set forth in Section 2.06(b).

“Indebtedness” of any Person means at any date, without duplication, (i) all obligations of such Person for borrowed money, or with respect to deposits or advances of any kind, or for the deferred purchase price of property or services other than trade accounts payable, (ii) all obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (iii) all obligations of such Person upon which interest charges are customarily paid, (iv) all obligations under leases that shall have been or should be, in accordance with GAAP, recorded as capital leases in respect of which such Person is liable as lessee, (v) withdrawal liability incurred under ERISA by such Person or any of its affiliates to any Multiemployer Plan, (vi) reimbursement obligations of such Person (whether contingent or otherwise) in respect of letters of credit, bankers acceptances, surety or other bonds and similar instruments, (vii) all Indebtedness of others secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person and (viii) obligations of such Person under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to above. For the avoidance of doubt, “Indebtedness” shall include, as of any date of determination with respect to FES, the aggregate obligations of the Gencos under outstanding First Mortgage Bonds issued pursuant to their respective FMB Mortgages to guarantee or otherwise support FES’s Market-to-Market Obligations, which obligations shall be deemed to be limited in amount to the aggregate amount of FES’s Mark-to-Market Obligations for which Mark-to-Market Guarantees are in effect as of such date less the amount of cash or letter of credit collateral securing or otherwise supporting FES’s Mark-to-Market Obligations as of such date.

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“Indemnified Persons” has the meaning set forth in Section 8.05(c) hereto.

“Indemnified Taxes” means all Taxes (including Other Taxes) other than Excluded Taxes.

“Interest Period” means, for each Eurodollar Rate Advance made to any Borrower as part of the same Borrowing, the period commencing on the date of such Eurodollar Rate Advance or the date of the Conversion of any Pro-Rata Advance into such Eurodollar Rate Advance and ending on the last day of the period selected by such Borrower pursuant to the provisions below and, thereafter in the case of Pro-Rata Advances, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by such Borrower pursuant to the provisions below. The duration of each such Interest Period shall be, in the case of any Eurodollar Rate Advance, one week or one, two, three or six months, in each case, as the applicable Borrower may select by notice to the Administrative Agent pursuant to Section 2.02(a) or Section 2.11(a); provided, however, that:

(i) no Borrower may select any Interest Period that ends after the latest Termination Date;

(ii) Interest Periods commencing on the same date for Advances made as part of the same Borrowing shall be of the same duration;

(iii) no more than ten different Interest Periods shall apply to outstanding Eurodollar Rate Advances on any date of determination; and

(iv) whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, that if such extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day.

“ISDA Master Agreement” means the printed form of the 1992 ISDA Master Agreement (Multicurrency — Cross Border) or the 2002 ISDA Master Agreement (Multicurrency — Cross Border), as applicable, including any Schedule and Credit Support Annex thereto, as published by the International Swaps and Derivatives Association, Inc.

“JPMCB” has the meaning set forth in the preamble hereto.

“Junior Subordinated Deferred Interest Debt Obligations” means subordinated deferrable interest debt obligations of any Borrower or any of its Subsidiaries (i) for which the maturity date is subsequent to the Termination Date and (ii) that are fully subordinated in right of payment to the Indebtedness hereunder.

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“L/C Commitment Amount” means $2,500,000,000 as the same may be reduced permanently from time to time pursuant to Section 2.06.

“L/C Fronting Bank Commitment” means, with respect to any Fronting Bank, the aggregate Stated Amount of all Letters of Credit that such Fronting Bank agrees to issue, as modified from time to time pursuant to an agreement signed by such Fronting Bank. With respect to each Lender that is a Fronting Bank on the date hereof, such Fronting Bank’s L/C Fronting Bank Commitment shall equal such Fronting Bank’s “L/C Fronting Bank Commitment” listed on Schedule II, and (ii) with respect to any Lender that becomes a Fronting Bank after the date hereof, such Lender’s L/C Fronting Bank Commitment shall equal the amount agreed upon between the Borrowers and such Lender at the time that such Lender becomes a Fronting Bank, in each case as such L/C Fronting Bank Commitment may be modified in accordance with the terms of this Agreement.

“Lender Extension Notice Date” has the meaning set forth in Section 2.19(b).

“Lenders” means the Banks listed on the signature pages hereof and each assignee of a Bank or another Lender that shall become a party hereto pursuant to Section 8.08 and, as the context requires, includes the Swing Line Lenders.

“Letter of Credit” has the meaning set forth in Section 2.04(a).

“Letter of Credit Cash Cover” has the meaning set forth in Section 6.01.

“Letter of Credit Request” has the meaning set forth in Section 2.04(c).

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset. For the purposes of this Agreement, a Person or any of its Subsidiaries shall be deemed to own, subject to a Lien, any asset that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such asset.

“Loan Documents” means this Agreement, any Note, the Fee Letters and the Fronting Bank Fee Letters.

“Majority Lenders” means, at any time prior to the Termination Date, Lenders having in the aggregate more than 50% of the Commitments (without giving effect to any termination in whole of the Commitments pursuant to Section 6.01) and at any time on or after the Termination Date, Lenders having more than 50% of the then aggregate Outstanding Credits of the Lenders; provided, that for purposes hereof, no Borrower, nor any of its Affiliates, if a Lender, shall be included in (i) the Lenders having such amount of the Commitments or the Advances or (ii) determining the total amount of the Commitments or the Outstanding Credits.

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“Margin Stock” has the meaning assigned to that term in Regulation U issued by the Board of Governors of the Federal Reserve System, and as amended and in effect from time to time.

“Mark-to-Market Guarantees” means guarantees by a Genco supporting FES’s Mark-to-Market Obligations, which guarantees may be secured by First Mortgage Bonds.

“Material Adverse Effect” means, with respect to any Borrower, (i) any material adverse effect on the business, property, operations or financial condition of such Borrower and its Consolidated Subsidiaries, taken as a whole, or (ii) any material adverse effect on the validity or enforceability against such Borrower of this Agreement or any Note.

“Money Pool” has the meaning set forth in Section 5.01(i).

“Moody’s” means Moody’s Investors Service, Inc.

“Multiemployer Plan” means a “multiemployer plan” as defined in Section 4001(a)(3) of ERISA to which any Borrower or any member of the Controlled Group is or may reasonably be expected to have an obligation to make, contributions, or with respect to which any Borrower may reasonably be expected to incur liability.

“New Fronting Bank” has the meaning set forth in Section 2.04(r).

“NGC-FES Guaranty” means the Guaranty, dated as of March 26, 2007, of NGC with respect to certain indebtedness of FES.

“NGC” means FirstEnergy Nuclear Generation Corp., an Ohio corporation.

“Nonconsenting Lender” has the meaning set forth in Section 2.19(b).

“Nonrecourse Indebtedness” means, with respect to any Borrower and its Subsidiaries, (i) any Indebtedness that finances the acquisition, development, construction or improvement of an asset in respect of which the Person to which such Indebtedness is owed has no recourse whatsoever to such Borrower or any of its Affiliates and (ii) any Indebtedness existing on the date of this Agreement that finances the ownership or operation of an asset in respect of which the Person to which such Indebtedness is owed has no recourse whatsoever to such Borrower or any of its Affiliates, in each case of clauses (i) and (ii), other than:

(A) recourse to the named obligor with respect to such Indebtedness (the “Debtor”) for amounts limited to the cash flow or net cash flow (other than historic cash flow) from the asset; and

(B) recourse to the Debtor for the purpose only of enabling amounts to be claimed in respect of such Indebtedness in an enforcement of any security interest or lien given by the Debtor over the asset or the income, cash flow or other proceeds deriving from the asset (or given by any shareholder or the like in the Debtor over its shares or like interest in the capital of the Debtor) to secure the Indebtedness, but only if the extent of the recourse to the Debtor is limited solely to the amount of any recoveries made on any such enforcement; and

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(C) recourse to the Debtor generally or indirectly to any Affiliate of the Debtor, under any form of assurance, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for a breach of an obligation (other than a payment obligation or an obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the Person against which such recourse is available.

“Note” means any promissory note issued at the request of a Lender pursuant to Section 2.18 in the form of Exhibit B hereto.

“Notice of Pro-Rata Borrowing” means a notice of a Pro-Rata Borrowing pursuant to Section 2.02(a), which shall be substantially in the form of Exhibit C.

“Notice of Swing Line Borrowing” means a notice of a Swing Line Borrowing pursuant to Section 2.03 which, if in writing, shall be substantially in the form of Exhibit D.

“OECD” means the Organization for Economic Cooperation and Development.

“Organizational Documents” means, as applicable to any Person, the charter, code of regulations, articles of incorporation, by-laws, certificate of formation, operating agreement, certificate of partnership, limited liability company agreement, operating agreement, partnership agreement, certificate of limited partnership, limited partnership agreement or other constitutive documents of such Person.

“Original Fronting Banks” has the meaning set forth in Section 2.04(r).

“Other Taxes” means any and all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made hereunder or under any other Loan Document or from the execution, delivery, performance or enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, this Agreement or any other Loan Document.

“Outstanding Credits” means, on any date of determination, an amount equal to (i) the aggregate principal amount of all Advances outstanding on such date plus (ii) the aggregate undrawn amount of all issued Letters of Credit outstanding on such date plus (iii) the aggregate amount of Reimbursement Obligations outstanding on such date (excluding Reimbursement Obligations that, on such date of determination, are repaid with the proceeds of Advances made in accordance with Sections 2.04 (f) and (g), to the extent the principal amount of such Advances is included in the determination of the aggregate principal amount of all outstanding Advances as provided in clause (i) of this definition). The Outstanding Credits of a Lender on any date of determination shall be an amount equal to the outstanding Advances made by such Lender plus the amount of such Lender’s participation interest in outstanding Letters of Credit, Reimbursement Obligations and Swing Line Advances included in the definition of “Outstanding Credits”.

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“Parent” means, with respect to any Lender, any Person as to which such Lender is, directly or indirectly, a subsidiary.

“Participant” has the meaning set forth in Section 8.08(d).

“Participant Register” has the meaning set forth in Section 8.08(d).

“Patriot Act” means the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001), as in effect from time to time.

“Payment Date” means the date on which payment of a Drawing is made by a Fronting Bank.

“PBGC” means the Pension Benefit Guaranty Corporation and any entity succeeding to any or all of its functions under ERISA.

“Percentage” means, in respect of any Lender on any date of determination, the percentage obtained by dividing such Lender’s Commitment on such day by the total of the Commitments on such day, and multiplying the quotient so obtained by 100%.

“Permitted Obligations” mean (i) nonspeculative Hedging Obligations of any Person and its subsidiaries arising in the ordinary course of business and in accordance with such Person’s established risk management policies that are designed to protect such Person against, among other things, fluctuations in interest rates or currency exchange rates and which in the case of agreements relating to interest rates shall have a notional amount no greater than the payments due with respect to the applicable obligations being hedged and (ii) Commodity Trading Obligations. For the avoidance of doubt, such transactions shall be considered nonspeculative if undertaken in conformance with FE’s Corporate Risk Management Policy then in effect, as approved by FE’s Audit Committee, together with the Approved Business Unit Risk Management Policies referenced thereunder, including, but not limited to, the FES Commodity Portfolio Risk Management Policy.

“Permitted Securitization” means, for any Borrower and its Subsidiaries, any sale, assignment, conveyance, grant and/or contribution, or series of related sales, assignments, conveyances, grants and/or contributions, by such Borrower or any of its Subsidiaries of Receivables (or purported sale, assignment, conveyance, grant and/or contribution) to a trust, corporation or other entity, where the purchase of such Receivables may be funded or exchanged in whole or in part by the incurrence or issuance by the applicable Securitization SPV, if any, of Indebtedness or securities (such Indebtedness and securities being “Attributable Securitization Obligations”) that are to be secured by or otherwise satisfied by payments from, or that represent interests in, the

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cash flow derived primarily from such Receivables (provided, however, that “Indebtedness” as used in this definition shall not include Indebtedness incurred by a Securitization SPV owed to any Borrower or any of its Subsidiaries, which Indebtedness represents all or a portion of the purchase price or other consideration paid by such Securitization SPV for such receivables or interests therein), where (i) any representation, warranty, covenant, recourse, repurchase, hold harmless, indemnity or similar obligations of such Borrower or any of its Subsidiaries, as applicable, in respect of Receivables sold, assigned, conveyed, granted or contributed, or payments made in respect thereof, are customary for transactions of this type, and do not prevent the characterization of the transaction as a true sale under applicable laws (including debtor relief laws) and (ii) any representation, warranty, covenant, recourse, repurchase, hold harmless, indemnity or similar obligations of any Securitization SPV in respect of Receivables sold, assigned, conveyed, granted or contributed or payments made in respect thereof, are customary for transactions of this type.

“Person” means an individual, partnership, corporation (including a business trust), limited liability company, joint stock company, trust, unincorporated association, joint venture or other entity, or a government or any political subdivision or agency thereof.

“Plan” means, at any time, an “employee pension benefit plan” (as defined in Section 3(2) of ERISA), other than a Multiemployer Plan, that is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 or 430 of the Code, (i) that is (A) maintained by or contributed to by (or to which there is or may be an obligation to contribute to by) any Borrower or any member of the Controlled Group for employees of any Borrower or a member of the Controlled Group, or (B) maintained pursuant to a collective bargaining agreement or any other arrangement under which more than one employer makes contributions, and (ii) each such plan as to which any Borrower or a member of the Controlled Group has within the preceding five plan years maintained, contributed to or had an obligation to contribute to.

“Platform” has the meaning set forth in Section 8.03(b).

“Pro-Rata Advance” means an advance by a Lender to any Borrower as part of a Pro-Rata Borrowing pursuant to Section 2.01 and refers to an Alternate Base Rate Pro-Rata Advance or a Eurodollar Rate Advance, subject to Conversion pursuant to Section 2.10 or 2.11.

“Pro-Rata Borrowing” means a borrowing consisting of simultaneous Pro-Rata Advances of the same Type made by each of the Lenders pursuant to Section 2.01 or Converted pursuant to Section 2.10 or 2.11.

“PUCO” means The Public Utilities Commission of Ohio.

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“Receivables” means any accounts receivable, payment intangibles, notes receivable, rights to receive future payments and related rights (whether now existing or arising or acquired in the future, whether constituting accounts, chattel paper, instruments, general intangibles or otherwise, and including the right to payment of any interest or finance charges), including financial transmission rights (“FTRs”) or any other rights to payment from PJM Interconnection LLC or another regional transmission authority of the Borrower or any of its Subsidiaries, and any supporting obligations and other financial assets related thereto (including all collateral securing such accounts receivables, FTRs or other assets, contracts and contract rights, all guarantees with respect thereto, and all proceeds thereof) that are transferred, or in respect of which security interests are granted in one or more transactions that are customary for asset securitizations of such Receivables.

“Recipient” means, as applicable, (i) the Administrative Agent, (ii) any Lender, (iii) any Fronting Bank and (iv) any Swing Line Lender.

“Reference Banks” means JPMCB and any Lender as may be selected from time to time to act as a replacement or additional Reference Bank hereunder by the Administrative Agent.

“Reference Ratings” means, with respect to any Borrower, the ratings assigned by S&P and Moody’s to the senior unsecured non-credit enhanced debt of such Borrower; provided that, if there is no such rating, “Reference Ratings” shall mean the ratings that are one level below the ratings assigned by S&P and Moody’s to the senior secured debt of such Borrower.

“Register” has the meaning set forth in Section 8.08(c).

“Reimbursement Obligation” means the obligation of each Borrower to reimburse a Fronting Bank for any Drawing paid by such Fronting Bank pursuant to Section 2.04(g).

“Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

“Required Reimbursement Date” has the meaning set forth in Section 2.04(f)(i).

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc.

“SEC” means the United States Securities and Exchange Commission.

“Securitization SPV” means any trust, partnership or other Person established by a Borrower or a Subsidiary of such Borrower to implement a Permitted Securitization.

“Significant Subsidiaries” means (i) with respect to FES, each of FGC and NGC, and (ii) with respect to either Borrower, any other significant subsidiary (as such term is defined in Regulation S-X of the SEC (17 C.F.R. §210.1-02(w)), or any successor provision) of such Borrower (excluding Securitization SPVs).

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“Specified Date” has the meaning set forth in Section 2.19(c).

“Stated Amount” means the maximum amount available to be drawn by a Beneficiary under a Letter of Credit.

“Subsidiary” means, with respect to any Person, any corporation or other entity of which securities or other ownership interests having ordinary voting power to elect a majority of the Board of Directors or other persons performing similar functions are at the time directly or indirectly owned by such a Person, or one or more Subsidiaries, or by such Person and one or more of its Subsidiaries.

“Swing Line Advance” means an Advance made by a Swing Line Lender to any Borrower as part of a Swing Line Borrowing pursuant to Section 2.03.

“Swing Line Borrowing” means a borrowing consisting of a Swing Line Advance made by a Swing Line Lender pursuant to Section 2.03.

“Swing Line Commitment” means, with respect to any Swing Line Lender, the aggregate amount of Swing Line Advances that such Swing Line Lender agrees to make, as modified from time to time pursuant to an agreement signed by such Swing Line Lender. With respect to each Lender that is a Swing Line Lender on the date hereof, such Swing Line Lender’s Swing Line Commitment shall equal the “Swing Line Commitment” listed for such Swing Line Lender on Schedule III and, with respect to any Lender that becomes a Swing Line Lender after the date hereof, such Lender’s Swing Line Commitment shall equal the amount agreed upon between the Borrowers and such Lenders at the time such Lender becomes a Swing Line Lender.

“Swing Line Lender” means each of the Lenders identified as a “Swing Line Lender” on Schedule III and any other Lender or Affiliate thereof that may be appointed from time to time by the Borrowers to provide Swing Line Advances under this Agreement, that is reasonably acceptable to the Administrative Agent and that accepts such appointment.

“Swing Line Sublimit” means an amount equal to the lesser of (i) $250,000,000 and (ii) the aggregate Commitments. The Swing Line Sublimit is part of, and not in addition to, the aggregate Commitments.

“Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, assessments, fees, charges or withholdings imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“Termination Date” means June 17, 2016, subject, for certain Lenders, to the extension described in Section 2.19 hereof, or, in any case, the earlier date of termination in whole of the Commitments pursuant to Section 2.06 or Section 6.01 hereof.

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“Termination Event” means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations), or (ii) the withdrawal of any member of the Controlled Group from a Plan during a plan year in which it was a “substantial employer” as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under Section 4041 or 4042 of ERISA, or (iv) the institution of proceedings to terminate a Plan by the PBGC, or (v) any other event or condition that might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment by a court of competent jurisdiction of a trustee to administer, any Plan.

“Total Capitalization” means, with respect to any Borrower at any date of determination the sum, without duplication, of (i) Consolidated Debt of such Borrower, (ii) the capital stock (but excluding treasury stock and capital stock subscribed and unissued) and other equity accounts (including retained earnings and paid in capital but excluding accumulated other comprehensive income and loss) of such Borrower and its Consolidated Subsidiaries, (iii) consolidated equity of the preference stockholders of such Borrower and its Consolidated Subsidiaries, and (iv) the aggregate principal amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Debt Obligations of such Borrower and its Consolidated Subsidiaries.

“Trust Preferred Securities” means any securities, however denominated, (i) issued by any Borrower or any Consolidated Subsidiary of any Borrower, (ii) that are not subject to mandatory redemption or the underlying securities, if any, of which are not subject to mandatory redemption, (iii) that are perpetual or mature no less than 30 years from the date of issuance, (iv) the indebtedness issued in connection with which, including any guaranty, is subordinate in right of payment to the unsecured and unsubordinated indebtedness of the issuer of such indebtedness or guaranty, and (v) the terms of which permit the deferral of the payment of interest or distributions thereon to a date occurring after the Termination Date.

“Type” means the designation of a Borrowing or an Advance as a Eurodollar Rate Borrowing or Advance or as an Alternate Base Rate Borrowing or Advance.

“Unmatured Default” means any event that, with the giving of notice or the passage of time, or both, would constitute an Event of Default.

“U.S. Person” means any Person that is a “United States person” as defined in Section 7701(a)(30) of the Code.

“U.S. Tax Compliance Certificate” has the meaning set forth in Section 2.16(e)(ii)(C).

SECTION 1.02. Computation of Time Periods.

In this Agreement in the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each means “to but excluding”.

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SECTION 1.03. Accounting Terms.

All accounting terms not specifically defined herein shall be construed in accordance with GAAP consistent with those applied in the preparation of the financial statements referred to in Section 4.01(g).

SECTION 1.04. Terms Generally.

Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise, (i) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, amended and restated, supplemented or otherwise modified (subject to any restrictions on such amendments, restatements, supplements or modifications set forth herein), (ii) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (iii) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provisions hereof, (iv) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement, and (v) the definitions of terms herein shall apply equally to the singular and plural forms of the terms defined.

ARTICLE II
AMOUNTS AND TERMS OF THE ADVANCES AND LETTERS OF CREDIT

SECTION 2.01. The Pro-Rata Advances.

Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Pro-Rata Advances to each Borrower in Dollars only from time to time on any Business Day during the period from the date hereof until the Termination Date in an aggregate amount not to exceed at any time outstanding the Available Commitment of such Lender. Each Pro-Rata Borrowing shall be in an aggregate amount not less than $5,000,000 or an integral multiple of $1,000,000 in excess thereof and shall consist of Advances of the same Type and, in the case of Eurodollar Rate Advances, having the same Interest Period made or Converted on the same day by the Lenders ratably according to their respective Commitments. Within the limits of each Lender’s Available Commitment, and subject to the conditions set forth in Article III and the other terms and conditions hereof, each Borrower may from time to time borrow, prepay pursuant to Section 2.12 and reborrow under this Section 2.01; provided, that in no case shall any Lender be required to make a Pro-Rata Advance to a Borrower hereunder if (i) the amount of such Pro-Rata Advance would exceed such Lender’s Available Commitment, (ii) the making of such Pro-Rata Advance, together with the making of the other Pro-Rata Advances constituting part of the same Pro-Rata Borrowing, would cause the total amount of all Outstanding Credits to exceed the aggregate amount of the Commitments or (iii) the amount of such Pro-Rata Advance, together with all other Outstanding Credits for the account of such Borrower, would exceed such Borrower’s Borrower Sublimit.

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SECTION 2.02. Making the Pro-Rata Advances.

(a) Each Pro-Rata Borrowing shall be made on notice, given (i) in the case of a Pro-Rata Borrowing comprising Eurodollar Rate Advances, not later than 11:00 a.m. (New York time) on the third Business Day prior to the date of the proposed Borrowing, and (ii) in the case of a Pro-Rata Borrowing comprising Alternate Base Rate Pro-Rata Advances, not later than 11:00 a.m. (New York time) on the date of the proposed Pro-Rata Borrowing, by any Borrower to the Administrative Agent, which shall give to each Lender prompt notice thereof. Each such Notice of Pro-Rata Borrowing by a Borrower shall be by telecopier, in substantially the form of Exhibit C hereto, specifying therein the requested (A) date of such Pro-Rata Borrowing, (B) Type of Pro-Rata Advances to be made in connection with such Pro-Rata Borrowing, (C) aggregate amount of such Pro-Rata Borrowing, (D) in the case of a Pro-Rata Borrowing comprising Eurodollar Rate Advances, the initial Interest Period for each such Pro-Rata Advance, which Pro-Rata Borrowing shall be subject to the limitations stated in the definition of “Interest Period” in Section 1.01, and (E) the identity of the Borrower requesting such Pro-Rata Borrowing. Each Borrower may request that more than one Borrowing be made on any date. Each Lender shall, before 1:00 p.m. (New York time) on the date of such Pro-Rata Borrowing, make available for the account of its Applicable Lending Office to the Administrative Agent at its address referred to in Section 8.02, in same day funds, such Lender’s Percentage of such Pro-Rata Borrowing. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Administrative Agent will make such funds available to such Borrower at the Administrative Agent’s aforesaid address.

(b) Each Notice of Pro-Rata Borrowing delivered by any Borrower shall be irrevocable and binding on such Borrower. In the case of any Notice of Pro-Rata Borrowing delivered by any Borrower requesting Eurodollar Rate Advances, such Borrower shall indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure by such Borrower to fulfill on or before the date specified in such Notice of Pro-Rata Borrowing the applicable conditions set forth in Article III, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by such Lender to fund the Pro-Rata Advance to be made by such Lender as part of such Borrowing when such Pro-Rata Advance, as a result of such failure, is not made on such date.

(c) Unless the Administrative Agent shall have received written notice via facsimile transmission from a Lender prior to (A) 5:00 p.m. (New York time) one Business Day prior to the date of a Pro-Rata Borrowing comprising Eurodollar Rate Advances or (B) 12:00 noon (New York time) on the date of a Pro-Rata Borrowing comprising Alternate Base Rate Pro-Rata Advances that such Lender will not make available to the Administrative Agent such Lender’s Percentage of such Pro-Rata Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of such Pro-Rata Borrowing in accordance with subsection (a) of this Section 2.02 and the Administrative Agent may, in reliance upon such assumption, make available to the applicable Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Percentage of such Pro-Rata Borrowing available to the Administrative Agent, such Lender and such Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to such Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of such Borrower, the interest rate applicable at the time to Pro-Rata Advances made in connection with such Pro-Rata Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Pro-Rata Advance as part of such Pro-Rata Borrowing for purposes of this Agreement.

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(d) The failure of any Lender to make the Pro-Rata Advance to be made by it as part of any Pro-Rata Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Pro-Rata Advance on the date of such Pro-Rata Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Pro-Rata Advance to be made by such other Lender on the date of any Borrowing.

SECTION 2.03. Swing Line Advances.

(a) The Swing Line. Subject to the terms and conditions set forth herein, each Swing Line Lender agrees to make Swing Line Advances to any Borrower in Dollars only from time to time on any Business Day during the period from the date hereof until the Termination Date in an aggregate amount not to exceed at any time the amount of such Swing Line Lender’s Swing Line Commitment; provided, however, no Swing Line Lender shall be required to make a Swing Line Advance hereunder if (i) the amount of such Swing Line Advance, together with the aggregate principal amount of all other Swing Line Advances outstanding would exceed the Swing Line Sublimit, (ii) the making of such Swing Line Advance, together with the making of the other Swing Line Advances constituting part of the same Swing Line Borrowing, would cause the total amount of all Outstanding Credits to exceed the aggregate amount of the Commitments or (iii) the amount of such Swing Line Advance would exceed such Borrower’s Borrower Sublimit. Within the foregoing limits, and subject to the other terms and conditions hereof, each Borrower may borrow under this Section 2.03, prepay under Section 2.12, and reborrow under this Section 2.03. Immediately upon the making of a Swing Line Advance, each Lender shall be deemed to, and hereby irrevocably and unconditionally agrees to, purchase from the applicable Swing Line Lender a risk participation in such Swing Line Advance in an amount equal to such Lender’s Percentage of the amount of such Swing Line Advance. No more than five Swing Line Advances may be outstanding hereunder at any time.

(b) Borrowing Procedures. Each Swing Line Borrowing shall be made upon any Borrower’s irrevocable notice to the applicable Swing Line Lender and the Administrative Agent, which may be given by telephone. Each such notice must be received by the applicable Swing Line Lender and the Administrative Agent not later than 11:00 a.m. (New York time) on the date of the proposed Swing Line Borrowing, or at such later time as a Swing Line Lender may agree, and shall specify (i) the date of such Swing Line Borrowing, (ii) the amount of such Swing Line Borrowing, which shall be not less than $1,000,000 or an integral multiple of $1,000,000 in excess thereof, and (iii) the identity of the Borrower requesting such Swing Line Borrowing. Each such telephonic notice must be confirmed promptly by delivery to the relevant Swing Line Lender and the Administrative Agent of a written Notice of

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Swing Line Borrowing, appropriately completed and signed by such Borrower. Promptly after receipt by such Swing Line Lender of any telephonic Notice of Swing Line Borrowing, such Swing Line Lender will confirm with the Administrative Agent (by telephone or in writing) that the Administrative Agent has also received such Notice of Swing Line Borrowing and, if not, such Swing Line Lender will notify the Administrative Agent (by telephone or in writing) of the contents thereof. Unless such Swing Line Lender has received notice (by telephone or in writing) from the Administrative Agent (including at the request of any Lender) prior to 12:00 p.m. (New York time) on the date of the proposed Swing Line Borrowing (A) directing such Swing Line Lender not to make such Swing Line Advance as a result of the limitations set forth in the first sentence of Section 2.03(a) or (B) that one or more of the applicable conditions specified in Article III is not then satisfied, then, subject to the terms and conditions hereof, such Swing Line Lender will, not later than 1:00 p.m. on the borrowing date specified in such Notice of Swing Line Borrowing, make the amount of its Swing Line Advance available to the applicable Borrower at its office by crediting the account of such Borrower on the books of such Swing Line Lender in immediately available funds.

(c) Refinancing of Swing Line Advances.

(i) Each Swing Line Lender at any time in its sole and absolute discretion may request, on behalf of any Borrower (each of which hereby irrevocably authorizes each Swing Line Lender to so request on its behalf), that each Lender make an Alternate Base Rate Pro-Rata Advance in an amount equal to such Lender’s Percentage of the amount of Swing Line Advances made by such Swing Line Lender then outstanding to such Borrower. Such request shall be made in writing (which written request shall be deemed to be a Notice of Pro-Rata Borrowing for purposes hereof) and in accordance with the requirements of Sections 2.01 and 2.02, without regard to the minimum and multiples specified therein for the principal amount of Alternate Base Rate Pro-Rata Advances, but subject to the unutilized portion of the Commitments and the conditions set forth in Section 3.02. Such Swing Line Lender shall furnish such Borrower with a copy of the applicable Notice of Pro-Rata Borrowing promptly after delivering such notice to the Administrative Agent. Each Lender shall, before 1:00 p.m. (New York time) on the date of such Borrowing, make available for the account of its Applicable Lending Office to the Administrative Agent at its address referred to in Section 8.02, in same day funds, such Lender’s Percentage of such Pro-Rata Borrowing. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Administrative Agent will make such funds available to such Borrower at the Administrative Agent’s aforesaid address, whereupon, subject to Section 2.03(c)(ii), each Lender that so makes funds available shall be deemed to have made an Alternate Base Rate Pro-Rata Advance to such Borrower in such amount. The Administrative Agent shall remit the funds so received to the applicable Swing Line Lender.

(ii) If for any reason any Swing Line Advance cannot be refinanced by a Pro-Rata Borrowing in accordance with Section 2.03(c)(i), the request for Alternate Base Rate Pro-Rata Advances submitted by a Swing Line Lender as set forth herein shall be deemed to be a request by such Swing Line Lender that each Lender fund its risk participation in the relevant Swing Line Advances, and each Lender’s payment to the Administrative Agent for the account of such Swing Line Lender pursuant to Section 2.03(c)(i) shall be deemed payment in respect of such participation.

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(iii) If any Lender fails to make available to the Administrative Agent for the account of any Swing Line Lender any amount required to be paid by such Lender pursuant to the foregoing provisions of this Section 2.03(c) by the time specified in Section 2.03(c)(i), such Swing Line Lender shall be entitled to recover from such Lender (acting through the Administrative Agent), on demand, such amount with interest thereon for the period from the date such payment is required to the date on which such payment is immediately available to such Swing Line Lender at a rate per annum equal to the greater of the Federal Funds Rate and a rate determined by such Swing Line Lender in accordance with banking industry rules on interbank compensation. A certificate of such Swing Line Lender submitted to any Lender (through the Administrative Agent) with respect to any amounts owing under this clause (iii) shall be conclusive absent manifest error.

(iv) Each Lender’s obligation to make Pro-Rata Advances or to purchase and fund risk participations in Swing Line Advances pursuant to this Section 2.03(c) shall be absolute and unconditional and shall not be affected by any circumstance, including (A) any setoff, counterclaim, recoupment, defense or other right that such Lender may have against any Swing Line Lender, any Borrower or any other Person for any reason whatsoever, (B) the occurrence or continuance of an Unmatured Default or Event of Default, or (C) any other occurrence, event or condition, whether or not similar to any of the foregoing; provided, however, that each Lender’s obligation to make Pro-Rata Advances pursuant to this Section 2.03(c) is subject to the conditions set forth in Section 3.02. No such funding of risk participations shall relieve or otherwise impair the obligation of any Borrower to repay Swing Line Advances, together with interest as provided herein.

(d) Repayment of Participations.

(i) At any time after any Lender has purchased and funded a risk participation in a Swing Line Advance, if the applicable Swing Line Lender receives any payment on account of such Swing Line Advance, such Swing Line Lender will distribute to such Lender its Percentage of such payment (appropriately adjusted, in the case of interest payments, to reflect the period of time during which such Lender’s risk participation was funded) in the same funds as those received by such Swing Line Lender.

(ii) If any payment received by any Swing Line Lender in respect of principal or interest on any Swing Line Advance is required to be returned by such Swing Line Lender under any of the circumstances described in Section 2.15(g) (including pursuant to any settlement entered into by the Swing Line Lender in its discretion), each Lender shall pay to such Swing Line Lender its Percentage thereof on demand of the Administrative Agent, plus interest thereon from the date of such demand to the date such amount is returned, at a rate per annum equal to the Federal Funds Rate. The Administrative Agent will make such demand upon the request of such Swing Line Lender. The obligations of the Lenders under this clause shall survive the payment in full of the obligations hereunder and the termination of this Agreement.

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(e) Interest for Account of Swing Line Lenders. Each Swing Line Lender shall be responsible for invoicing the applicable Borrower for interest on the Swing Line Advances made to such Borrower. Until each Lender funds its Alternate Base Rate Pro-Rata Advance or risk participation pursuant to this Section 2.03 to refinance such Lender’s Percentage of any Swing Line Advance, interest in respect of such Percentage interest shall be solely for the account of such Swing Line Lender.

(f) Payments Directly to Swing Line Lenders. Each Borrower with outstanding Swing Line Advances shall make all payments of principal and interest in respect of such Swing Line Advances directly to the Swing Line Lender that made such Advances.

SECTION 2.04. Letters of Credit.

(a) Agreement of Fronting Banks. Subject to the terms and conditions of this Agreement, each Fronting Bank agrees to issue and amend (including, without limitation, to extend or renew) for the account of any Borrower or any Subsidiary thereof (each such Person, an “Account Party”) one or more standby letters of credit (individually, a “Letter of Credit” and collectively, the “Letters of Credit”) from and including the date hereof to the third Business Day preceding the Termination Date, in an aggregate Stated Amount at any time outstanding not to exceed such Fronting Bank’s LC Fronting Bank Commitment, up to a maximum aggregate Stated Amount of all Letters of Credit at any one time outstanding equal to the L/C Commitment Amount minus Reimbursement Obligations outstanding at such time. Each Letter of Credit may be renewable (if so requested by the applicable Borrower), shall have a Stated Amount not less than $100,000 and shall have an Expiration Date of no later than the earlier of (x) the third Business Day preceding the latest Termination Date and (y) the date occurring one year after the Date of Issuance of such Letter of Credit; provided, however, that no Fronting Bank will issue or amend a Letter of Credit if, immediately following such issuance or amendment, (i) the Stated Amount of such Letter of Credit would (A) exceed the Available Commitments or (B) when aggregated with (1) the Stated Amounts of all other outstanding Letters of Credit and (2) the outstanding Reimbursement Obligations, exceed the L/C Commitment Amount or (ii) the total amount of all Outstanding Credits would exceed the aggregate amount of the Commitments. Letters of Credit shall be denominated in Dollars only. Notwithstanding that any Letter of Credit issued or outstanding hereunder may be in support of any obligations of, or for the account of, a Subsidiary of a Borrower, any Borrower that requests the issuance of any such Letter of Credit in support of any obligations of, or for the account of, any of its Subsidiaries shall be obligated to reimburse the applicable Fronting Bank for any and all drawings under such Letter of Credit. Each Borrower that requests the issuance of any such Letter of Credit hereby acknowledges that the issuance of Letters of Credit for the account of its Subsidiaries inures to such Borrower’s benefit and that such Borrower’s business derives substantial benefits from the businesses of such Subsidiary. No Fronting Bank shall be under any obligation to issue any Letter of Credit if (A) any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain such Fronting Bank from issuing such Letter of Credit, (B) any law applicable to such Fronting Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over such Fronting Bank shall prohibit, or request that such Fronting Bank refrain from, the issuance of letters of credit generally or such Letter of Credit in particular or shall impose upon such Fronting Bank with respect to such Letter of Credit any restriction, reserve or capital requirement (for which such Fronting Bank is not otherwise compensated hereunder) not in effect on the date hereof, or shall impose upon such Fronting Bank any unreimbursed loss, cost or expense that was not applicable on the date hereof and that such Fronting Bank in good faith deems material to it, (C) the issuance of such Letter of Credit would violate one or more policies of such Fronting Bank or (D) such Fronting Bank is not required to make any Extension of Credit in connection with a Letter of Credit under Section 2.21(d).

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(b) Forms. Each Letter of Credit shall be in a form customarily used by the Fronting Bank that is to issue such Letter of Credit or in such other form as has been approved by such Fronting Bank. At the time of issuance or amendment, subject to the terms and conditions of this Agreement, the amount and the terms and conditions of each Letter of Credit shall be subject to approval by the applicable Fronting Bank and the applicable Borrower.

(c) Notice of Issuance; Application. The applicable Borrower shall give the applicable Fronting Bank and the Administrative Agent written notice, or telephonic notice confirmed in writing, in any case, at least two Business Days (or such shorter period as such Fronting Bank may agree in its sole discretion) prior to the requested Date of Issuance of a Letter of Credit, such notice to be in substantially the form of Exhibit E hereto (a “Letter of Credit Request”). Such Borrower shall also execute and deliver such customary letter of credit application forms as requested from time to time by such Fronting Bank. Such application forms shall indicate the identity of the Account Party and that such Borrower is the “Applicant” or shall otherwise indicate that such Borrower is the obligor in respect of any Letter of Credit to be issued thereunder. If the terms or conditions of the application forms conflict with any provision of this Agreement, the terms of this Agreement shall govern.

(d) Issuance. Provided that the applicable Borrower has given the notice prescribed by Section 2.04(c) and subject to the other terms and conditions of this Agreement, including the satisfaction of the applicable conditions precedent set forth in Article III, the applicable Fronting Bank shall issue the requested Letter of Credit on the requested Date of Issuance as set forth in the applicable Letter of Credit Request for the benefit of the stipulated Beneficiary and shall deliver the original of such Letter of Credit to the Beneficiary at the address specified in the notice. At the request of the applicable Borrower, such Fronting Bank shall deliver a copy of each Letter of Credit to such Borrower within a reasonable time after the Date of Issuance thereof. Upon the request of such Borrower, such Fronting Bank shall deliver to such Borrower a copy of any Letter of Credit proposed to be issued hereunder prior to the issuance thereof.

(e) Notice of Drawing. Each Fronting Bank shall promptly notify the applicable Borrower by telephone, facsimile or other telecommunication of any Drawing under a Letter of Credit issued for the account of such Borrower by such Fronting Bank.

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(f) Payments. Each Borrower hereby agrees to pay to each Fronting Bank, in the manner provided in subsection (g) below:

(i) on the date of receipt by such Borrower of notice of any Drawing pursuant to a subsection (e) above, if such notice is received not later than 11:00 a.m. (New York City time), or on the first Business Day following receipt of such notice by such Borrower, if such notice is received later than 11:00 a.m. (New York City time), an amount equal to the amount paid by such Fronting Bank in connection with such Drawing (such date being the “Required Reimbursement Date”); and

(ii) if any Drawing shall be reimbursed to any Fronting Bank after 12:00 noon (New York time) on the applicable Payment Date, interest on any and all amounts required to be paid pursuant to clause (i) of this subsection (f) from and after such Payment Date until payment in full, payable on demand, at the annual rate of interest applicable to Alternate Base Rate Advances as in effect from time to time, provided, however, that from and after the Required Reimbursement Date with respect to such Drawing until payment in full, such interest rate shall be increased by 2.00%.

(g) Method of Reimbursement. Each Borrower shall reimburse each Fronting Bank for each Drawing under any Letter of Credit issued for the account of such Borrower by such Fronting Bank pursuant to subsection (f) above in the following manner:

(i) such Borrower shall reimburse such Fronting Bank in the manner described in subsection (f) above and Section 2.15; or

(ii) if (A) such Borrower has not reimbursed such Fronting Bank pursuant to paragraph (i) above, (B) the applicable conditions to Borrowing set forth in Articles II and III have been fulfilled, and (C) the Available Commitments in effect at such time exceed the amount of the Drawing to be reimbursed, such Borrower may reimburse such Fronting Bank for such Drawing with the proceeds of an Alternate Base Rate Pro-Rata Advance or, if the conditions specified in the foregoing clauses (A), (B) and (C) have been satisfied and a Notice of Borrowing requesting a Eurodollar Rate Advance has been given in accordance with Section 2.02 three Business Days prior to the relevant Payment Date, with the proceeds of a Eurodollar Rate Advance.

(h) Nature of Fronting Banks’ Duties. In determining whether to honor any Drawing under any Letter of Credit issued by any Fronting Bank, such Fronting Bank shall be responsible only to determine that the documents and certificates required to be delivered under such Letter of Credit have been delivered and that they comply on their face with the requirements of such Letter of Credit. Each Borrower otherwise assumes all risks of the acts and omissions of, or misuse of any Letter of Credit issued by any Fronting Bank for the account of such Borrower by, the Beneficiary of such Letter of Credit. In furtherance and not in limitation of the foregoing, but consistent with applicable law, no Fronting Bank shall be responsible, absent gross negligence or willful misconduct, (i) for the form, validity, sufficiency, accuracy, genuineness or legal effects of any document submitted by any party in connection with the application for and issuance of any drawing honored under a Letter of Credit, even if it should in fact prove to be in any or all respects invalid, insufficient, inaccurate, fraudulent or forged; (ii) for the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign any such Letter of Credit, or the rights or benefits thereunder or proceeds thereof, in whole or in part,

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which may prove to be invalid or ineffective for any reason; (iii) for errors, omissions, interruptions or delays in transmission or delivery of any messages, by mail, cable, telegraph, telex, facsimile or otherwise, whether or not they be in cipher; (iv) for errors in interpretation of technical terms; (v) for any loss or delay in the transmission or otherwise of any document required in order to make a drawing under any such Letter of Credit, or the proceeds thereof; (vi) for the misapplication by the Beneficiary of any such Letter of Credit or of the proceeds of any drawing honored under such Letter of Credit; and (vii) for any consequences arising from causes beyond the control of such Fronting Bank. None of the above shall affect, impair or prevent the vesting of any of such Fronting Bank’s rights or powers hereunder. Not in limitation of the foregoing, any action taken or omitted to be taken by any Fronting Bank under or in connection with any Letter of Credit shall not create against such Fronting Bank any liability to the Borrowers or any Lender, except for actions or omissions resulting from the gross negligence or willful misconduct of such Fronting Bank or any of its agents or representatives, and such Fronting Bank shall not be required to take any action that exposes such Fronting Bank to personal liability or that is contrary to this Agreement or applicable law.

(i) Obligations of Borrowers Absolute. The obligation of each Borrower to reimburse each Fronting Bank for Drawings honored under the Letters of Credit issued for the account of such Borrower by such Fronting Bank shall be unconditional and irrevocable and shall be paid strictly in accordance with the terms of this Agreement under all circumstances including, without limitation, the following circumstances:

(i) any lack of validity or enforceability of any Letter of Credit;

(ii) the existence of any claim, set-off, defense or other right that any Borrower, any Account Party or any Affiliate of any Borrower or any Account Party may have at any time against a Beneficiary or any transferee of any Letter of Credit (or any Persons or entities for whom any such Beneficiary or transferee may be acting), such Fronting Bank or any other Person, whether in connection with this Agreement, the transactions contemplated herein or any unrelated transaction;

(iii) any draft, demand, certificate or any other documents presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(iv) the surrender or impairment of any security for the performance or observance of any of the terms of any of the Loan Documents;

(v) any non-application or misapplication by the Beneficiary of the proceeds of any Drawing under a Letter of Credit; or

(vi) the fact that an Event of Default or an Unmatured Default shall have occurred and be continuing.

No payment made under this Section shall be deemed to be a waiver of any claim any Borrower may have against any Fronting Bank or any other Person.

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(j) Participations by Lenders. By the issuance of a Letter of Credit and without any further action on the part of any Fronting Bank or any Lender in respect thereof, each Fronting Bank shall hereby be deemed to have granted to each Lender, and each Lender shall hereby be deemed to have acquired from such Fronting Bank, an undivided interest and participation in such Letter of Credit (including any letter of credit issued by such Fronting Bank in substitution or exchange for such Letter of Credit pursuant to the terms thereof) equal to such Lender’s Percentage of the Stated Amount of such Letter of Credit, effective upon the issuance of such Letter of Credit. In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to such Fronting Bank, in accordance with this subsection (j), such Lender’s Percentage of each payment made by such Fronting Bank in respect of an unreimbursed Drawing under a Letter of Credit. Such Fronting Bank shall notify the Administrative Agent of the amount of such unreimbursed Drawing honored by it not later than (x) 12:00 noon (New York time) on the date of payment of a draft under a Letter of Credit, if such payment is made at or prior to 11:00 a.m. (New York time) on such day, and (y) the close of business (New York time) on the date of payment of a draft under a Letter of Credit, if such payment is made after 11:00 a.m. (New York time) on such day, and the Administrative Agent shall notify each Lender of the date and amount of such unreimbursed Drawing under such Letter of Credit honored by such Fronting Bank and the amount of such Lender’s Percentage therein no later than (1) 1:00 p.m. (New York time) on such day, if such payment is made at or prior to 11:00 a.m. (New York time) on such day, and (2) 11:00 a.m. (New York time) on the next following Business Day, if such payment is made after 11:00 a.m. (New York time) on such day. Not later than 2:00 p.m. (New York time) on the date of receipt of a notice of an unreimbursed Drawing by a Lender, such Lender agrees to pay to such Fronting Bank an amount equal to the product of (A) such Lender’s Percentage and (B) the amount of the payment made by such Fronting Bank in respect of such unreimbursed Drawing.

If payment of the amount due pursuant to the preceding sentence from a Lender is received by such Fronting Bank after the close of business on the date it is due, such Lender agrees to pay to such Fronting Bank, in addition to (and along with) its payment of the amount due pursuant to the preceding sentence, interest on such amount at a rate per annum equal to (i) for the period from and including the date such payment is due to but excluding the second succeeding Business Day, the Federal Funds Rate, and (ii) for the period from and including the second Business Day succeeding the date such payment is due to but excluding the date on which such amount is paid in full, the Federal Funds Rate plus 2.00%.

(k) Obligations of Lenders Absolute. Each Lender acknowledges and agrees that (i) its obligation to acquire a participation in any Fronting Bank’s liability in respect of the Letters of Credit and (ii) its obligation to make the payments specified herein, and the right of each Fronting Bank to receive the same, in the manner specified herein, are absolute and unconditional and shall not be affected by any circumstances whatsoever, including, without limitation, (A) the occurrence and continuance of any Event of Default or Unmatured Default; (B) any other breach or default by any Borrower, the Administrative Agent or any Lender hereunder; (C) any lack of validity or enforceability of any Letter of Credit or any Loan Document; (D) the existence of any claim, setoff, defense or other right that the Lender may have at any time against any Borrower, any other Account Party, any Beneficiary, any Fronting Bank or any other Lender; (E) the existence of any claim, setoff, defense or other right that any Borrower may have at any time against any Beneficiary, any Fronting Bank, the Administrative Agent, any Lender or any other Person, whether in connection with this Agreement or any other documents contemplated hereby or any unrelated transactions; (F) any amendment or waiver of, or consent to any departure from, all or any of the Letters of Credit or this Agreement; (G) any statement or any document presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect; (H) payment by any Fronting Bank under any Letter of Credit against presentation of a draft or certificate that does not comply with the terms of such Letter of Credit, so long as such payment is not the consequence of such Fronting Bank’s gross negligence or willful misconduct in determining whether documents presented under a Letter of Credit comply with the terms thereof; (I) the occurrence of the Termination Date; or (J) any other circumstance or happening whatsoever, whether or not similar to any of the foregoing. Nothing herein shall prevent the assertion by any Lender of a claim by separate suit or compulsory counterclaim, nor shall any payment made by a Lender under Section 2.04 hereof be deemed to be a waiver of any claim that a Lender may have against any Fronting Bank or any other Person.

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(l) Proceeds of Reimbursements. Upon receipt of a payment from a Borrower pursuant to subsection (f) hereof, the applicable Fronting Bank shall promptly transfer to each Lender that has funded its participation in the applicable Drawing pursuant to subsection (j) above, such Lender’s pro rata share (determined in accordance with such Lender’s Percentage) of such payment. All payments due to the Lenders from any Fronting Bank pursuant to this subsection (l) shall be made to the Lenders if, as, and, to the extent possible, when such Fronting Bank receives payments in respect of Drawings under the Letters of Credit pursuant to subsection (f) hereof, and in the same funds in which such amounts are received; provided that if any Lender to which such Fronting Bank is required to transfer any such payment (or any portion thereof) pursuant to this subsection (l) does not receive such payment (or portion thereof) prior to (i) the close of business on the Business Day on which such Fronting Bank received such payment from such Borrower, if such Fronting Bank received such payment prior to 1:00 p.m. (New York time) on such day, or (ii) 1:00 p.m. (New York time) on the Business Day next succeeding the Business Day on which such Fronting Bank received such payment from the Borrower, if such Fronting Bank received such payment after 1:00 p.m. (New York time) on such day, such Fronting Bank agrees to pay to such Lender, along with its payment of the portion of such payment due to such Lender, interest on such amount at a rate per annum equal to (A) for the period from and including the Business Day when such payment was required to be made to the Lenders to but excluding the second succeeding Business Day, the Federal Funds Rate and (B) for the period from and including the second Business Day succeeding the Business Day when such payment was required to be made to the Lenders to but excluding the date on which such amount is paid in full, the Federal Funds Rate plus 2.00%.

(m) Concerning the Fronting Banks. Each Fronting Bank will exercise and give the same care and attention to the Letters of Credit issued by it as it gives to its other letters of credit and similar obligations, and each Lender agrees that each Fronting Bank’s sole liability to such Lender shall be (i) to distribute promptly, as and when received by such Fronting Bank, and in accordance with the provisions of subsection (l) above, such Lender’s Percentage of any payments to such Fronting Bank by the Borrowers pursuant to subsection (f) above in respect of Drawings under the Letters of Credit issued by such Fronting Bank, (ii) to exercise or refrain from exercising any right or to take or to refrain from taking any action under this Agreement or any Letter of Credit issued by such Fronting Bank as may be directed in writing by the Majority Lenders (or, when expressly required by the terms of this Agreement, all

32

of the Lenders) or the Administrative Agent acting at the direction and on behalf of the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders), except to the extent required by the terms hereof or thereof or by applicable law, and (iii) as otherwise expressly set forth in this Section 2.04. No Fronting Bank shall be liable for any action taken or omitted at the request or with approval of the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders) or of the Administrative Agent acting on behalf of the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders) or for the nonperformance of the obligations of any other party under this Agreement, any Letter of Credit or any other document contemplated hereby or thereby. Without in any way limiting any of the foregoing, each Fronting Bank may rely upon the advice of counsel concerning legal matters and upon any written communication or any telephone conversation that it believes to be genuine or to have been signed, sent or made by the proper Person and shall not be required to make any inquiry concerning the performance by any Borrower, any Beneficiary or any other Person of any of their respective obligations and liabilities under or in respect of this Agreement, any Letter of Credit or any other documents contemplated hereby or thereby. No Fronting Bank shall have any obligation to make any claim, or assert any Lien, upon any property held by such Fronting Bank or assert any offset thereagainst in satisfaction of all or any part of the obligations of the Borrowers hereunder; provided that each Fronting Bank shall, if so directed by the Majority Lenders or the Administrative Agent acting on behalf of and with the consent of the Majority Lenders, have an obligation to make a claim, or assert a Lien, upon property held by such Fronting Bank in connection with this Agreement, or assert an offset thereagainst.

Each Fronting Bank may accept deposits from, make loans or otherwise extend credit to, and generally engage in any kind of banking or trust business with the Borrowers or any of their Affiliates, or any other Person, and receive payment on such loans or extensions of credit and otherwise act with respect thereto freely and without accountability in the same manner as if it were not a Fronting Bank hereunder.

Each Fronting Bank makes no representation or warranty and shall have no responsibility with respect to: (i) the genuineness, legality, validity, binding effect or enforceability of this Agreement or any other documents contemplated hereby; (ii) the truthfulness, accuracy or performance of any of the representations, warranties or agreements contained in this Agreement or any other documents contemplated hereby; (iii) the collectibility of any amounts due under this Agreement; (iv) the financial condition of the Borrowers or any other Person; or (v) any act or omission of any Beneficiary with respect to its use of any Letter of Credit or the proceeds of any Drawing under any Letter of Credit.

(n) Indemnification of Fronting Banks by Lenders. To the extent that any Fronting Bank is not reimbursed and indemnified by the Borrowers under Section 8.05 hereof, each Lender agrees to reimburse and indemnify such Fronting Bank on demand, pro rata in accordance with such Lender’s Percentage, for and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by or asserted against such Fronting Bank, in any way relating to or arising out of this Agreement, any Letter of Credit or any other document contemplated hereby or thereby, or any action taken or omitted by such Fronting Bank under or in connection with this Agreement, any Letter of Credit or any other document contemplated hereby or thereby; provided, however, that such Lender shall not be liable

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for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from such Fronting Bank’s gross negligence or willful misconduct; and provided further, however, that such Lender shall not be liable to such Fronting Bank or any other Lender for the failure of any Borrower to reimburse such Fronting Bank for any drawing made under a Letter of Credit issued for the account of such Borrower with respect to which such Lender has paid such Fronting Bank such Lender’s pro rata share (determined in accordance with such Lender’s Percentage), or for such Borrower’s failure to pay interest thereon. Each Lender’s obligations under this subsection (n) shall survive the payment in full of all amounts payable by such Lender under subsection (j) above, and the termination of this Agreement and the Letters of Credit. Nothing in this subsection (n) is intended to limit any Lender’s reimbursement obligation contained in subsection (j) above.

(o) Representations of Lenders. As between any Fronting Bank and the Lenders, by its execution and delivery of this Agreement each Lender hereby represents and warrants solely to such Fronting Bank that (i) it is duly organized and validly existing in good standing under the laws of the jurisdiction of its formation, and has full corporate power, authority and legal right to execute, deliver and perform its obligations to such Fronting Bank under this Agreement; and (ii) this Agreement constitutes its legal, valid and binding obligation enforceable against it in accordance with the terms hereof, except as such enforceability may be limited by applicable bank organization, moratorium, conservatorship or other laws now or hereafter in effect affecting the enforcement of creditors rights in general and the rights of creditors of banks, and except as such enforceability may be limited by general principles of equity (whether considered in a proceeding at law or in equity).

(p) The Letters of Credit listed in Schedule IV shall be deemed “Letters of Credit” upon fulfillment of the conditions precedent listed in Sections 3.01 and 3.02.

(q) Successor Fronting Bank. Any Fronting Bank may resign at any time by giving written notice thereof to the Lenders, the other Fronting Banks and the Borrowers, as long as such Fronting Bank has no Letters of Credit outstanding under this Agreement. Upon such resignation, the Borrowers may designate one or more Lenders as Fronting Banks to replace the retiring Fronting Bank. If a Fronting Bank has any Letters of Credit outstanding under this Agreement and delivers a written notice of its intent to resign to the Lenders, the other Fronting Banks and the Borrowers, such Fronting Bank shall continue to honor its obligations under this Agreement, but shall have no obligation to issue any new Letter of Credit. Upon receipt of such notice of intent to resign, the Borrowers and such Fronting Bank may agree to replace or terminate the outstanding Letters of Credit issued by such Fronting Bank and to designate one or more Lenders as Fronting Banks to replace such Fronting Bank.

(r) Reallocation of L/C Fronting Bank Commitments. If any Lender becomes a Fronting Bank after the date hereof (a “New Fronting Bank”), the L/C Fronting Bank Commitments of the Lenders that are Fronting Banks on the date hereof (the “Original Fronting Banks”) shall be reduced by an aggregate amount equal to such New Fronting Bank’s L/C Fronting Banks Commitment, with such reduction to be allocated among the Original Fronting Banks ratably in accordance such Original Fronting Banks’ respective L/C Fronting Bank Commitments on the date of such reduction.

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SECTION 2.05. Fees.

(a) Each Borrower agrees to pay to the Administrative Agent for the account of each Lender a commitment fee on the amount of such Lender’s Percentage of the unused portion of such Borrower’s Borrower Sublimit from the date hereof in the case of each Bank and from the effective date specified in the Assignment and Assumption pursuant to which it became a Lender in the case of each other Lender until the Termination Date applicable to such Lender, payable on the last day of each March, June, September and December during such period, and on such Termination Date, at the rate per annum set forth below determined by reference to the Reference Ratings of FE from time to time in effect:

LEVEL 6

LEVEL 2

LEVEL 3

LEVEL 4

LEVEL 5

Reference

Reference

Reference

Reference

Reference

Ratings

LEVEL 1

Ratings lower

Ratings of

Ratings lower

Ratings lower

lower than

Reference

than Level 1

lower than

than Level 3

than Level 4

BB+ by S&P

Ratings at least

but at least

Level 2 but at

but at least

but at least

and Ba1 by

A- by S&P or

BBB+ by

least BBB by

BBB- by S&P

BB+ by S&P

Moody’s, or

BASIS FOR

A3 by

S&P or Baa1

S&P or Baa2

or Baa3 by

or Ba1 by

no Reference

PRICING

Moody’s.

by Moody’s.

by Moody’s.

Moody’s.

Moody’s.

Ratings.

Commitment Fee

0.15

%

0.20

%

0.25

%

0.30

%

0.40

%

0.55

%

For purposes of the foregoing, if (i) there is a difference of one level in Reference Ratings of S&P and Moody’s and the higher of such Reference Ratings falls in Level 1, Level 2, Level 3, Level 4 or Level 5, then the higher Reference Rating will be used to determine the commitment fee, and (ii) there is a difference of more than one level in Reference Ratings of S&P and Moody’s, the Reference Rating that is one level above the lower of such Reference Ratings will be used to determine the commitment fee, unless the lower of such Reference Ratings falls in Level 6, in which case the lower of such Reference Ratings will be used to determine the commitment fee. If there exists only one Reference Rating, such Reference Rating will be used to determine the commitment fee.

(b) Each Borrower agrees to pay the fees payable by such Borrower in such amounts and payable on such terms as set forth in the Fee Letters.

(c) Each Borrower agrees to pay to the Administrative Agent, for the account of the Lenders, a fee in an amount equal to the then Applicable Margin for Eurodollar Rate Advances for such Borrower multiplied by the Stated Amount of each Letter of Credit issued for the account of such Borrower, in each case for the number of days that such Letter of Credit is issued and outstanding, payable quarterly in arrears on the last day of each March, June, September and December and on the date such Letter of Credit expires.

(d) Each Borrower agrees to pay to each Fronting Bank, for its own account, certain fees payable such Borrower in such amounts and payable on such terms as set forth in the Fronting Bank Fee Letter to which such Fronting Bank is a party.

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SECTION 2.06. Adjustment of the Commitments; Borrower Sublimits.

(a) Commitment Reduction. The Borrowers shall have the right, upon at least three Business Days’ notice to the Administrative Agent, to terminate in whole or, upon same day notice, from time to time to permanently reduce ratably in part the unused portion of the Commitments; provided that each partial reduction shall be in the aggregate amount of $5,000,000 or in an integral multiple of $1,000,000 in excess thereof; provided, further, that the Commitments may not be reduced to an amount that is less than the aggregate Stated Amount of outstanding Letters of Credit. Subject to the foregoing, any reduction of the Commitments to an amount below $2,500,000,000 shall also result in a reduction of the L/C Commitment Amount to the extent of such deficit. Each such notice of termination or reduction shall be irrevocable; provided, further, that, if, after giving effect to any reduction of the Commitments, the Swing Line Sublimit or any Borrower Sublimit exceeds the amount of the aggregate Commitments, such sublimit shall be automatically reduced by the amount of such excess, and the L/C Fronting Bank Commitments shall be automatically reduced ratably in proportion to the amount of reduction of the Commitments. Without limiting subsection (b) below, any Commitment reduced or terminated pursuant to this subsection (a) may not be reinstated.

(b) Commitment Increase. (i) On any date on or prior to the Termination Date, but no more than once in each calendar year, the Borrowers may increase the aggregate amount of the Commitments by an amount not less than $50,000,000 and up to an aggregate amount for all such increases not more than the sum of the aggregate amount of the Commitments on the date of such request plus $500,000,000 (any such increase, a “Commitment Increase”) by designating one or more of the existing Lenders or one or more Affiliates thereof (each of which, in its sole discretion, may determine whether and to what degree to participate in such Commitment Increase) or one or more other Persons that at the time agree, in the case of any existing Lender, to increase its Commitment (an “Increasing Lender”) and, in the case of any other Person or an Affiliate of a Lender (an “Additional Lender”), to become a party to this Agreement; provided that (i) each Additional Lender shall be acceptable to the Administrative Agent, and each Increasing Lender and each Additional Lender shall be acceptable to the Fronting Banks and the Swing Line Lenders, (ii) the allocations of the Commitment Increase among the Increasing Lenders shall be based on the ratio of each Increasing Lender’s proposed Commitment amount after giving effect to such Commitment Increase to the aggregate amount of all Increasing Lenders’ proposed Commitment amounts after giving effect to such Commitment Increase, and (iii) the amount of the Commitment of each Additional Lender shall not be less than $5,000,000. The sum of the increases in the Commitments of the Increasing Lenders pursuant to this subsection (b) plus the Commitments of the Additional Lenders upon giving effect to the Commitment Increase shall not exceed the amount of the Commitment Increase. The Borrowers shall provide prompt notice of any proposed Commitment Increase pursuant to this Section 2.06(b) to the Administrative Agent, which shall promptly provide a copy of such notice to the Lenders and the Fronting Banks.

(ii) Any Commitment Increase shall become effective upon (A) the receipt by the Administrative Agent of an agreement in form and substance satisfactory to the Administrative Agent signed by each Borrower, each Increasing Lender and each Additional Lender, setting forth the new Commitment of each such Lender and setting forth the agreement of each Additional Lender to become a party to this Agreement and to be bound by all the terms and provisions hereof binding upon each Lender, (B) the funding by each Lender of the Advance(s) to be made by each such Lender described in paragraph (iii) below and (C) receipt by the Administrative Agent of a certificate (the statements contained in which shall be true) of an Authorized Officer of each Borrower stating that both before and after giving effect to such Commitment Increase (1) no Event of Default has occurred and is continuing and (2) all representations and warranties made by such Borrower in this Agreement are true and correct in all material respects.

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(iii) Upon the effective date of any Commitment Increase, the Borrowers shall prepay the outstanding Pro-Rata Advances (if any) in full, and shall simultaneously make new Pro-Rata Advances hereunder in an amount equal to such prepayment, so that, after giving effect thereto, the Pro-Rata Advances are held ratably by the Lenders in accordance with their respective Commitments (after giving effect to such Commitment Increase). Prepayments made under this paragraph (iii) shall not be subject to the notice requirements of Section 2.12.

(iv) Notwithstanding any provision contained herein to the contrary, from and after the date of any Commitment Increase and the making of any Pro-Rata Advances on such date pursuant to paragraph (iii) above, all calculations and payments of the commitment fee, Letter of Credit fees and interest on the Advances shall take into account the actual Commitment of each Lender and the principal amount outstanding of each Advance made by such Lender during the relevant period of time.

(c) Borrower Sublimit Increase. In connection with any Commitment Increase, each Borrower may increase its Borrower Sublimit by an amount equal to its Fraction (calculated as of the date hereof) of such Commitment Increase by delivering a notice to the Administrative Agent requesting such increase.

SECTION 2.07. Repayment of Advances.

Each Borrower agrees to repay the principal amount of each Advance made by each Lender to such Borrower no later than the earlier of (i) 364 days after the date such Advance is made (or in the case of a Swing Line Advance, 10 days after the date such Swing Line Advance is made) and (ii) the latest Termination Date applicable to such Lender; provided, however, that if any Borrower shall deliver to the Administrative Agent evidence reasonably satisfactory to the Administrative Agent (including, without limitation, certified copies of governmental approvals and legal opinions) that such Borrower is authorized under Applicable Law to incur Indebtedness hereunder maturing more than 364 days after the date of incurrence of such Indebtedness, such Borrower shall repay each Advance made to it by a Lender no later than the latest Termination Date applicable to such Lender.

SECTION 2.08. Interest on Advances.

Each Borrower agrees to pay interest on the unpaid principal amount of each Advance made by each Lender to such Borrower from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum, subject to Section 2.15(f):

(a) Alternate Base Rate Pro-Rata Advances. If such Advance is an Alternate Base Pro-Rata Rate Advance, a rate per annum equal at all times to the Alternate Base Rate in effect from time to time plus the Applicable Margin for such Alternate Base Rate Pro-Rata Advance in effect from time to time, payable quarterly in arrears on the last day of each March, June, September and December, on the Termination Date and on the date such Alternate Base Rate Pro-Rata Advance shall be Converted or be paid in full and as provided in Section 2.12;

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(b) Eurodollar Rate Advances. If such Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during the Interest Period for such Advance to the sum of the Eurodollar Rate for such Interest Period plus the Applicable Margin for such Eurodollar Rate Advance in effect from time to time, payable on the last day of each Interest Period for such Eurodollar Rate Advance (and, in the case of any Interest Period of six months, on the last day of the third month of such Interest Period), on the Termination Date and on the date such Eurodollar Rate Advance shall be Converted or be paid in full and as provided in Section 2.12; and

(c) Swing Line Advances. If such Advance is a Swing Line Advance, a rate per annum equal to the sum of the Alternate Base Rate in effect from time to time plus the Applicable Margin for such Swing Line Advance payable on the date such Swing Line Advance is paid in full and as provided in Section 2.12.

SECTION 2.09. Additional Interest on Advances.

Each Borrower agrees to pay to each Lender, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance made by such Lender to such Borrower, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage of such Lender for such Interest Period, payable on each date on which interest is payable on such Advance; provided, that no Lender shall be entitled to demand additional interest under this Section 2.09 more than 90 days following the last day of the Interest Period in respect of which such demand is made; provided further, however, that the foregoing proviso shall in no way limit the right of any Lender to demand or receive such additional interest to the extent that such additional interest relates to the retroactive application by the Board of Governors of the Federal Reserve System of any regulation described above if such demand is made within 90 days after the implementation of such retroactive regulation. Such additional interest shall be determined by such Lender and notified to the applicable Borrower through the Administrative Agent, and such determination shall be conclusive and binding for all purposes, absent manifest error.

SECTION 2.10. Interest Rate Determination.

(a) The Administrative Agent shall give prompt notice to the applicable Borrower and the Lenders of the applicable interest rate determined by the Administrative Agent for purposes of Section 2.08(a), (b) or (c).

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(b) If, with respect to any Eurodollar Rate Advances, the Majority Lenders notify the Administrative Agent that (i) Dollar deposits are not being offered to banks in the London interbank eurodollar market for the applicable amount and Interest Period of such Eurodollar Rate Advances, (ii) adequate and reasonable means do not exist for determining the Eurodollar Rate or (iii) the Eurodollar Rate for any Interest Period for such Advances will not adequately reflect the cost to such Majority Lenders of making or funding their respective Eurodollar Rate Advances for such Interest Period, the Administrative Agent shall forthwith so notify the Borrowers and the Lenders, whereupon

(i) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into an Alternate Base Rate Pro-Rata Advance, and

(ii) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrowers and the Lenders that the circumstances causing such suspension no longer exist.

(c) Upon the occurrence and during the continuance of any Event of Default, (i) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period thereofor, Convert into a Base Rate Advance, and the obligation of the Lenders to make or to Convert Advances into, Eurodollar Rate Advances shall be suspended.

SECTION 2.11. Conversion of Advances.

(a) Voluntary. Any Borrower may on any Business Day, upon notice given to the Administrative Agent not later than 11:00 a.m. (New York time) on the third Business Day prior to the date of any proposed Conversion into Eurodollar Rate Advances, and on the date of any proposed Conversion into Alternate Base Rate Pro-Rata Advances, and subject to the provisions of Sections 2.10 and 2.14, Convert all Pro-Rata Advances of one Type made to such Borrower in connection with the same Borrowing into Pro-Rata Advances of another Type or Types or Pro-Rata Advances of the same Type having the same or a new Interest Period; provided, however, that any Conversion of, or with respect to, any Eurodollar Rate Advances into Pro-Rata Advances of another Type or Pro-Rata Advances of the same Type having the same or new Interest Periods, shall be made on, and only on, the last day of an Interest Period for such Eurodollar Rate Advances, unless the applicable Borrower shall also reimburse the Lenders in respect thereof pursuant to Section 8.05(b) on the date of such Conversion. Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Pro-Rata Advances to be Converted, and (iii) if such Conversion is into, or with respect to, Eurodollar Rate Advances, the duration of the Interest Period for each such resulting Pro-Rata Advance.

(b) Mandatory. If any Borrower shall fail to select the Type of any Pro-Rata Advance or the duration of any Interest Period for any Borrowing comprising Eurodollar Rate Advances in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01 and Section 2.11(a), or if any proposed Conversion of a Borrowing that is to comprise Eurodollar Rate Advances upon Conversion shall not occur as a result of the circumstances described in paragraph (c) below, the Administrative Agent will forthwith so notify such Borrower and the Lenders, and such Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Alternate Base Rate Pro-Rata Advances.

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(c) Failure to Convert. Each notice of Conversion given by any Borrower pursuant to subsection (a) above shall be irrevocable and binding on such Borrower. In the case of any Borrowing that is to comprise Eurodollar Rate Advances upon Conversion, the Borrower agrees to indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure of such Conversion to occur pursuant to the provisions of Section 2.10(c), including, without limitation, any loss, cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by such Lender to fund such Eurodollar Rate Advances upon such Conversion, when such Conversion does not occur. Each Borrower’s obligations under this subsection (c) shall survive the repayment of all other amounts owing by such Borrower to the Lenders and the Administrative Agent under this Agreement and any Note and the termination of the Commitments.

SECTION 2.12. Prepayments.

(a) Optional. Any Borrower may at any time prepay the outstanding principal amounts of the Advances made to such Borrower as part of the same Borrowing in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid, upon notice thereof given to the Administrative Agent by such Borrower not later than 11:00 a.m. (New York time) (i) on the date of any such prepayment in the case of Alternate Base Rate Advances and (ii) on the second Business Day prior to any such prepayment in the case of Eurodollar Rate Advances; provided, however, that (x) each partial prepayment of any Borrowing shall be in an aggregate principal amount not less than $5,000,000 with respect to Pro-Rata Borrowings and $1,000,000 with respect to Swing Line Borrowings and (y) in the case of any such prepayment of a Eurodollar Rate Advance, such Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.05(b) on the date of such prepayment.

(b) Mandatory. (i) If and to the extent that the Outstanding Credits on any date hereunder shall exceed the aggregate amount of the Commitments hereunder on such date, each Borrower agrees to (A) prepay on such date a principal amount of Advances and/or (B) pay to the Administrative Agent an amount in immediately available funds (which funds shall be held as collateral pursuant to arrangements satisfactory to the Administrative Agent) equal to all or a portion of the amount available for drawing under the Letters of Credit outstanding at such time, which prepayment under clause (A) and payment under clause (B) shall, when taken together result in the amount of Outstanding Credits minus the amount paid to the Administrative Agent pursuant to clause (B) being less than or equal to the aggregate amount of the Commitments hereunder on such date.

(ii) If at any time the Outstanding Credits with respect to a Borrower on any date hereunder shall exceed the Borrower Sublimit for such Borrower, such Borrower agrees to (A) prepay on such date Advances in a principal amount equal to such excess and/or (B) pay to the Administrative Agent an amount in immediately available funds (which funds shall be held as collateral pursuant to arrangements satisfactory to the Administrative Agent) equal to all or a portion of the amount available for drawing under the Letters of Credit outstanding to such Borrower at such time, which prepayment under clause (A) and payment under clause (B) shall, when taken together, result in the amount of Outstanding Credits minus the amount paid to the Administrative Agent pursuant to clause (B) being less than or equal to the aggregate amount of the applicable Borrower Sublimit hereunder on such date.

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(iii) If at any time the aggregate principal amount of the Swing Line Advances exceeds the Swing Line Sublimit, each Borrower agrees to prepay the Swing Line Advances outstanding to such Borrower in a principal amount equal to such Borrower’s pro-rata amount of such excess, determined on the basis of the percentage of the aggregate principal amount of Swing Line Advances outstanding to such Borrower.

Any prepayment of Advances shall be accompanied by accrued interest on the amount prepaid to the date of such prepayment and, in the case of any such prepayment of Eurodollar Rate Advances, the applicable Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.05(b).

SECTION 2.13. Increased Costs.

(a) If, due to any Change in Law, there shall be any increase in the cost (other than in respect of Taxes, which are addressed exclusively in Section 2.16) to any Lender of agreeing to make or making, funding or maintaining Eurodollar Rate Advances or any increase in the cost to any Fronting Bank or any Lender of issuing, maintaining or participating in Letters of Credit, other than, in each case, relating to Taxes, then each Borrower shall from time to time, upon demand by such Lender or such Fronting Bank (as the case may be) (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender or such Fronting Bank (as the case may be) additional amounts sufficient to compensate such Lender or such Fronting Bank (as the case may be) for such increased cost. A certificate as to the amount of such increased cost and the basis therefor, submitted to each Borrower and the Administrative Agent by such Lender or such Fronting Bank (as the case may be), shall constitute such demand and shall be conclusive and binding for all purposes, absent manifest error.

(b) If any Lender or any Fronting Bank determines that any Change in Law affects or would affect the amount of capital required or expected to be maintained by such Lender or such Fronting Bank (as the case may be) or any corporation controlling such Lender or such Fronting Bank (as the case may be) and that the amount of such capital is increased by or based upon the existence of (i) such Lender’s commitment to lend or participate in Letters of Credit hereunder and other commitments of this type or (ii) the Advances made by such Lender or (iii) the participations in Letters of Credit acquired by such Lender or (iv) in the case of any Fronting Bank, such Fronting Bank’s commitment to issue, maintain and honor drawings under Letters of Credit hereunder, or (v) the honoring of Letters of Credit by any Fronting Bank hereunder, then, upon demand by such Lender or such Fronting Bank (as the case may be) (with a copy of such demand to the Administrative Agent), each Borrower shall immediately pay to the Administrative Agent for the account of such Lender or such Fronting Bank (as the case may be), from time to time as specified by such Lender or such Fronting Bank (as the case may be), additional amounts sufficient to compensate such Lender, such Fronting Bank or such corporation in the light of such circumstances, to the extent that such Lender or such Fronting Bank (as the case may be) determines such increase in capital to be allocable to (i) in the case of such Lender, the existence of such Lender’s commitment to lend hereunder or the Advances made by such Lender or (ii) the participations in Letters of Credit acquired by such Lender or (iii) in the case of any Fronting Bank, such Fronting Bank’s Commitment to issue, maintain and honor drawings under Letters of Credit hereunder, or (iv) the honoring of Letters of Credit by any Fronting Bank hereunder. A certificate as to such amounts submitted to each Borrower and the Administrative Agent by such Lender or such Fronting Bank (as the case may be) shall constitute such demand and shall be conclusive and binding for all purposes, absent manifest error.

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(c) Each Borrower shall be liable for its pro rata share of each payment to be made by the Borrowers under subsections (a) and (b) of this Section 2.13, determined on the basis of such Borrower’s Fraction; provided, however, that if and to the extent that any such liabilities are reasonably determined by the Borrowers (subject to the approval of the Administrative Agent, which approval shall not be unreasonably withheld) to be directly attributable to Advances made to a specific Borrower, then only such Borrower shall be liable for such payments.

(d) Failure or delay on the part of any Lender or Fronting Bank to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s or Fronting Bank’s right to demand such compensation, provided that the Borrowers shall not be required to compensate a Lender or Fronting Bank pursuant to this Section for any increased costs or additional amounts incurred more than 180 days prior to the date that such Lender or Fronting Bank notifies the Borrowers of such Lender’s or Fronting Bank’s intention to claim such compensation (except that, if such Change in Law giving rise to such increased costs is retroactive, then the 180-day period referred to above shall be extended to include the period of retroactive effect thereof).

SECTION 2.14. Illegality.

Notwithstanding any other provision of this Agreement, if any Lender shall notify the Administrative Agent that the introduction of or any change in or in the interpretation of any law or regulation makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for any Lender or its Eurodollar Lending Office to perform its obligations hereunder to make Eurodollar Rate Advances or to fund or maintain Eurodollar Rate Advances hereunder, (i) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrowers and the Lenders that the circumstances causing such suspension no longer exist and (ii) the Borrowers shall forthwith prepay in full all Eurodollar Rate Advances of all Lenders then outstanding, together with interest accrued thereon, unless (A) the Borrowers, within five Business Days of notice from the Administrative Agent, Converts all Eurodollar Rate Advances of all Lenders then outstanding into Advances of another Type in accordance with Section 2.11 or (B) the Administrative Agent notifies the Borrowers that the circumstances causing such prepayment no longer exist. Any Lender that becomes aware of circumstances that would permit such Lender to notify the Administrative Agent of any illegality under this Section 2.14 shall use its best efforts (consistent with its internal policy and legal and regulatory restrictions) to change the jurisdiction of its Applicable Lending Office if the making of such change would avoid or eliminate such illegality and would not, in the reasonable judgment of such Lender, be otherwise disadvantageous to such Lender.

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SECTION 2.15. Payments and Computations.

(a) Each Borrower shall make each payment hereunder and under any Note not later than 12:00 noon (New York time) on the day when due in Dollars to the Administrative Agent or, with respect to payments made in respect of Reimbursement Obligations, to the applicable Fronting Bank, at its address referred to in Section 8.02 in same day funds, without set-off, counterclaim or defense and any such payment to the Administrative Agent or any Fronting Bank (as the case may be) shall constitute payment by such Borrower hereunder or under any Note, as the case may be, for all purposes, and upon such payment the Lenders shall look solely to the Administrative Agent or such Fronting Bank (as the case may be) for their respective interests in such payment. The Administrative Agent or such Fronting Bank (as the case may be) will promptly after any such payment cause to be distributed like funds relating to the payment of principal or interest or commitment fees or Reimbursement Obligations ratably (other than amounts payable pursuant to Section 2.02(c), 2.05, 2.09, 2.11(c), 2.13, 2.16, 2.21 or 8.05(b)) (according to the Lenders’ respective Commitments) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 8.08(d), from and after the effective date specified in such Assignment and Assumption, the Administrative Agent and each Fronting Bank shall make all payments hereunder and under any Note in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

(b) Each Borrower hereby authorizes each Lender, each Swing Line Lender and each Fronting Bank, if and to the extent payment owed to such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) is not made by such Borrower to the Administrative Agent, such Swing Line Lender or such Fronting Bank (as the case may be) when due hereunder or under any Note held by such Lender, to charge from time to time against any or all of such Borrower’s accounts (other than any payroll account maintained by such Borrower with such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) if and to the extent that such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) shall have expressly waived its set-off rights in writing in respect of such payroll account) with such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) any amount so due.

(c) All computations of interest based on the Alternate Base Rate (based upon JPMCB’s “prime rate”) shall be made by the Administrative Agent on the basis of a year of 365 or 366 days, as the case may be, and all computations of commitment fees and of interest based on the Alternate Base Rate (based upon the Federal Funds Rate or upon clause (iii) of the definition of Alternate Base Rate), the Eurodollar Rate or the Federal Funds Rate shall be made by the Administrative Agent, and all computations of interest pursuant to Section 2.09 shall be made by a Lender, on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such commitment fees or interest are payable. Each determination by the Administrative Agent (or, in the case of Section 2.09, by a Lender) of an interest rate hereunder shall be conclusive and binding for all purposes, absent manifest error.

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(d) Whenever any payment hereunder or under any Note shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or commitment fees, as the case may be; provided, however, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month, such payment shall be made on the next preceding Business Day.

(e) Unless the Administrative Agent shall have received notice from any Borrower prior to the date on which any payment is due to the Lenders hereunder that such Borrower will not make such payment in full, the Administrative Agent may assume that each Borrower has made such payment in full to the Administrative Agent on such date and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent that a Borrower shall not have so made such payment in full to the Administrative Agent, each Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate.

(f) The principal amount of any Advance (or any portion thereof) payable by a Borrower hereunder or under any Note that is not paid when due (whether at stated maturity, by acceleration or otherwise) shall (to the fullest extent permitted by law) bear interest from the date when due until paid in full at a rate per annum equal at all times to the rate otherwise applicable to such Advance plus 2% per annum, payable upon demand. Any other amount payable by a Borrower hereunder or under any Note that is not paid when due (whether at stated maturity, by acceleration or otherwise) shall (to the fullest extent permitted by law) bear interest from the date when due until paid in full at a rate per annum equal at all times to the rate of interest applicable to Alternate Base Rate Advances plus 2% per annum, payable upon demand.

(g) To the extent that any payment by or on behalf of a Borrower is made to the Administrative Agent, any Fronting Bank or any Lender, or the Administrative Agent, any Fronting Bank or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by the Administrative Agent, such Fronting Bank or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding under any bankruptcy, insolvency or other similar law now or hereafter in effect or otherwise, then (i) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (ii) each Lender and each Fronting Bank severally agrees to pay to the Administrative Agent upon demand its applicable share (without duplication) of any amount so recovered from or repaid by the Administrative Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the Federal Funds Rate from time to time in effect. The obligations of the Lenders and the Fronting Banks under clause (ii) of the preceding sentence shall survive the payment in full of any amounts hereunder and the termination of this Agreement.

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SECTION 2.16. Taxes.

(a) Any and all payments by each Borrower hereunder and under any Note or any other Loan Document shall be made, in accordance with Section 2.15, free and clear of and without deduction or withholding for any Indemnified Taxes, and all liabilities with respect thereto. If a Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder or under any Note or any other Loan Document to any Recipient, (i) if such Taxes are Indemnified Taxes, the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 2.16) such Recipient receives an amount equal to the sum it would have received had no such deductions been made, (ii) such Borrower shall make such deductions and (iii) such Borrower shall timely pay or cause to be timely paid the full amount deducted to the relevant Governmental Authority in accordance with Applicable Law.

(b) In addition, each Borrower agrees to timely pay or cause to be timely paid any Other Taxes in accordance with Applicable Law.

(c) Each Borrower agrees to indemnify each Recipient, within 30 days after written demand therefore, for the full amount of Indemnified Taxes (including, without limitation, any Indemnified Taxes imposed by any jurisdiction on amounts payable under this Section 2.16) paid or payable by such Recipient and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally asserted. A certificate as to the amount of such payment or liability delivered to FE by or on behalf of the applicable Recipient shall be conclusive, absent manifest error.

(d) As soon as practicable after any payment of Indemnified Taxes by any Borrower to a Governmental Authority, such Borrower shall deliver to the Administrative Agent an original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e) Tax Forms.

(i) Any Lender that is a U.S. Person shall deliver to each Borrower and the Administrative Agent, on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of such Borrower or the Administrative Agent), duly executed originals of IRS Form W-9 (or copies thereof) certifying, to the extent such Lender is legally entitled to do so, that such Lender is exempt from U.S. federal backup withholding tax.

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(ii) Any Lender that is not a U.S. Person and that is entitled to an exemption from or reduction of withholding tax under the Code or any treaty to which the United States is a party with respect to payments under this Agreement shall deliver to each Borrower and the Administrative Agent, at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by such Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding, as applicable. Without limiting the generality of the foregoing, each Lender that is not a U.S. Person shall, to the extent it is legally entitled to do so, (w) on or prior to the date such Lender becomes a Lender under this Agreement, (x) on or prior to the date on which any such form or certification expires or becomes obsolete, (y) after the occurrence of any event requiring a change in the most recent form or certification previously delivered by it pursuant to this subsection, and (z) from time to time upon the reasonable request by any Borrower or the Administrative Agent, deliver to such Borrower and the Administrative Agent (in such number of copies as shall be requested by such Borrower or the Administrative Agent), whichever of the following is applicable:

(A) if such Lender is claiming eligibility for benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, duly executed originals of IRS Form W-8BEN, or any successor form thereto, establishing an exemption from, or reduction of, U.S. federal withholding tax pursuant to the “interest” article of such tax treaty, and (y) with respect to any other payments under any Loan Document, duly executed originals of IRS Form W-8BEN, or any successor form thereto, establishing an exemption from, or reduction of, U.S. federal withholding tax pursuant to the “business profits” or “other income” article of such tax treaty;

(B) duly executed originals of IRS Form W-8ECI, or any successor form thereto, certifying that the payments received by such Lender are effectively connected with such Lender’s conduct of a trade or business in the United States;

(C) if such Lender is claiming the benefits of the exemption for “portfolio interest” under Section 871(h) or Section 881(c) of the Code, duly executed originals of IRS Form W-8BEN, or any successor form thereto, together with a certificate (a “U.S. Tax Compliance Certificate”) upon which such Lender certifies that (1) such Lender is not a bank for purposes of Section 881(c)(3)(A) of the Code, or the obligation of the Borrower hereunder is not, with respect to such Lender, a loan agreement entered into in the ordinary course of its trade or business, within the meaning of that Section of the Code, (2) such Lender is not a 10% shareholder of the Borrower within the meaning of Section 871(h)(3) or Section 881(c)(3)(B) of the Code, (3) such Lender is not a controlled foreign corporation that is related to the Borrower within the meaning of Section 881(c)(3)(C) of the Code, and (4) the interest payments in question are not effectively connected with a U.S. trade or business conducted by such Lender; or

(D) if such Lender is not the beneficial owner (for example, a partnership or a Lender granting a participation), duly executed originals of IRS Form W-8IMY, or any successor form thereto, accompanied by IRS Form W-9, IRS Form W-8ECI, IRS Form W-8BEN, a U.S. Tax Compliance Certificate, and/or other certification documents from each beneficial owner, as applicable.

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(iii) Each Lender agrees that if any form or certification it previously delivered under this Section 2.16(e) expires or becomes obsolete or inaccurate in any respect and such Lender is not legally entitled to provide an updated form or certification, it shall promptly notify the Borrowers and the Administrative Agent of its inability to update such form or certification.

(f) If a payment made to a Lender hereunder or under any other Loan Document would be subject to U.S. Federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to each Borrower and the Administrative Agent, at the time or times prescribed by law and at such time or times reasonably requested by any Borrower or the Administrative Agent, such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by such Borrower or the Administrative Agent as may be necessary for each of the Borrowers and the Administrative Agent to comply with its obligations under FATCA, to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment.

(g) Any Lender claiming any additional amounts payable pursuant to this Section 2.16 shall use its best efforts (consistent with its internal policy and legal and regulatory restrictions) to change the jurisdiction of its Applicable Lending Office if the making of such a change would avoid the need for, or reduce the amount of, any such additional amounts that may thereafter accrue and would not, in the reasonable judgment of such Lender, be otherwise disadvantageous to such Lender.

(h) Without prejudice to the survival of any other agreement of the Borrowers hereunder, the agreements and obligations of the Borrowers contained in this Section 2.16 shall survive the payment in full of principal and interest hereunder and under any Note.

SECTION 2.17. Sharing of Payments, Etc.

(a) If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Advances made by it or participations in Letters of Credit acquired by it (other than pursuant to Section 2.02(c), 2.09, 2.11(c), 2.13, 2.16, 2.21 or 8.05(b)) in excess of its ratable share of payments on account of the Advances or Letters of Credit (as the case may be) obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participations in the Advances made by them or participations in Letters of Credit acquired by them (as the case may be) as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s ratable share (according to the proportion of (a) the amount of such Lender’s required repayment to (b) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. Each Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.17 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of such Borrower in the amount of such participation.

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(b) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.02(c), 2.03(c), 2.04(j) or 7.05, then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent for the account of such Lender for the benefit of the Administrative Agent, any Swing Line Lender or any Fronting Bank to satisfy such Lender’s obligations to it under such Section until all such unsatisfied obligations are fully paid, and/or (ii) hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

SECTION 2.18. Noteless Agreement; Evidence of Indebtedness.

(a) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of each Borrower to such Lender resulting from each Advance made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

(b) The Administrative Agent shall also maintain accounts in which it will record (i) the amount of each Advance made hereunder, the Borrower thereof, the Type thereof and the Interest Period (if any) with respect thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from such Borrower to each Lender hereunder, and (iii) the amount of any sum received by the Administrative Agent hereunder from each Borrower and each Lender’s share thereof.

(c) Subject to Section 8.08(c), the entries maintained in the accounts maintained pursuant to subsections (a) and (b) above shall be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of the Administrative Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of each Borrower to repay such obligations in accordance with their terms.

(d) Any Lender may request that its Advances be evidenced by a Note. In such event, each Borrower shall prepare, execute and deliver to such Lender a Note payable to such Lender and its registered assigns. Thereafter, the Advances evidenced by such Note and interest thereon shall at all times (including after any assignment pursuant to Section 8.08) be represented by one or more Notes payable to the payee named therein, or to its registered assigns pursuant to Section 8.08, except to the extent that any such Lender or assignee subsequently returns any such Note for cancellation and requests that such Borrowings once again be evidenced as described in subsections (a) and (b) above.

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SECTION 2.19. Extension of Termination Date.

(a) The Borrowers may, by notice to the Administrative Agent (which shall promptly notify the Lenders) not earlier than 45 days prior to any anniversary of the date of this Agreement (the “Anniversary Date”) but no later than 30 days prior to such anniversary of the Closing Date (the date of delivery of any such notice being the “Borrower Extension Notice Date”), request that each Lender extend such Lender’s Termination Date for an additional one year after the Termination Date then in effect for such Lender hereunder (the “Existing Termination Date”). The Borrowers may request no more than two extensions pursuant to this Section.

(b) Each Lender, acting in its sole and individual discretion, shall, by notice to the Administrative Agent given not earlier than 30 days prior to the applicable Anniversary Date and not later than the date (the “Lender Extension Notice Date”) that is 20 days prior to the Applicable Anniversary Date, advise the Administrative Agent whether or not such Lender agrees to such extension (and each Lender that determines not to so extend its Existing Termination Date (a “Nonconsenting Lender”) shall notify the Administrative Agent of such fact promptly after such determination (but in any event no later than the Lender Extension Notice Date), and any Lender that does not so advise the Administrative Agent on or before the Lender Extension Notice Date shall be deemed to be a Nonconsenting Lender. The election of any Lender to agree to such extension shall not obligate any other Lender to so agree.

(c) The Administrative Agent shall notify the Borrowers of each Lender’s determination under this Section no later than the date 15 days prior to the applicable Anniversary Date, or, if such date is not a Business Day, on the next preceding Business Day (the “Specified Date”).

(d) The Borrowers shall have the right on or before the fifth Business Day after the Specified Date to replace each Nonconsenting Lender (i) with an existing Lender, and/or (ii) by adding as “Lenders” under this Agreement in place thereof, one or more Persons (each Lender in clauses (i) and (ii), an “Additional Commitment Lender”), in each case, with the approval of the Administrative Agent, the Swing Line Lenders and the Fronting Banks (which approvals shall not be unreasonably withheld), each of which Additional Commitment Lenders shall have entered into an agreement in form and substance satisfactory to the Borrowers and the Administrative Agent pursuant to which such Additional Commitment Lender shall, effective as of the Specified Date, undertake a Commitment (and, if any such Additional Commitment Lender is already a Lender, its Commitment shall be in addition to such Lender’s Commitment hereunder on such date); provided that the aggregate amount of the Commitments for all Additional Commitment Lenders shall be no more than the aggregate amount of the Commitments of all Nonconsenting Lenders; provided, further, that the existing Lenders shall have the right to increase their Commitments up to the amount of the Nonconsenting Lenders’ Commitments before the Borrowers shall have the right to substitute any other Person for any Nonconsenting Lender.

(e) If (and only if) the aggregate amount of the Commitments of the Lenders that have agreed to extend their Existing Termination Dates plus the aggregate additional Commitments of the Additional Commitment Lenders shall be more than 50% of the aggregate amount of the Commitments in effect immediately prior to the Specified Date, then, effective as of the Specified Date, the Existing Termination Date of each Lender agreeing to an extension and of each Additional Commitment Lender shall be extended to the date that is one year after the Existing Termination Date, and each Additional Commitment Lender shall thereupon become a “Lender” for all purposes of this Agreement.

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(f) Notwithstanding the foregoing, the extension of a Lender’s Existing Termination Date pursuant to this Section shall be effective with respect to such Lender on the Specified Date but only if (i) the following statements shall be true: (A) no event has occurred and is continuing, or would result from the extension of the Existing Termination Date, that constitutes an Event of Default or an Unmatured Default and (B) the representations and warranties contained in Section 4.01 (other than the first sentence of subsection (g) thereof but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended) are correct in all material respects on and as of the Specified Date, before and after giving effect to such extension, as though made on and as of such date, except for those made specifically as of another date, in which case such representations and warranties shall be true as of such other date, provided that, for purposes of the representations and warranties in Sections 4.01(f) and the last sentence of 4.01(g), the Disclosure Documents shall include all the SEC filings made by FE and the Borrowers prior to the applicable Borrower Extension Notice Date and (ii) on or prior to the Specified Date the Administrative Agent shall have received the following, each dated the Specified Date and in form and substance satisfactory to the Administrative Agent: (x) a certificate of an Authorized Officer of each Borrower to the effect that as of the Specified Date the statements set forth in clauses (A) and (B) above are true, (y) certified copies of the resolutions of the Board of Directors of each Borrower authorizing such extension and the performance of this Agreement on and after the Specified Date, and of all documents evidencing other necessary corporate action and Governmental Action with respect to this Agreement and such extension of the Existing Termination Date and (z) an opinion of counsel to the Borrowers, as to such matters related to the foregoing as the Administrative Agent or the Lenders through the Administrative Agent may reasonably request.

(g) Subject to subsection (d) above, the Commitment of any Nonconsenting Lender shall automatically terminate on its Existing Termination Date (without regard to any extension by any other Lender).

(h) Each Swing Line Lender and Fronting Bank may, in its sole discretion, elect not to serve in such capacity following any extension of the Termination Date; provided that, (i) the Borrowers and the Administrative Agent may appoint a replacement for any such resigning Swing Line Lender or Fronting Bank and (ii) the extension of the Termination Date may become effective without regard to whether such replacement is found.

SECTION 2.20. Several Obligations.

Each Borrower’s obligations hereunder are several and not joint. Any action taken by or on behalf of the Borrowers shall not result in one Borrower being held responsible for the actions, debts or liabilities of the other Borrowers. Nothing contained herein shall be interpreted as requiring the Borrowers to effect Borrowings jointly.

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SECTION 2.21. Defaulting Lenders.

Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a) fees shall cease to accrue on the Percentage of such Defaulting Lender in the unused portion of each Borrower’s Borrower Sublimit pursuant to Section 2.05(a);

(b) the Commitment and Outstanding Credits of such Defaulting Lender shall not be included in determining whether (i) the Majority Lenders have taken or may take any action under this Agreement or (ii) all Lenders affected thereby have taken or may take any action under this Agreement, except to the extent Section 8.01 requires the consent of all Lenders affected thereby (and does not otherwise exclude the Defaulting Lenders from such required consent) to an amendment, waiver or other modification;

(c) if any Swing Line Advance, Letter of Credit or Reimbursement Obligation is outstanding at the time such Lender becomes a Defaulting Lender then:

(i) all or any part of the obligation of such Defaulting Lender to participate in such Swing Line Advance, Letter of Credit or Reimbursement Obligation shall be reallocated among the non-Defaulting Lenders in accordance with their respective Percentages but only to the extent that (x) the sum of all non-Defaulting Lenders’ Outstanding Credits does not exceed the total of all non-Defaulting Lenders’ Commitments and (y) the conditions set forth in Section 3.02 are satisfied at such time;

(ii) if the reallocation described in clause (i) above cannot, or can only partially, be effected, each Borrower shall within one Business Day following notice by the Administrative Agent (x) first, prepay its Swing Line Advances, if any, and (y) second, cash collateralize for the benefit of the applicable Fronting Banks only such Borrower’s obligations, if any, corresponding to such Defaulting Lender’s obligation to participate in Letters of Credit (after giving effect to any partial reallocation pursuant to clause (i) above) in a manner reasonably satisfactory to the Administrative Agent and such Fronting Banks for so long as such LC Exposure is outstanding;

(iii) if and to the extent that any Borrower cash collateralizes any portion of such Defaulting Lender’s obligation to participate in Letters of Credit pursuant to clause (ii) above, such Borrower shall not be required to pay any fees to such Defaulting Lender pursuant to Section 2.05(c) with respect to such Defaulting Lender’s Percentage of the Stated Amount of all Letters of Credit during the period such Defaulting Lender’s obligation is cash collateralized;

(iv) if the obligation of the non-Defaulting Lenders to participate in Letters of Credit is reallocated pursuant to clause (i) above, then the fees payable to the Lenders pursuant to Section 2.05(c) shall be adjusted in accordance with such non-Defaulting Lenders’ Percentages; and

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(v) if all or any portion of the obligation of the non-Defaulting Lenders to participate in Letters of Credit is neither reallocated nor cash collateralized pursuant to clause (i) or (ii) above, then, without prejudice to any rights or remedies of any Fronting Bank or any other Lender hereunder, all fees payable under Section 2.05(c) with respect to such Defaulting Lender’s Percentage of the Stated Amount of all Letters of Credit shall be payable to the applicable Fronting Banks until and to the extent that such obligation is reallocated and/or cash collateralized; and

(d) so long as such Lender is a Defaulting Lender, no Swing Line Lender shall be required to fund any Swing Line Advance, and no Fronting Bank shall be required to make any Extension of Credit in connection with a Letter of Credit, unless it is satisfied that the related exposure and the Defaulting Lender’s then outstanding obligations to participate in such Letter of Credit will be 100% covered by the Commitments of the non-Defaulting Lenders and/or cash collateral will be provided by the applicable Borrower in accordance with subsection (c) above, and participating interests in any newly made Swing Line Advance or any new Extension of Credit relating to a Letter of Credit shall be allocated among non-Defaulting Lenders in a manner consistent with subsection (c)(i) above (and such Defaulting Lender shall not participate therein).

If a Bankruptcy Event with respect to a Parent of any Lender shall occur following the date hereof and for so long as such event shall continue, then no Swing Line Lender shall be required to fund any Swing Line Advance, and no Fronting Bank shall be required to issue, amend or increase any Letter of Credit, unless such Swing Line Lender or Fronting Bank, as the case may be, shall have entered into arrangements with the applicable Borrower or such Lender reasonably satisfactory to such Swing Line Lender or Fronting Bank, as the case may be, to defease any risk to it in respect of such Lender hereunder.

In the event that the Administrative Agent, the applicable Borrower, the Swing Line Lenders and the Fronting Banks all agree that a Defaulting Lender has adequately remedied all matters that caused such Lender to be a Defaulting Lender, then the obligation of such Lender to participate in Swing Line Advances made to such Borrower and Letters of Credit for the account of such Borrower shall be readjusted to reflect the inclusion of such Lender’s Commitment and on such date such Lender shall purchase at par such of the Advances of the other Lenders (other than Swing Line Advances) as the Administrative Agent shall determine may be necessary in order for such Lender to hold such Advances in accordance with its Percentage.

ARTICLE III
CONDITIONS OF LENDING AND ISSUING LETTERS OF CREDIT

SECTION 3.01. Conditions Precedent to Initial Extension of Credit.

The obligation of each Lender and each Swing Line Lender to make its initial Advance to any Borrower, and the obligation of each Fronting Bank to issue its initial Letter of Credit, are subject to the conditions precedent that on or before the date of any such Extension of Credit:

(a) The Administrative Agent shall have received the following, each dated the same date (except for the financial statements referred to in paragraph (iv)), in form and substance satisfactory to the Administrative Agent and (except for any Note) with one copy for each Swing Line Lender, each Fronting Bank and each Lender:

(i) This Agreement, duly executed by each of the parties hereto, and Notes requested by any Lender pursuant to Section 2.18(d), duly completed and executed by each Borrower and payable to the order of such Lender;

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(ii) Certified copies of the resolutions of the Board of Directors of each Borrower (or the equivalent authorization, in the case of Allegheny) approving this Agreement and the other Loan Documents to which it is, or is to be, a party and of all documents evidencing any other necessary corporate action with respect to this Agreement and such Loan Documents;

(iii) A certificate of the Secretary or an Assistant Secretary of each Borrower certifying (A) the names and true signatures of the officers of such Borrower authorized to sign each Loan Document to which such Borrower is, or is to become, a party and the other documents to be delivered hereunder; (B) that attached thereto are true and correct copies of the Organizational Documents of such Borrower, in each case as in effect on such date; (C) that attached thereto are true and correct copies of all governmental and regulatory authorizations and approvals (including such Borrower’s Approval) required for the due execution, delivery and performance by such Borrower of this Agreement and each other Loan Document to which such Borrower is, or is to become, a party and (D) solely with respect to the certificate of FES, that attached thereto are true and correct copies of the Genco Guarantees;

(iv) Copies of all the Disclosure Documents (it being agreed that those Disclosure Documents publicly available on the SEC’s EDGAR Database or on FE’s website no later than the Business Day immediately preceding the date of such Extension of Credit will be deemed to have been delivered under this clause (iv));

(v) An opinion of Wendy E. Stark, Associate General Counsel of FE, counsel for the Borrowers, substantially in the form of Exhibit F hereto;

(vi) An opinion of Akin Gump Strauss Hauer & Feld LLP, special counsel for the Borrowers, substantially in the form of Exhibit G hereto;

(vii) A favorable opinion of King & Spalding LLP, special New York counsel for the Administrative Agent, substantially in the form of Exhibit H hereto; and

(viii) Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent, such Fronting Bank, such Swing Line Lender or such other Lender (as the case may be).

(b) The Borrowers and each Fronting Bank shall have entered into an agreement, in form and substance satisfactory to such Fronting Bank, concerning fees payable by the Borrower to such Fronting Bank for its own account (the “Fronting Bank Fee Letters”).

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(c) The Borrowers shall have paid all of the fees payable in accordance with the Fee Letters, and the Borrowers shall have paid all the fees payable in accordance with the Fronting Bank Fee Letters.

(d) All amounts outstanding under the Existing Facilities, whether for principal, interest, fees or otherwise, shall have been paid in full, all commitments to lend thereunder shall have been terminated, and the Existing Facilities shall have been terminated.

(e) The Administrative Agent shall have received all documentation and information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including without limitation the Patriot Act, to the extent such documentation or information is requested by the Administrative Agent on behalf of the Lenders prior to the date hereof.

SECTION 3.02. Conditions Precedent to Each Extension of Credit.

The obligation of each Lender and each Swing Line Lender to make an Advance to any Borrower as part of any Borrowing (including the initial Borrowing) that would increase the aggregate principal amount of Advances outstanding hereunder, and the obligation of each Fronting Bank to issue, amend, extend or renew a Letter of Credit (including the initial Letter of Credit for the account of such Borrower), in each case, as part of an Extension of Credit, shall be subject to the further conditions precedent that on the date of such Extension of Credit:

(i) The following statements shall be true (and each of the giving of the applicable Notice of Pro-Rata Borrowing, Notice of Swing Line Borrowing or Letter of Credit Request and the acceptance by such Borrower of the proceeds of such Borrowing or the acceptance of a Letter of Credit by the Beneficiary thereof, as the case may be, shall constitute a representation and warranty by such Borrower that on the date of such Extension of Credit such statements are true):

(A) The representations and warranties of such Borrower contained in Section 4.01 (other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof with respect to any Extension of Credit following the initial Extension of Credit) hereof are true and correct on and as of the date of such Extension of Credit, before and after giving effect to such Extension of Credit and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of such Extension of Credit, in which case, such representation and warranty shall be true and correct as of such specific date);

(B) No event has occurred and is continuing, or would result from such Extension of Credit or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower; and

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(C) Immediately following such Extension of Credit, (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment, (3) the aggregate principal amount of Advances outstanding for such Borrower shall not exceed the amounts authorized under such Borrower’s Approval, (4) the Outstanding Credits for the account of any Borrower shall not exceed the Borrower Sublimit for such Borrower, (5) the aggregate principal amount of the Swing Line Advances outstanding shall not exceed the Swing Line Sublimit, and (6) if such Extension of Credit relates to a Letter of Credit, the Stated Amount thereof, when aggregated with (x) the Stated Amount of each other Letter of Credit that is outstanding or with respect to which a Letter of Credit Request has been received and (y) the outstanding Reimbursement Obligations, shall not exceed the L/C Commitment Amount; and

(ii) Such Borrower shall have delivered to the Administrative Agent copies of such other approvals and documents as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any other Lender (through the Administrative Agent) may reasonably request.

ARTICLE IV
REPRESENTATIONS AND WARRANTIES

SECTION 4.01. Representations and Warranties of the Borrowers.

Each Borrower represents and warrants as follows:

(a) Existence and Power. It is a corporation or limited liability company, as the case may be, duly formed, validly existing and in good standing under the laws of the jurisdiction of its formation, is duly qualified to do business as a foreign corporation or limited liability company in and is in good standing under the laws of each state in which the ownership of its properties or the conduct of its business makes such qualification necessary, except where the failure to be so qualified would not reasonably be expected to have a Material Adverse Effect with respect to such Borrower, and has all corporate or limited liability company powers and all governmental licenses, authorizations, consents and approvals required to carry on its business as now conducted except where the failure to do so, in each case, would not reasonably be expected to have a Material Adverse Effect.

(b) Due Authorization. The execution, delivery and performance by it of each Loan Document to which it is, or is to become, a party, have been duly authorized by all necessary corporate action on its part and do not, and will not, require the consent or approval of its shareholders or members, as the case may be, other than such consents and approvals as have been duly obtained, given or accomplished.

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(c) No Violation, Etc. Neither the execution, delivery or performance by it of this Agreement or any other Loan Document to which it is, or is to become, a party, nor the consummation by it of the transactions contemplated hereby or thereby, nor compliance by it with the provisions hereof or thereof, contravenes or will contravene, or results or will result in a breach of, any of the provisions of its Organizational Documents, any Applicable Law, or any indenture, mortgage, lease or any other agreement or instrument to which it or any of its Subsidiaries is party or by which its property or the property of any of its Subsidiaries is bound, or results or will result in the creation or imposition of any Lien upon any of its property or the property of any of its Subsidiaries except as provided herein, except to the extent such contravention or breach, or the creation or imposition of any such Lien, individually or in the aggregate, has not had and would not reasonably be expected to have a Material Adverse Effect with respect to such Borrower. Each Borrower and each of its Subsidiaries is in compliance with all laws (including, without limitation, ERISA and Environmental Laws), regulations and orders of any Governmental Authority applicable to it or its property and all indentures, agreements and other instruments binding upon it or its property, except where the failure to do so, individually or in the aggregate, has not had and would not reasonably be expected to have a Material Adverse Effect with respect to such Borrower.

(d) Governmental Actions. No Governmental Action is or will be required in connection with the execution, delivery or performance by it, or the consummation by it of the transactions contemplated by this Agreement or any other Loan Document to which it is, or is to become, a party other than such Borrower’s Approval, as applicable, which has been duly issued and is in full force and effect.

(e) Execution and Delivery. This Agreement and the other Loan Documents to which it is, or is to become, a party have been or will be (as the case may be) duly executed and delivered by it, and this Agreement is, and upon execution and delivery thereof each other Loan Document will be, the legal, valid and binding obligation of it enforceable against it in accordance with its terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally.

(f) Litigation. Except as disclosed in such Borrower’s Disclosure Documents, there is no pending or, to such Borrower’s knowledge, threatened action or proceeding (including, without limitation, any proceeding relating to or arising out of Environmental Laws) affecting such Borrower or any of its Subsidiaries before any court, governmental agency or arbitrator that would reasonably be expected to have a Material Adverse Effect with respect to such Borrower.

(g) Financial Statements; Material Adverse Change. The consolidated balance sheets of such Borrower and its Subsidiaries, as at December 31, 2010, and the related consolidated statements of income, retained earnings and cash flows of such Borrower and its Subsidiaries, certified by PricewaterhouseCoopers LLP or Deloitte & Touche LLP, as applicable, independent public accountants, and the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows of such Borrower and its Subsidiaries, for the three months then ended, copies of which have been furnished to each Lender, each Swing Line Lender and each Fronting Bank, in all cases as amended and restated to the date hereof, present fairly in all material respects the consolidated financial position of such Borrower and its Subsidiaries as at the indicated dates and the consolidated results of the operations of such Borrower and its Subsidiaries for the periods ended on the indicated dates, all in accordance with GAAP consistently applied (in the case of such statements that are unaudited, subject to year-end adjustments and the exclusion of detailed footnotes). Except as disclosed in such Borrower’s Disclosure Documents, there has been no change, event or occurrence since December 31, 2010 that has had a Material Adverse Effect with respect to such Borrower.

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(h) ERISA. Except as would not reasonably be expected to have a Material Adverse Effect:

(i) No Termination Event has occurred or is reasonably expected to occur with respect to any Plan.

(ii) Schedule B (Actuarial Information) to the most recent annual report (Form 5500 Series) with respect to each Plan, copies of which have been filed with the Internal Revenue Service and furnished (or made available) to the Banks, (A) is complete and accurate, (B) fairly presents the funding status of such Plan, and (C) since the date of such Schedule B there has been no change in such funding status.

(iii) Neither it nor any member of the Controlled Group has incurred or reasonably expects to incur any withdrawal liability under ERISA to any Multiemployer Plan.

(i) Margin Stock. After applying the proceeds of each Extension of Credit, not more than 25% of the value of the assets of such Borrower and its Subsidiaries subject to the restrictions of Section 5.03(a) or (b) will consist of or be represented by Margin Stock. Such Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying Margin Stock, and no proceeds of any Extension of Credit will be used to purchase or carry any Margin Stock or to extend credit to others for the purpose of purchasing or carrying any Margin Stock.

(j) Investment Company. Such Borrower is not an “investment company” or a company “controlled” by an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

(k) No Event of Default. No event has occurred and is continuing that constitutes an Event of Default or an Unmatured Default in each case with respect to such Borrower.

(l) No Material Misstatements. The reports, financial statements and other written information furnished by or on behalf of such Borrower to the Administrative Agent, any Fronting Bank or any Lender pursuant to or in connection with the Loan Documents and the transactions contemplated thereby, when taken together with such Borrower’s Disclosure Documents, do not contain and will not contain, when taken as a whole, any untrue statement of a material fact and do not omit and will not omit, when taken as a whole, to state any fact necessary to make the statements therein, in the light of the circumstances under which they were or will be made, not misleading in any material respect.

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(m) Genco Guarantees. All Indebtedness of FES (including, without limitation, its Indebtedness under the Loan Documents and pursuant to the FES-FGC Guaranty) is guaranteed by NGC pursuant to the NGC-FES Guaranty; and all Indebtedness of FES (including, without limitation, its Indebtedness under the Loan Documents and pursuant to the FES-NGC Guaranty) is guaranteed by FGC pursuant to the FGC-FES Guaranty.

ARTICLE V
COVENANTS OF THE BORROWERS

SECTION 5.01. Affirmative Covenants of the Borrowers.

Unless the Majority Lenders shall otherwise consent in writing, so long as any amount payable by any Borrower hereunder shall remain unpaid, any Letter of Credit shall remain outstanding or any Lender shall have any Commitment hereunder, such Borrower will:

(a) Preservation of Corporate Existence, Etc. (i) Without limiting the right of such Borrower to merge with or into or consolidate with or into any other corporation or entity in accordance with the provisions of Section 5.03(c) hereof, preserve and maintain its corporate or limited liability company (as the case may be) existence, (ii) qualify and remain qualified as a foreign corporation or limited liability company (as the case may be) in each jurisdiction in which such qualification is reasonably necessary in view of its business and operations or the ownership of its properties and (iii) preserve, renew and keep in full force and effect the rights, privileges and franchises necessary or desirable in the normal conduct of its business, except, in the case of clauses (ii) and (iii) above, to the extent that failure to do so would not reasonably be expected to result in a Material Adverse Effect with respect to such Borrower; provided, however, that any Borrower may change its form of organization from a corporation to a limited liability company or from a limited liability company to a corporation if the Administrative Agent is reasonably satisfied that such change shall not affect any obligations of such Borrower under the Loan Documents.

(b) Compliance with Laws, Etc. Comply, and cause each of its Subsidiaries to comply, in all material respects with all applicable laws, rules, regulations, and orders of any Governmental Authority, the noncompliance with which would not reasonably be expected to result in a Material Adverse Effect with respect to such Borrower, such compliance to include, without limitation, compliance with the Patriot Act, regulations promulgated by the U.S. Treasury Department Office of Foreign Assets Control, Environmental Laws and ERISA and paying before the same become delinquent all material taxes, assessments and governmental charges imposed upon it or upon its property, except to the extent compliance with any of the foregoing is then being contested in good faith by appropriate legal proceedings.

(c) Maintenance of Insurance, Etc. Maintain insurance with responsible and reputable insurance companies or associations or through its own program of self-insurance in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties in the same general areas in which such Borrower operates.

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(d) Inspection Rights. At any reasonable time and from time to time as the Administrative Agent, any Swing Line Lender, any Fronting Bank or any Lender may reasonably request (upon five Business Days’ prior notice delivered to the applicable Borrower and no more than once a year, unless an Event of Default has occurred and is continuing), permit the Administrative Agent, such Fronting Bank or such Lender or any agents or representatives thereof to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, such Borrower and any of its Subsidiaries, and to discuss the affairs, finances and accounts of such Borrower and any of its Subsidiaries with any of their respective officers or directors; provided, however, that (x) such Borrower reserves the right to restrict access to any of its Subsidiaries’ facilities in accordance with reasonably adopted procedures relating to safety and security and (y) neither Borrower nor any of its Subsidiaries shall be required to disclose to the Administrative Agent, any Swingline Lender, any Fronting Bank or any Lender or any agents or representatives thereof any information that is the subject of attorney-client privilege or attorney work-product privilege properly asserted by the applicable Person to prevent the loss of such privilege in connection with such information or that is prevented from disclosure pursuant to a confidentiality agreement with third parties (provided that such Borrower agrees to use commercially reasonable efforts to obtain any required third-party consent to such disclosure, subject to customary nondisclosure restrictions applicable to the Administrative Agent, any Swingline Lender, any Fronting Bank or the Lenders, as applicable). The Administrative Agent, each Swing Line Lender, each Fronting Bank and each Lender agree to use reasonable efforts to ensure that any information concerning such Borrower or any of its Subsidiaries obtained by the Administrative Agent, such Fronting Bank or such Lender pursuant to this subsection (d) or subsection (g) that is not contained in a report or other document filed with the SEC, distributed by such Borrower or FE to its security holders or otherwise generally available to the public, will, to the extent permitted by law and except as may be required by valid subpoena or in the normal course of the Administrative Agent’s, such Swing Line Lender’s, such Fronting Bank’s or such Lender’s business operations be treated confidentially by the Administrative Agent, such Swing Line Lender, such Fronting Bank or such Lender, as the case may be, and will not be distributed or otherwise made available by the Administrative Agent, such Swing Line Lender, such Fronting Bank or such Lender, as the case may be, to any Person, other than the Administrative Agent’s, such Swing Line Lender’s, such Fronting Bank’s or such Lender’s employees, authorized agents or representatives (including, without limitation, attorneys and accountants).

(e) Keeping of Books. Keep, and cause each Subsidiary to keep, proper books of record and account in which entries shall be made of all financial transactions and the assets and business of such Borrower and each of its Subsidiaries in accordance with GAAP.

(f) Maintenance of Properties. Maintain and preserve, and cause each of its Subsidiaries to maintain and preserve, all of its properties (except such properties the failure of which to maintain or preserve would not have, individually or in the aggregate, a Material Adverse Effect with respect to such Borrower) that are used or that are useful in the conduct of its business in good working order and condition, ordinary wear and tear excepted, and in accordance with prudent industry practices applicable to the industry of such Borrower, in all material respects, and (subject to (b) above) applicable law it being understood that this covenant relates only to the good working order and condition of such properties and shall not be construed as a covenant of such Borrower or any of its Subsidiaries not to dispose of such properties by sale, lease, transfer or otherwise.

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(g) Reporting Requirements. Furnish, or cause to be furnished, to the Administrative Agent, with sufficient copies for each Lender and each Fronting Bank, the following:

(i) promptly after becoming aware of the occurrence of any Event of Default with respect to such Borrower continuing on the date of such statement, the statement of an Authorized Officer of such Borrower setting forth details of such Event of Default and the action that such Borrower has taken or proposes to take with respect thereto;

(ii) as soon as available and in any event within 60 days after the close of each of the first three quarters in each fiscal year of such Borrower, consolidated balance sheets of such Borrower and its Subsidiaries as at the end of such quarter and consolidated statements of income of such Borrower and its Subsidiaries for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, fairly presenting in all material respects the financial condition of such Borrower and its Subsidiaries as at such date and the results of operations of such Borrower and its Subsidiaries for such period and setting forth in each case in comparative form the corresponding figures for the corresponding period of the preceding fiscal year, all in reasonable detail and duly certified (subject to year-end audit adjustments) by the chief financial officer, treasurer, assistant treasurer or controller of such Borrower as having been prepared in accordance with GAAP consistently applied (in the case of such statements that are unaudited, subject to year-end adjustments and the exclusion of detailed footnotes);

(iii) as soon as available and in any event within 105 days after the end of each fiscal year of such Borrower, a copy of the annual report for such year for such Borrower and its Subsidiaries, containing consolidated and consolidating financial statements of such Borrower and its Subsidiaries for such year certified by PricewaterhouseCoopers LLP, Deloitte & Touche LLP or other independent public accountants of recognized national standing as fairly presenting, in all material respects, the financial position of such Borrower and its Subsidiaries as at the end of such year and the results of their operations and their cash flows for the three-year period (or, if such Borrower is not then required to file reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, the two-year period) ending as at the end of such year in conformity with GAAP;

(iv) concurrently with the delivery of the financial statements specified in clauses (ii) and (iii) above a certificate of the chief financial officer, treasurer, assistant treasurer or controller of such Borrower (A) stating whether such Borrower has any knowledge of the occurrence and continuance at the date of such certificate of any Event of Default not theretofore reported pursuant to the provisions of clause (i) of this subsection (g), and, if so, stating the facts with respect thereto, and (B) setting forth in a true and correct manner, the calculation of the ratio contemplated by Section 5.02 hereof, as of the date of the most recent financial statements accompanying such certificate, to show such Borrower’s compliance with or the status of the financial covenant contained in Section 5.02 hereof;

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(v) promptly after the sending or filing thereof, copies of any reports that such Borrower sends to any of its securityholders, and copies of all reports on Form 10-K, Form 10-Q or Form 8-K, if any, that such Borrower or any of its Subsidiaries files with the SEC;

(vi) as soon as possible and in any event within 20 days after such Borrower or any member of the Controlled Group knows or has reason to know that any Termination Event with respect to any Plan has occurred or is reasonably likely to occur, that would reasonably be expected to result in liability exceeding $100,000,000 to such Borrower or such member of the Controlled Group, a statement of the chief financial officer of such Borrower describing such Termination Event and the action, if any, that such Borrower or such member of the Controlled Group, as the case may be, proposes to take with respect thereto;

(vii) promptly upon reasonable request by the Administrative Agent or any Lender, after the filing thereof with the Internal Revenue Service, copies of each Schedule B (Actuarial Information) to the annual report (Form 5500 Series) with respect to each Plan;

(viii) promptly upon request and in any event within five Business Days after receipt thereof by such Borrower or any member of the Controlled Group from a Multiemployer Plan sponsor, a copy of each notice received by such Borrower or such member of the Controlled Group concerning the imposition of withdrawal liability pursuant to Section 4202 of ERISA;

(ix) promptly and in any event within five Business Days after Moody’s or S&P has changed any relevant Reference Rating, notice of such change; and

(x) such other information respecting the condition or operations, financial or otherwise, of such Borrower or any of its Subsidiaries, including, without limitation, copies of all reports and registration statements that such Borrower or any Subsidiary files with the SEC or any national securities exchange, as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any Lender (through the Administrative Agent) may from time to time reasonably request.

The financial statements and reports described in paragraphs (ii), (iii) and (v) above will be deemed to have been delivered hereunder if publicly available on the SEC’s EDGAR Database or on FE’s website no later than the date specified for delivery of same under paragraph (ii), (iii) or (v), as applicable, above. If any financial statements or report described in (ii) and (iii) above is due on a date that is not a Business Day, then such financial statements or report shall be delivered on the next succeeding Business Day.

(h) Borrower Approvals. Maintain such Borrower’s Approval in full force and effect and comply with all terms and conditions thereof until all amounts outstanding under the Loan Documents shall have been repaid or paid (as the case may be) and the Termination Date has occurred.

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(i) Subordination of Certain Affiliate Obligations. Cause all Indebtedness of such Borrower and its Subsidiaries to any Affiliate, other than to such Borrower or any of its Subsidiaries (including, without limitation, under the Second Amended and Restated Non-Utility Money Pool Agreement, dated as of April 6, 2011 (as amended, modified, restated and replaced from time to time, the “Money Pool”), among FE, the Borrowers and certain other Affiliates of the Borrowers), to be subordinated to the obligations of such Borrower hereunder on the terms set forth in Exhibit I hereto.

(j) FES Guarantees. Maintain and cause its applicable Subsidiaries to maintain in full force and effect each Genco Guarantee to which such Person is a party and not cause, permit or consent to, or permit its applicable Subsidiaries to cause, permit or consent to, any modification or waiver of any Genco Guarantee that would reasonably be expected to adversely affect the rights of the Lenders thereunder.

SECTION 5.02. Debt to Capitalization Ratio.

Unless the Majority Lenders shall otherwise consent in writing, so long as any amount payable by any Borrower hereunder shall remain unpaid, any Letter of Credit for the account of any Borrower shall remain outstanding or any Lender shall have any Commitment to any Borrower hereunder, such Borrower will maintain a Debt to Capitalization Ratio of no more than 0.65 to 1.00 (determined as of the last day of each fiscal quarter).

SECTION 5.03. Negative Covenants of the Borrowers.

Unless the Majority Lenders shall otherwise consent in writing, so long as any amount payable by any Borrower hereunder shall remain unpaid, any Letter of Credit for the account of any Borrower shall remain outstanding or any Lender shall have any Commitment to any Borrower hereunder, such Borrower will not:

(a) Sales, Etc. (i) Sell, lease, transfer or otherwise dispose of any shares of common stock of any Significant Subsidiary of such Borrower, whether now owned or hereafter acquired by such Borrower, or permit any Significant Subsidiary of such Borrower to do so, or (ii) sell, lease, transfer or otherwise dispose of (whether in one transaction or a series of transactions) or permit any of its Subsidiaries to sell, lease, transfer or dispose of (whether in one transaction or a series of transactions) assets located in The United States of America (other than any assets that are purported to be conveyed in connection with a Permitted Securitization but including assets purported to be conveyed pursuant to any sale leaseback transaction) having an aggregate book value (determined as of the date of such transaction for all such transactions since the date hereof) that is greater than 20% of the book value of all of the consolidated fixed assets of such Borrower, as reported on the most recent consolidated balance sheet of such Borrower prior to the date of such sale, lease transfer or disposition to any entity other than such Borrower or any of its wholly owned direct or indirect Subsidiaries; provided, however, that this provision shall not in any way restrict, and shall not apply to, (A) the disposition of any Borrower’s direct or indirect interests in (1) the approximately 700 megawatt Fremont Energy Center in Fremont, Ohio, (2) the 42 megawatt Richland Peaking Facility in Defiance, Ohio, or (3) the 18 megawatt Stryker Peaking Facility in Springfield, Ohio or (B) the sale, lease, transfer or other disposition of a Borrower’s assets to the other Borrower, a Subsidiary of the other Borrower or a newly-formed Person to which all or substantially all of the assets and liabilities of both Borrowers or their Subsidiaries are being transferred, in each case, pursuant to a transaction permitted under subsection (c) below. In addition, Attributable Securitization Obligations of the Borrowers and their respective Subsidiaries shall not at any time exceed in the aggregate $500,000,000.

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(b) Liens, Etc. Create or suffer to exist, or permit any Significant Subsidiary of such Borrower to create or suffer to exist, any Lien upon or with respect to any of its properties (including, without limitation, any shares of any class of equity security of any Significant Subsidiary of such Borrower), in each case to secure or provide for the payment of Indebtedness, other than (i) liens consisting of (A) pledges or deposits in the ordinary course of business to secure obligations under worker’s compensation laws or similar legislation, (B) deposits in the ordinary course of business to secure, or in lieu of, surety, appeal, or customs bonds to which such Borrower or Significant Subsidiary is a party, (C) pledges or deposits in the ordinary course of business to secure performance in connection with bids, tenders or contracts (other than contracts for the payment of money), or (D) materialmen’s, mechanics’, carriers’, workers’, repairmen’s or other like Liens incurred in the ordinary course of business for sums not yet due or currently being contested in good faith by appropriate proceedings diligently conducted, or deposits to obtain in the release of such Liens; (ii) purchase money liens or purchase money security interests upon or in any property acquired or held by such Borrower or Significant Subsidiary in the ordinary course of business, which secure the purchase price of such property or secure indebtedness incurred solely for the purpose of financing the acquisition of such property; (iii) Liens existing on property acquired by such Borrower or Significant Subsidiary or on the property of any Person at the time that such Person becomes a direct or indirect Significant Subsidiary of such Borrower or Significant Subsidiary or is merged into or consolidated with such Borrower or Significant Subsidiary; provided, in each case, that such Liens were not created to secure the acquisition of such Person; (iv) Liens in existence on the date of this Agreement; (v) Liens created by any FMB Mortgage, so long as under the terms thereof no “event of default” (howsoever designated) in respect of any bonds issued thereunder will be triggered by reference to an Event of Default or Unmatured Default; (vi) Liens securing Attributable Securitization Obligations on the assets purported to be sold in connection with the applicable Permitted Securitization; (vii) Liens securing Nonrecourse Indebtedness; (viii) Liens on cash or cash equivalents deposited on behalf of or pledged to counterparties with respect to Permitted Obligations of such Borrower or any of its Significant Subsidiaries; (ix) Liens on cash or cash equivalents to defease Indebtedness of such Borrower or any of its Subsidiaries; (x) Liens on cash or cash equivalents constituting proceeds from a disposition of assets otherwise not prohibited under subsection (a) above, which proceeds are deposited in escrow accounts for indemnification, adjustment of purchase price or similar obligations to the purchaser of such assets; (xi) Liens securing obligations in respect of pollution control or industrial revenue bonds or nuclear fuel leases, provided that such Liens extend to only the equipment, project, nuclear fuel or other assets financed with the proceeds of such financing; (xii) Liens arising in connection with leases that shall have been or should be, in accordance with GAAP, recorded as capital leases in respect of which such Borrower or Significant Subsidiary is liable as lessee; provided, that no such Lien shall extend to or cover any assets of such Borrower or Significant Subsidiary other than the assets of such Borrower or Significant Subsidiary subject to such lease and proceeds thereof; and (xiii) Liens created for the sole purpose of refinancing, extending, renewing or replacing in whole or in part Indebtedness secured by any Lien referred to in the foregoing clauses (i) through (xii); provided, however, that the principal

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amount of Indebtedness (or, if greater, the aggregate lending commitment) secured thereby shall not exceed the principal amount of Indebtedness (or, if greater, the aggregate lending commitment) so secured at the time of such refinancing, extension, renewal or replacement, and that such refinancing, extension, renewal or replacement, as the case may be, shall be limited to all or a part of the property or Indebtedness that secured the Lien so extended, renewed or replaced (and any improvements on such property). Notwithstanding the foregoing, First Mortgage Bonds may not be issued or used to secure, or otherwise to assure creditors or counterparties with respect to payments on other Indebtedness, Commodity Trading Obligations or Hedging Obligations of any Borrower or any of its Subsidiaries, except that (A) each Genco may issue and use First Mortgage Bonds in order to secure payment obligations of FES or such Genco to any of FE’s regulated utility Subsidiaries with respect to FES’s Mark-to-Market Obligations in an amount not greater than the difference between (x) the amount of First Mortgage Bonds that may at the time of determination be issued under the applicable issuance tests under the FMB Mortgage of such Genco (as such issuance tests are in effect on the date hereof) and (y) the amount of First Mortgage Bonds issued by such Genco and used for the purpose described in clause (B) below, and (B) each Genco and Allegheny may issue First Mortgage Bonds to secure Indebtedness of such Person or its Subsidiaries to unaffiliated Persons in an aggregate principal amount outstanding at any time for the Gencos and Allegheny collectively not in excess of $3.414 billion.

(c) Mergers, Etc. Merge with or into or consolidate with or into any other Person, or permit any of its Subsidiaries to do so unless (i) immediately after giving effect thereto, no event shall occur and be continuing that constitutes an Event of Default, (ii) the consolidation or merger shall not materially and adversely affect the ability of such Borrower (or its successor by merger or consolidation as contemplated by clause (i) of this subsection (c)) to perform its obligations hereunder or under any other Loan Document, and (iii) in the case of any merger or consolidation to which such Borrower is a party, the Person formed by such consolidation or into which such Borrower shall be merged shall assume such Borrower’s obligations under this Agreement and the other Loan Documents to which it is a party in a writing reasonably satisfactory in form and substance to the Administrative Agent. Without limiting the foregoing, (A) each Borrower may merge with or into or consolidate with or into (x) the other Borrower or into a newly-formed Person into which both Borrowers are being merged or consolidated (which will become the sole Borrower hereunder) or (y) a wholly-owned Subsidiary of the other Borrower (in which case such other Borrower will become the sole Borrower hereunder), and (B) each Borrower may transfer all or substantially all of its assets and liabilities to the other Borrower, to a wholly-owned Subsidiary of the other Borrower (in which case such other Borrower will become the sole Borrower hereunder) or to a newly-formed Person to which all or substantially all of the assets and liabilities of both Borrowers are being transferred (which will become the sole Borrower hereunder), in each case of clauses (A) and (B), if (1) the surviving Person, transferee or Person otherwise specified above to become the sole Borrower hereunder, as applicable, assumes both Borrowers’ obligations under this Agreement and the other Loan Documents pursuant to an instrument in form and substance reasonably satisfactory to the Administrative Agent, (2) the Administrative Agent receives evidence reasonably satisfactory to it that, after giving effect to such transactions, the Genco Guarantees will remain in full force and effect and will apply (either as a result of such merger, consolidation or transfer or pursuant to amendments to the Genco Guarantees) to the obligations of Allegheny under this Agreement and the other Loan Documents (as so transferred or assumed) in the same manner and to the same extent as they applied to the obligations of FES under this Agreement and the other Loan Documents on the date hereof, (3) the Reference Ratings of the surviving or resulting Borrower are not, after giving effect to such transactions, any lower than the Reference Ratings of each Borrower that was a party to such transactions immediately prior to the consummation of such transactions, unless the Reference Ratings of such surviving or resulting Borrower are at least BBB- and Baa3, and (4) the parties to such transaction deliver to the Administrative Agent certified copies of all corporate or limited liability, equity holder and Governmental Authority approvals required in connection with such transactions and legal opinions of counsel to such parties relating to such transactions and the assumption agreement described in clause (1) above.

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(d) Compliance with ERISA. (i) Enter into any nonexempt “prohibited transaction” (within the meaning of Section 4975 of the Code or Section 406 of ERISA) involving any Plan that may result in any liability of such Borrower to any Person that (in the opinion of the Majority Lenders and the Fronting Banks) would reasonably be expected to have a Material Adverse Effect with respect to any Borrower or (ii) allow or suffer to exist any other event or condition known to such Borrower that results in any liability of such Borrower to the PBGC that would reasonably be expected to have a Material Adverse Effect with respect to any Borrower. For purposes of this subsection (d), “liability” shall not include termination insurance premiums payable under Section 4007 of ERISA.

(e) Use of Proceeds. Use the proceeds of any Extension of Credit for any purpose other than (ii) refinancing the Existing Facilities to which such Borrower is a party and (ii) working capital and other general corporate purposes of such Borrower and its Subsidiaries; provided, however, that such Borrower may not use such proceeds in connection with any Hostile Acquisition.

(f) Limitation on Cross-Default Provisions. Incur or permit any Significant Subsidiary to incur (which for purposes of this subsection (f), shall not include the drawdown of any revolving credit facility or any letter of credit facility in existence on the date hereof or any other incurrence of Indebtedness or other obligation under agreements in existence on the date hereof pursuant to the terms thereof as in effect on the date hereof) after the date hereof any Indebtedness, Commodity Trading Obligations or Hedging Obligations that shall or may become subject to acceleration, redemption or mandatory purchase prior to the stated maturity date of such Indebtedness or the stated or otherwise applicable date for performance of such Commodity Trading Obligations or Hedging Obligations, as the case may be, upon the occurrence of one or more events of default or credit event or similar events (howsoever designated) under any document or instrument evidencing any other such Indebtedness, Commodity Trading Obligations or Hedging Obligations (any such provision to the effect of the foregoing being a “Cross-Default Provision”) of FE or any of its Subsidiaries (other than any Borrower and its Subsidiaries); provided however, that, during the six-month period following the date hereof, each Borrower and its Subsidiaries may incur Commodity Trading Obligations and Hedging Obligations pursuant to any ISDA Master Agreement and related schedule that contains such a Cross-Default Provision if and to the extent that such ISDA Master Agreement and related schedule contained such Cross-Default Provision on the date hereof; and provided further, that any Cross-Default Provision of any Borrower or any of its Subsidiaries that relates to the other Borrower or any of its Subsidiaries shall not provide the applicable creditor or counterparty, as the case may be, rights more extensive than those provided to the Lenders under Section 6.01(e) below unless an Authorized Officer of the applicable Borrower shall have delivered a certified true and correct copy of such Cross-Default Provision to the Administrative Agent, whereupon the provisions of Section 6.01(e) shall be deemed to be automatically amended without any further action on the part of any Borrower, the Lenders or any other Person in a manner such that the Lenders shall receive the benefit of any such more extensive rights to the same extent that any such creditor or counterparty is entitled thereto.

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(g) Restrictions on Lending under Money Pool. At any time an Event of Default or an Unmatured Default shall have occurred and be continuing, make, or cause or permit any Subsidiary of such Borrower to make, loans and advances to any other Person under the Money Pool.

ARTICLE VI
EVENTS OF DEFAULT

SECTION 6.01. Events of Default.

If any of the following events shall occur and be continuing with respect to any Borrower (as to such Borrower, an “Event of Default”):

(a) (i) Any principal of any Advance or any Reimbursement Obligation shall not be paid by such Borrower when the same becomes due and payable, or (ii) any interest on any Advance or any fees or other amounts payable hereunder shall not be paid by such Borrower within three Business Days after the same becomes due and payable; or

(b) Any representation or warranty made by such Borrower (or any of its officers) in any Loan Document or in connection with any Loan Document shall prove to have been incorrect or misleading in any material respect when made; or

(c) (i) Such Borrower shall fail to perform or observe any covenant set forth in (A) Section 5.01(j), Section 5.02 or Section 5.03 on its part to be performed or observed or (B) Section 5.01(i) and such failure shall remain unremedied for five Business Days, or (ii) such Borrower shall fail to perform or observe any other term, covenant or agreement (other than those covenants otherwise covered in clause (a) or (c)(i) of this Section 6.01) contained in this Agreement or any other Loan Document on its part to be performed or observed and such failure shall remain unremedied for 30 days after written notice thereof shall have been given to such Borrower by the Administrative Agent or any Lender; or

(d) Any material provision of this Agreement or any other Loan Document shall at any time and for any reason cease to be valid and binding upon such Borrower, except pursuant to the terms thereof, or shall be declared to be null and void, or the validity or enforceability thereof shall be contested in any manner by such Borrower or any Governmental Authority, or such Borrower shall deny in any manner that it has any or further liability or obligation under this Agreement or any other Loan Document; or

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(e) Such Borrower or any Significant Subsidiary of such Borrower shall fail to pay any principal of or premium or interest on any Indebtedness (other than Indebtedness under this Agreement) that is outstanding in a principal amount in excess of $100,000,000 in the aggregate when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Indebtedness; or any other event shall occur or condition shall exist under any agreement or instrument relating to any such Indebtedness and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such event or condition is to accelerate, or to permit the acceleration of, the maturity of such Indebtedness; or any such Indebtedness shall be declared to be due and payable, or required to be prepaid (other than by a regularly scheduled required prepayment), prior to the stated maturity thereof; or

(f) Such Borrower or any Significant Subsidiary of such Borrower shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against any Borrower or any Significant Subsidiary of such Borrower seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition or arrangement with creditors, a readjustment of its debts, in each case under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted or acquiesced in by it), either such proceeding shall remain undismissed or unstayed for a period of 60 consecutive days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or any Borrower or any Significant Subsidiary of such Borrower shall take any corporate action to authorize or to consent to any of the actions set forth above in this subsection (f); or

(g) Any judgment or order for the payment of money exceeding any applicable insurance coverage by more than $100,000,000 shall be rendered by a court of final adjudication against such Borrower or any Significant Subsidiary of such Borrower and either (i) valid enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or

(h) Any Termination Event with respect to a Plan or a Multiemployer Plan shall have occurred, and, 30 days after notice thereof shall have been given to such Borrower by the Administrative Agent or any Lender, such Termination Event (if correctable) shall not have been corrected, and either (1) the actual liability in respect of such Termination Event to such Borrower would reasonably be expected to exceed $100,000,000, or (2) such Borrower or any member of the Controlled Group as employer under a Multiemployer Plan shall have made a complete or partial withdrawal from such Multiemployer Plan and, as a result thereof, such Borrower would reasonably be expected to incur withdrawal liability in an amount exceeding $100,000,000; or

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(i) (i) FE shall fail to own directly or indirectly 100% of the issued and outstanding shares of common stock of each Borrower and each Borrower’s Significant Subsidiaries, (ii) any Person or two or more Persons acting in concert shall have acquired beneficial ownership (within the meaning of Rule 13d-3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended), directly or indirectly, of securities of FE (or other securities convertible into such securities) representing 30% or more of the combined voting power of all securities of FE entitled to vote in the election of directors; or (iii) commencing after the date of this Agreement, individuals who as of the date of this Agreement were directors shall have ceased for any reason to constitute a majority of the Board of Directors of FE unless the Persons replacing such individuals were nominated by the stockholders or the Board of Directors of FE in accordance with FE’s Organizational Documents (each a “Change of Control”);

then, and in any such event, the Administrative Agent shall at the request, or may with the consent, of the Majority Lenders, (i) by notice to the defaulting Borrower, declare the obligation of each Lender to make Advances to such Borrower, the obligation of the Fronting Banks to issue Letters of Credit for the account of such Borrower and the obligation of the Swing Line Lenders to make Swing Line Advances to such Borrower, to be terminated, whereupon the same shall forthwith terminate, and (ii) by notice to such Borrower, declare the Advances made to such Borrower, an amount equal to the aggregate Stated Amount of all issued but undrawn Letters of Credit issued for the account of such Borrower, (such amount being the “Letter of Credit Cash Cover”) and all other amounts payable under this Agreement and the other Loan Documents by such Borrower to be forthwith due and payable, whereupon such Advances and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by such Borrower; provided, however, that in the event of an actual or deemed entry of an order for relief with respect to any Borrower or any Significant Subsidiary of such Borrower under the Bankruptcy Code, (A) the obligation of each Lender to make Advances to such Borrower, the obligation of the Fronting Banks to issue Letters of Credit for the account of such Borrower, and the obligation of the Swing Line Lenders to make Swing Line Advances to such Borrower shall automatically be terminated and (B) all Advances made to such Borrower, the Letter of Credit Cash Cover with respect to such Borrower and all other amounts payable under this Agreement by such Borrower shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by such Borrower. In the event that any Borrower is required to pay the Letter of Credit Cash Cover pursuant to this Section, such payment shall be made in immediately available funds to the Administrative Agent, which shall hold such funds as collateral pursuant to arrangements reasonably satisfactory to the Administrative Agent and the Fronting Banks to secure Reimbursement Obligations in respect of Letters of Credit then outstanding, for the benefit of the Lenders and the Fronting Banks.

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ARTICLE VII
THE ADMINISTRATIVE AGENT

SECTION 7.01. Authorization and Action.

Each Lender, each Fronting Bank and each Swing Line Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto. As to any matters not expressly provided for by this Agreement the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Majority Lenders, and such instructions shall be binding upon all Lenders and all Fronting Banks; provided, however, that the Administrative Agent shall not be required to take any action that exposes the Administrative Agent to personal liability or that is contrary to this Agreement or applicable law. The Administrative Agent agrees to give to each Lender and each Fronting Bank prompt notice of each notice given to it by the Borrowers pursuant to the terms of this Agreement and to promptly forward to each Lender, each Fronting Bank and each Swing Line Lender the financial statements and any other certificates or statements delivered to the Administrative Agent pursuant to Section 5.01(g).

SECTION 7.02. Administrative Agent’s Reliance, Etc.

Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable to any Lender, any Fronting Bank, any Swing Line Lender or the Borrowers for any action taken or omitted to be taken by it or them under or in connection with this Agreement, except for its or their own gross negligence or willful misconduct. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat each Lender listed in the Register as a “Lender” with a Commitment in the amount recorded in the Register until the Administrative Agent receives and accepts an Assignment and Assumption entered into by a Lender listed in the Register, as assignor, and the applicable assignee, as provided in Section 8.08, at which time the Administrative Agent will make such recordations in the Register as are appropriate to reflect the assignment effected by such Assignment and Assumption; (ii) may consult with legal counsel (including counsel for the Borrowers), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender, any Fronting Bank or any Swing Line Lender and shall not be responsible to any Lender, any Fronting Bank or any Swing Line Lender for any statements, warranties or representations (whether written or oral) made in or in connection with the Loan Documents; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of the Loan Documents on the part of the Borrowers or to inspect the property (including the books and records) of the Borrowers, and, without limiting the foregoing, shall be deemed not to have knowledge of any Default or Event of Default unless and until written notice is given by a Lender or a Borrower to the Administrative Agent in accordance with the terms of this Agreement; (v) shall not be responsible to any Lender, any Fronting Bank or any Swing Line Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any other instrument or document furnished pursuant thereto; and (vi) shall incur no liability under or in respect of this Agreement by acting upon any notice, consent, certificate or other instrument or writing (which may be by telecopier, telegram or cable) believed by it in good faith to be genuine and signed or sent by the proper party or parties.

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SECTION 7.03. JPMCB and the Fronting Banks and Swing Line Lenders.

With respect to its Commitment, the Advances made by it and any Note issued to it, each of JPMCB and each Lender that is also a Fronting Bank or a Swing Line Lender shall have the same rights and powers under this Agreement as any other Lender and may exercise the same as though it were not the Administrative Agent, a Fronting Bank or a Swing Line Lender (as the case may be); and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated, include each of JPMCB and each Lender that is also a Fronting Bank as a Swing Line Lender in its individual capacity. Each of JPMCB and each Lender that is also a Fronting Bank as a Swing Line Lender and its Affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with, each Borrower, any of its respective subsidiaries and any Person who may do business with or own securities of such Borrower or any such subsidiary, all as if JPMCB or such Lender were not the Administrative Agent, a Fronting Bank or a Swing Line Lender (as the case may be) and without any duty to account therefor to the Lenders or any other Fronting Bank or Swing Line Lender.

SECTION 7.04. Lender Credit Decision; No Other Duties.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, the Fronting Banks, the Swing Line Lenders or any other Lender (or any such Person or any Affiliate thereof acting in the capacity of “Joint Lead Arranger”, “Syndication Agent” or “Documentation Agent”) and based on the financial statements referred to in Section 4.01(g) and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, the Fronting Banks, the Swing Line Lenders or any other Lender (or any such Person or any Affiliate thereof acting in the capacity of “Joint Lead Arranger”, “Syndication Agent” or “Documentation Agent”) and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement.

Anything herein to the contrary notwithstanding, none of the Persons listed on the cover page hereof as a “Joint Lead Arranger”, “Documentation Agent” or “Syndication Agent” shall have any powers, duties or responsibilities under this Agreement or any of the other Loan Documents, except in its capacity, as applicable, as the Administrative Agent, a Fronting Bank, a Swing Line Lender, or a Lender hereunder.

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SECTION 7.05. Indemnification.

The Lenders agree to indemnify the Administrative Agent (to the extent not reimbursed by the Borrowers), ratably according to the amounts of their respective Commitments, from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by, or asserted against the Administrative Agent in any way relating to or arising out of this Agreement or any action taken or omitted by the Administrative Agent (in its capacity as such) under this Agreement; provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent’s gross negligence or willful misconduct. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent promptly upon demand for its ratable share of any out-of-pocket expenses (including reasonable counsel fees) incurred by the Administrative Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, this Agreement, to the extent that such expenses are reimbursable by the Borrowers but for which the Administrative Agent is not reimbursed by the Borrowers.

SECTION 7.06. Successor Administrative Agent.

The Administrative Agent may resign at any time by giving written notice thereof to the Lenders, the Fronting Banks, the Borrowers and the Swing Line Lenders and may be removed at any time with or without cause by the Majority Lenders, the Fronting Banks and the Swing Line Lenders. Upon any such resignation or removal, the Majority Lenders, the Fronting Banks and the Swing Line Lenders shall have the right, with the prior written consent of the Borrowers (unless an Event of Default has occurred and is continuing), which consent shall not be unreasonably withheld or delayed, to appoint a successor Administrative Agent. If no successor Administrative Agent shall have been so appointed by the Majority Lenders, the Fronting Banks and the Swing Line Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent’s giving of notice of resignation or the Majority Lenders’, the Fronting Banks’ and the Swing Line Lenders’ removal of the retiring Administrative Agent, then the retiring Administrative Agent may, on behalf of the Lenders, the Fronting Banks and the Swing Line Lenders, appoint a successor Administrative Agent, which shall be a Lender or an Affiliate of a Lender and (i) a commercial bank organized under the laws of the United States, or any State thereof or (ii) a commercial bank organized under the laws of any other country that is a member of the OECD or has concluded special lending arrangements with the International Monetary Fund associated with its “General Arrangements to Borrow”, or a political subdivision of any such country, provided that such bank is acting through a branch or agency located in the United States and shall have a combined capital and surplus of at least $250,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent’s resignation or removal hereunder as Administrative Agent, the provisions of this Article VII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement. Notwithstanding the foregoing, if no Event of Default or Unmatured Default shall have occurred and be continuing, then no successor Administrative Agent shall be appointed under this Section 7.06 without the prior written consent of the Borrowers, which consent shall not be unreasonably withheld or delayed.

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SECTION 7.07. Delegation of Duties.

The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder by or through any one or more sub-agents appointed by the Administrative Agent; provided that, the appointment of a sub-agent that is not an Affiliate of the Administrative Agent shall be subject to the prior consent of the Borrowers (unless an Event of Default has occurred and is continuing), which consent shall not be unreasonably withheld or delayed. The Administrative Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. Each such sub-agent and the Related Parties of the Administrative Agent shall be entitled to the benefits of all provisions of this Article VII and Section 8.05, as though such sub-agents were the “Administrative Agent”, as if set forth in full herein with respect thereto.

ARTICLE VIII
MISCELLANEOUS

SECTION 8.01. Amendments, Etc.

No amendment or waiver of any provision of this Agreement or any Note, nor consent to any departure by any Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall, unless in writing and signed by all the Lenders affected thereby (other than, in the case of clause (a), (e) or (f) below, any Defaulting Lender), do any of the following: (a) waive any of the conditions specified in Section 3.01 or 3.02 increase the Commitments of the Lenders or subject the Lenders to any additional obligations, (b) change any provision hereof in a manner that would alter the pro rata sharing of payments or the pro rata reduction of Commitments among the Lenders, (c) reduce the principal of, or interest (or rate of interest) on, the Advances or any fees or other amounts payable hereunder, (d) postpone any date fixed for any payment of principal of, or interest on, the Advances or any fees or other amounts payable hereunder, (e) change the percentage of the Commitments or of the aggregate unpaid principal amount of the Advances, the aggregate undrawn amount of outstanding Letters of Credit or the number of Lenders, that shall be required for the Lenders or any of them to take any action hereunder or (f) amend this Section 8.01 or the definition of “Majority Lenders”; and provided, further, that (i) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement or Section 2.21; (ii) that no amendment, waiver or consent that would adversely affect the rights of, or increase the obligations of, any Fronting Bank, or that would alter any provision hereof relating to or affecting Letters of Credit issued by such Fronting Bank or modify or waive Section 2.21, shall be effective unless agreed to in writing by such Fronting Bank or modify or waive Section 2.21; (iii) no amendment, waiver or consent that would adversely affect the rights of, or increase the obligations of, any Swing Line Lender, or that would alter provisions hereof relating to or affecting Swing Line Advances made by such Swing Line Lender or modify or waive Section 2.21, shall be effective unless agreed to in writing by such Swing Line Lender; and (iv) this Agreement may be amended and restated without the consent of any Lender, any Fronting Bank, any Swing Line Lender or the Administrative Agent if, upon giving effect to such amendment and restatement, such Lender, such Fronting Bank, such Swing Line Lender or the Administrative Agent, as the case may be, shall no longer be a party to this Agreement (as so amended and restated) or have any Commitment or other obligation hereunder (including, without limitation, any obligation to make payment on account of a Drawing) and shall have been paid in full all amounts payable hereunder to such Lender, such Fronting Bank, such Swing Line Lender or the Administrative Agent, as the case may be.

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SECTION 8.02. Notices, Etc.

Unless specifically provided otherwise in this Agreement, all notices and other communications provided for hereunder shall be in writing (including telecopier) and delivered by hand or overnight courier service, mailed or sent by telecopy, if to any Borrower, to it in care of FE at its address at 76 South Main Street, Akron, Ohio 44308, Attention: Treasurer, Telecopy: (330) 384-3772; if to any Bank (including any Swing Line Lender), at its Domestic Lending Office specified opposite its name on Schedule I hereto; if to any other Lender (including any Swing Line Lender), at its Domestic Lending Office specified in the Assignment and Assumption pursuant to which it became a Lender; if to the Administrative Agent, at its address at JPMorgan Chase Bank, N.A., 1111 Fannin, 10th Floor, Houston, TX 77002-6925, Attention: Leslie Hill, Telecopy: 713-427-6307, and with a copy to JPMorgan Chase Bank, N.A., 383 Madison Avenue, New York, NY 10179, Attention: Peter Christensen, Telecopy: 212-270-3897; if to any Fronting Bank identified on Schedule II hereto, at the address specified opposite its name on Schedule II hereto; if to any other Fronting Bank, at such address as shall be designated by such Fronting Bank in a written notice to the other parties; or, as to each party, at such other address as shall be designated by such party in a written notice to the other parties. Subject to the other notice requirements of this Agreement, all notices and communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt if delivered by hand or overnight courier service, mailed or sent by telecopy to such party and received during the normal business hours of such party as provided in this Section or in accordance with the latest unrevoked direction from such party given in accordance with this Section. If such notices and communications are received after the normal business hours of such party, receipt shall be deemed to have been given upon the opening of the recipient’s next Business Day.

SECTION 8.03. Electronic Communications.

(a) Each Borrower hereby agrees that it will provide to the Administrative Agent all information, documents and other materials that it is obligated to furnish to the Administrative Agent pursuant to the Loan Documents, including, without limitation, all notices, requests, financial statements, financial and other reports, certificates and other information materials, but excluding any such communication that (i) relates to a request for a new, or a conversion of an existing, Borrowing or other Extension of Credit (including any election of an interest rate or Interest Period relating thereto), (ii) relates to the payment of any principal or other amount due under the Credit Agreement prior to the scheduled date therefor, (iii) provides notice of any Unmatured Default or Event of Default under the Credit Agreement or (iv) is required to be delivered to satisfy any condition precedent to the effectiveness of the Credit Agreement and/or any Borrowing or other Extension of Credit thereunder (all such non-excluded communications being referred to herein collectively as “Communications”), by transmitting the Communications in an electronic/soft medium in a format reasonably acceptable to the Administrative Agent to leslie.d.hill@chase.com and Peter.Christensen@jpmorgan.com or faxing the Communications to (713) 427-6307 and (212) 270-3897. In addition, each Borrower agrees to continue to provide the Communications to the Administrative Agent in the manner otherwise specified in this Agreement, but only to the extent requested by the Administrative Agent.

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(b) Each Borrower further agrees that the Administrative Agent may make the Communications available to the Lenders by posting the Communications on Intralinks or a substantially similar electronic transmission systems (the “Platform”). Each Borrower acknowledges that the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution.

(c) THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE”. THE AGENT PARTIES (AS DEFINED BELOW) DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS, OR THE ADEQUACY OF THE PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE BY THE AGENT PARTIES IN CONNECTION WITH THE COMMUNICATIONS OR THE PLATFORM. IN NO EVENT SHALL THE ADMINISTRATIVE AGENT OR ANY OF ITS AFFILIATES OR ANY OF THEIR RESPECTIVE OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ADVISORS OR REPRESENTATIVES (COLLECTIVELY, “AGENT PARTIES”) HAVE ANY LIABILITY TO ANY BORROWER, ANY LENDER OR ANY OTHER PERSON OR ENTITY FOR DAMAGES OF ANY KIND, INCLUDING, WITHOUT LIMITATION, DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES, LOSSES OR EXPENSES (WHETHER IN TORT, CONTRACT OR OTHERWISE) ARISING OUT OF ANY BORROWER’S OR THE ADMINISTRATIVE AGENT’S TRANSMISSION OF THE COMMUNICATIONS THROUGH THE PLATFORM, EXCEPT TO THE EXTENT THE LIABILITY OF ANY AGENT PARTY IS FOUND IN A FINAL NON-APPEALABLE JUDGMENT BY A COURT OF COMPETENT JURISDICTION TO HAVE RESULTED PRIMARILY FROM SUCH AGENT PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

(d) The Administrative Agent agrees that the receipt of the Communications by the Administrative Agent at its e-mail address set forth above shall constitute effective delivery of the Communications to the Administrative Agent for purposes of the Loan Documents. Each Lender agrees that notice to it (as provided in the next sentence) specifying that the Communications have been posted to the Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Loan Documents. Each Lender agrees to notify the Administrative Agent in writing (including by electronic communication) from time to time of such Lender’s e-mail address to which the foregoing notice may be sent by electronic transmission and that the foregoing notice may be sent to such e-mail address. Subject to the other notice requirements of this Agreement, all such notices and Communications given to the Administrative Agent or such Lender in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt if delivered by electronic/soft medium to such party and received during the normal business hours of such party as provided in this Section or in accordance with the latest unrevoked direction from such party given in accordance with this Section. If such notices and communications are received after the normal business hours of such party, receipt shall be deemed to have been given upon the opening of the recipient’s next Business Day.

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(e) Nothing herein shall prejudice the right of the Administrative Agent or any Lender to give any notice or other communication pursuant to any Loan Document in any other manner specified in such Loan Document.

SECTION 8.04. No Waiver; Remedies.

No failure on the part of any Lender, any Fronting Bank, any Swing Line Lender or the Administrative Agent to exercise, and no delay in exercising, any right hereunder or under any Note shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

SECTION 8.05. Costs and Expenses; Indemnification.

(a) Each Borrower agrees to pay on demand all reasonable out-of-pocket costs and expenses incurred by the Administrative Agent, each Fronting Bank and each Swing Line Lender in connection with the preparation, execution, delivery, syndication administration, modification and amendment of this Agreement, any Note, any Letter of Credit and the other documents to be delivered hereunder, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Administrative Agent, the Fronting Banks and the Swing Line Lenders with respect thereto and with respect to advising the Administrative Agent, the Fronting Banks and each Swing Line Lender as to their rights and responsibilities under this Agreement. Each Borrower further agrees to pay on demand all reasonable out-of-pocket costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses of counsel), incurred by the Administrative Agent, the Fronting Banks, the Swing Line Lenders and the Lenders in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement, any Note and the other documents to be delivered hereunder, including, without limitation, counsel fees and expenses in connection with the enforcement of rights under this Section 8.05(a).

(b) Except as otherwise expressly provided to the contrary herein, if any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.11 or 2.14 or a prepayment pursuant to Section 2.12 or acceleration of the maturity of any amounts owing hereunder pursuant to Section 6.01 or upon an assignment made upon demand of a Borrower pursuant to Section 8.08(h) or for any other reason, the applicable Borrower shall, upon demand by any Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment or Conversion, including, without limitation, any loss, cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by any Lender to fund or maintain such Advance. Each Borrower’s obligations under this subsection (b) shall survive the repayment of all other amounts owing to the Lenders and the Administrative Agent under this Agreement and any Note and the termination of the Commitments.

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(c) Each Borrower hereby agrees to indemnify and hold each Lender, each Fronting Bank, the Administrative Agent and their respective Affiliates and their respective officers, directors, employees and professional advisors (each, an “Indemnified Person”) harmless from and against any and all claims, damages, liabilities, costs or expenses (including reasonable attorney’s fees and expenses, whether or not such Indemnified Person is named as a party to any proceeding or is otherwise subjected to judicial or legal process arising from any such proceeding) that any of them may incur or that may be claimed against any of them by any Person (including any Borrower) by reason of or in connection with or arising out of any investigation, litigation or proceeding related to the Commitments or the commitment of each Fronting Bank hereunder and any use or proposed use by any Borrower of the proceeds of any Extension of Credit or the existence or use of any Letter of Credit or the amounts drawn thereunder, except to the extent such claim, damage, liability, cost or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Person’s gross negligence or willful misconduct. Each Borrower’s obligations under this Section 8.05(c) shall survive (x) the repayment of all amounts owing to the Lenders, the Fronting Banks and the Administrative Agent under this Agreement and any Note, (y) the termination of the Commitments, the commitment of the Fronting Banks hereunder and any Letters of Credit and (z) the termination of this Agreement. If and to the extent that the obligations of the Borrowers under this Section 8.05(c) are unenforceable for any reason, each Borrower agrees to make the maximum payment in satisfaction of such obligations that are not unenforceable that is permissible under Applicable Law or, if less, such amount that may be ordered by a court of competent jurisdiction.

(d) To the extent permitted by law, each Borrower also agrees not to assert any claim against any Indemnified Person on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to actual or direct damages) in connection with, arising out of, or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Advances.

(e) Each Borrower shall be liable for its pro rata share of any payment to be made by the Borrowers under this Section 8.05, such pro rata share to be determined on the basis of such Borrower’s Fraction; provided, however, that if and to the extent that any such liabilities are reasonably determined by the Borrowers (subject to the approval of the Administrative Agent which approval shall not be unreasonably withheld) to be directly attributable to a specific Borrower, only such Borrower shall be liable for such payments.

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SECTION 8.06. Right of Set-off.

Upon the occurrence and during the continuance of any Event of Default each Lender, each Fronting Bank and each Swing Line Lender is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final, excluding, however, any payroll accounts maintained by the Borrowers with such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) if and to the extent that such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) shall have expressly waived its set-off rights in writing in respect of such payroll account) at any time held and other indebtedness at any time owing by such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) to or for the credit or the account of the Borrowers against any and all of the obligations of the Borrowers now or hereafter existing under this Agreement and any Note held by such Lender, whether or not such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) shall have made any demand under this Agreement or such Note and although such obligations may be unmatured. Each Lender, each Fronting Bank and each Swing Line Lender agrees promptly to notify the Borrowers after any such set-off and application made by such Lender, such Fronting Bank or such Swing Line Lender (as the case may be), provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender and each Fronting Bank and each Swing Line Lender under this Section 8.06 are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) may have.

SECTION 8.07. Binding Effect.

This Agreement shall become effective when it shall have been executed by the Borrowers and the Administrative Agent and when the Administrative Agent shall have been notified by each Bank, each Swing Line Lender and each Fronting Bank that such Bank, such Swing Line Lender or such Fronting Bank (as the case may be) has executed it and thereafter shall be binding upon and inure to the benefit of the Borrowers, the Administrative Agent, each Swing Line Lender, each Fronting Bank and each Lender and their respective successors and permitted assigns, except that the Borrowers shall not have the right to assign their rights or obligations hereunder or any interest herein (x) without the prior written consent of the Lenders and the Fronting Banks or (y) pursuant to Section 5.03(c).

SECTION 8.08. Assignments and Participations.

(a) Successors and Assigns Generally. No Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section 8.08, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section 8.08, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (f) of this Section 8.08 (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section 8.08 and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

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(b) Assignments by Lenders. Any Lender may at any time assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Advances at the time owing to it); provided that any such assignment shall be subject to the following conditions:

(i) Minimum Amounts.

(A) in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and/or the Advances at the time owing to it or contemporaneous assignments to related Approved Funds that equal at least the amount specified in subsection (b)(i)(B) of this Section 8.08 in the aggregate or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund, no minimum amount need be assigned; and

(B) in any case not described in subsection (b)(i)(A) of this Section 8.08, the aggregate amount of the Commitment (which for this purpose includes Advances outstanding thereunder) or, if the applicable Commitment is not then in effect, the principal outstanding balance of the Advances of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $5,000,000, unless each of the Administrative Agent and, so long as no Event of Default has occurred and is continuing, the Borrowers otherwise consent (each such consent not to be unreasonably withheld or delayed); provided that the Borrowers shall be deemed to have consented to any such assignment unless they shall object thereto by giving written notice to the Administrative Agent within five Business Days after having received notice thereof.

(ii) Proportionate Amounts. Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Advance or the Commitment assigned.

(iii) Required Consents. No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section 8.08 and, in addition:

(A) the consent of the Borrowers (such consent not to be unreasonably withheld or delayed) shall be required unless (x) an Event of Default has occurred and is continuing at the time of such assignment, or (y) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; provided that the Borrowers shall be deemed to have consented to any such assignment unless they shall object thereto by giving written notice to the Administrative Agent within five Business Days after having received notice thereof and provided, further, that the Borrowers’ consent shall not be required during the primary syndication hereof;

(B) the consent of the Administrative Agent (such consent not to be unreasonably withheld or delayed) shall be required for assignments if such assignment is to a Person that is not a Lender, an Affiliate of such Lender or an Approved Fund with respect to such Lender; and

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(C) the consent of each Fronting Bank and Swing Line Lender shall be required for all assignments, other than pursuant to subsection (f) below.

(iv) Assignment and Assumption. The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment. The assignee, if it is not a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(v) No Assignment to Certain Persons. No such assignment shall be made to (A) the Borrowers or any of the Borrowers’ Affiliates or Subsidiaries or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute any of the foregoing Persons described in this clause (B).

(vi) No Assignment to Natural Persons. No such assignment shall be made to a natural Person.

(vii) Certain Additional Payments. In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrowers and the Administrative Agent, the applicable pro rata share of Advances previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent, each Fronting Bank, each Swing Line Lender and each other Lender hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full pro rata share of all Advances and participations in Letters of Credit and Swing Line Advances in accordance with its Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable law without compliance with the provisions of this paragraph, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

Subject to acceptance and recording thereof by the Administrative Agent pursuant to paragraph (c) of this Section 8.08, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.13, 2.16 and 8.05 with respect to facts and circumstances occurring prior to the effective date of such assignment; provided, that except to the extent otherwise expressly agreed by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this paragraph shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (d) of this Section 8.08.

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(c) Register. The Administrative Agent, acting solely for this purpose as an agent of the Borrowers, shall maintain at its offices at 1111 Fannin, 10th Floor, Houston, TX 77002-6925 a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Advances owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive absent manifest error, and the Borrowers, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrowers and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d) Participations. Any Lender may at any time, without the consent of, or notice to, the Borrowers or the Administrative Agent, sell participations to any Person (other than a natural Person or the Borrowers or any of the Borrowers’ Affiliates or Subsidiaries) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Advances owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, and (iii) the Borrowers, the Administrative Agent, the Fronting Banks and Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. For the avoidance of doubt, each Lender shall be responsible for the indemnity under Section 7.05 with respect to any payments made by such Lender to its Participant(s). Each Lender that sells a participation shall, acting solely for this purpose as an agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under this Agreement (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register to any Person (including the identity of any Participant or any information relating to a Participant’s interest in any Commitments, Advances, Letters of Credit or its obligations under any Loan Document) except to the Internal Revenue Service and only to the extent that such disclosure is necessary to establish that such Commitment, Advance, Letter of Credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary.

80

Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clauses (a) through (f) of Section 8.01 that affects such Participant. The Borrowers agree that each Participant shall be entitled to the benefits of Sections 2.13 and 2.16 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section 8.08; provided that such Participant agrees to be subject to the provisions of Sections 2.16(f) and 8.08(h) as if it were an assignee under subsection (b) of this Section 8.08. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 8.06 as though it were a Lender; provided that such Participant agrees to be subject to Section 2.17 as though it were a Lender.

(e) Limitations upon Participant Rights. A Participant shall not be entitled to receive any greater payment under Sections 2.13 and 2.16 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrowers’ prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.16 unless the Borrowers are notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrowers, to comply with Section 2.16(e) as though it were a Lender.

(f) Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(g) Disclosure of Certain Information. Any Lender may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 8.08, disclose to the assignee or participant or proposed assignee or participant, any information relating to the Borrowers furnished to such Lender by or on behalf of the Borrowers; provided, that prior to any such disclosure, the assignee or participant or proposed assignee or participant shall agree to preserve the confidentiality of any confidential information relating to the Borrowers received by it from such Lender.

(h) Replacement of Lenders. If any Lender shall make demand for payment under Section 2.13(a), 2.13(b) or 2.16, or shall deliver any notice to the Administrative Agent pursuant to Section 2.14 resulting in the suspension of certain obligations of the Lenders with respect to Eurodollar Rate Advances, or shall be a Defaulting Lender, then, within 30 days of such demand (if, and only if, such payment demanded under Section 2.13(a), 2.13(b) or 2.16, as the case may be, shall have been made by a Borrower) or such notice (if such suspension is still in effect) or such Lenders’ becoming a Defaulting Lender, as the case may be, such Borrower may demand that such Lender assign in accordance with this Section 8.08 to one or more assignees designated by such Borrower and approved by the required Persons under subsection (b)(iii) above all (but not less than all) of such Lender’s Commitment and the Advances owing to it within the next 15 days. If any such assignee designated by such Borrower shall fail to consummate such assignment on terms acceptable to such Lender, or if such Borrower shall fail to designate any such assignee for all of such Lender’s

81

Commitment or Advances, then such Lender may assign such Commitment and Advances to any other assignee in accordance with this Section 8.08 during such 15-day period; it being understood for purposes of this Section 8.08(h) that such assignment shall be conclusively deemed to be on terms acceptable to such Lender, and such Lender shall be compelled to consummate such assignment to an assignee designated by such Borrower, if such assignee shall agree to such assignment in substantially the form of Exhibit A hereto and shall offer compensation to such Lender in an amount equal to the sum of the principal amount of all Advances outstanding to such Lender plus all interest accrued thereon to the date of such payment plus all other amounts payable by such Borrower to such Lender hereunder (whether or not then due) as of the date of such payment accrued in favor of such Lender hereunder. Notwithstanding the foregoing, no Lender shall make any assignment at any time pursuant to this subsection (g) if, at such time, (i) an Event of Default or Unmatured Default has occurred and is continuing, (ii) any Borrower has not satisfied all of its obligations hereunder with respect to such Lender or (iii) such replacement of such Lender is not acceptable to the Administrative Agent, the Fronting Banks and the Swing Line Lenders, as applicable, pursuant to subsection (b)(iii) above.

SECTION 8.09. Governing Law.

THIS AGREEMENT AND EACH OTHER LOAN DOCUMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

SECTION 8.10. Consent to Jurisdiction; Waiver of Jury Trial.

(a) To the fullest extent permitted by law, each Borrower hereby irrevocably (i) submits to the exclusive jurisdiction of any New York State or Federal court sitting in New York City and any appellate court from any thereof in any action or proceeding arising out of or relating to this Agreement, any other Loan Document or any Letter of Credit, and (ii) agrees that all claims in respect of such action or proceeding may be heard and determined in such New York State court or in such Federal court. Each Borrower hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding. Each Borrower also irrevocably consents, to the fullest extent permitted by law, to the service of any and all process in any such action or proceeding by the mailing by certified mail of copies of such process to such Borrower at its address specified in Section 8.02. Each Borrower agrees, to the fullest extent permitted by law, that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.

(b) EACH BORROWER, THE ADMINISTRATIVE AGENT, EACH FRONTING BANK, EACH SWING LINE LENDER AND THE LENDERS HEREBY WAIVE ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT, ANY OTHER LOAN DOCUMENT OR ANY LETTER OF CREDIT, OR ANY OTHER INSTRUMENT OR DOCUMENT DELIVERED HEREUNDER OR THEREUNDER.

82

SECTION 8.11. Severability.

Any provision of this Agreement that is prohibited, unenforceable or not authorized in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition, unenforceability or non-authorization without invalidating the remaining provisions hereof or affecting the validity, enforceability or legality of such provision in any other jurisdiction.

SECTION 8.12. Entire Agreement.

This Agreement and the Notes issued hereunder constitute the entire contract among the parties relative to the subject matter hereof. Any previous agreement among the parties with respect to the subject matter hereof is superseded by this Agreement, except (i) as expressly agreed in any such previous agreement and (ii) for the Fee Letters and the Fronting Bank Fee Letters. Except as is expressly provided for herein, nothing in this Agreement, expressed or implied, is intended to confer upon any party other than the parties hereto any rights, remedies, obligations or liabilities under or by reason of this Agreement.

SECTION 8.13. Execution in Counterparts.

This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

SECTION 8.14. USA PATRIOT Act Notice.

Each Lender that is subject to the Patriot Act, each Fronting Bank and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies the Borrowers pursuant to the requirements of the Patriot Act that it is required to obtain, verify and record information that identifies the Borrowers, which information includes the name and address of the Borrower and other information that will allow such Lender, such Fronting Bank or the Administrative Agent, as applicable, to identify the Borrowers in accordance with the Patriot Act.

SECTION 8.15. No Fiduciary Duty.

The Administrative Agent, each Fronting Bank, each Swing Line Lender, each Lender and their respective Affiliates (collectively, the “Credit Parties”), may have economic interests that conflict with those of the Borrowers, their stockholders and/or their affiliates. Each Borrower agrees that nothing in the Loan Documents or otherwise will be deemed to create an advisory, fiduciary or agency relationship or fiduciary or other implied duty between any Credit Party, on the one hand, and such Borrower, its stockholders or its affiliates, on the other. The Borrowers acknowledge and agree that (i) the transactions contemplated by the Loan Documents (including the exercise of rights and remedies hereunder and thereunder) are arm’s-length commercial transactions between the Credit Parties, on the one hand, and the Borrowers, on the other, and (ii) in connection therewith and with the process leading thereto, (x) no Credit Party has assumed an advisory or fiduciary responsibility in favor of any Borrower, its stockholders or its affiliates with respect to the transactions contemplated hereby (or the exercise of rights or remedies with respect thereto) or the process leading thereto (irrespective of whether any Credit Party has advised, is currently advising or will advise any Borrower, its stockholders or its Affiliates on other matters) or any other obligation to any Borrower except the obligations expressly set forth in the Loan Documents and (y) each Credit Party is acting solely as principal and not as the agent or fiduciary of any Borrower, its management, stockholders, creditors or any other Person. Each Borrower acknowledges and agrees that it has consulted its own legal and financial advisors to the extent it deemed appropriate and that it is responsible for making its own independent judgment with respect to such transactions and the process leading thereto. Each Borrower agrees that it will not claim that any Credit Party has rendered advisory services of any nature or respect, or owes a fiduciary or similar duty to such Borrower, in connection with such transaction or the process leading thereto.

[Signatures to Follow]

83

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

FIRSTENERGY SOLUTIONS CORP.
By:	/s/ James F. Pearson
	James F. Pearson
	Vice President & Treasurer
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
By:	/s/ James F. Pearson
	James F. Pearson
	Vice President & Treasurer

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-1

JPMORGAN CHASE BANK, N.A., as Administrative Agent, as a Bank and as a Fronting Bank
By:	/s/ Peter Christensen
	Name:	Peter Christensen
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-2

BANK OF AMERICA, N.A., as a Bank, as a Fronting Bank and as a Swing Line Lender
By:	/s/ Mike Mason
	Name:	Mike Mason
	Title:	Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-3

BARCLAYS BANK PLC, as a Bank
By:	/s/ Ann E. Sutton
	Name:	Ann E. Sutton
	Title:	Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-4

THE ROYAL BANK OF SCOTLAND PLC, as a Bank and as a Fronting Bank
By:	/s/ Andrew N. Taylor
	Name:	Andrew N. Taylor
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-5

CITIBANK, N.A., as a Bank and as a Fronting Bank
By:	/s/ Maureen Maroney
	Name:	Maureen Maroney
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-6

KEYBANK NATIONAL ASSOCIATION, as a Bank and as a Fronting Bank
By:	/s/ Sherrie I. Manson
	Name:	Sherrie I. Manson
	Title:	Senior Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-7

THE BANK OF NOVA SCOTIA, as a Bank and as a Fronting Bank
By:	/s/ Thane Rattew
	Name:	Thane Rattew
	Title:	Managing Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-8

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Bank and as a Fronting Bank
By:	/s/ Bradford Joyce
	Name:	Bradford Joyce
	Title:	Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-9

UNION BANK, N.A., as a Bank
By:	/s/ Eric Otieno
	Name:	Eric Otieno
	Title:	Assistant Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-10

WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Bank and as a Fronting Bank
By:	/s/ Frederick W. Price
	Name:	Frederick W. Price
	Title:	Managing Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-11

MORGAN STANLEY BANK, N.A., as a Bank
By:	/s/ Sherrese Clarke
	Name: Sherrese Clarke
	Title:   Authorized Signatory

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-12

BNP Paribas, as a Bank
By:	/s/ Denis O’Meara
	Name:	Denis O’Meara
	Title:	Managing Director
By:	/s/ Pasquale Perraglia
	Name:	Pasquale Perraglia
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-13

CREDIT SUISSE AG, Cayman Islands Branch, as a Bank
By:	/s/ Shaheen Malik
	Name:	Shaheen Malik
	Title:	Vice President
By:	/s/ Rahul Parmar
	Name:	Rahul Parmar
	Title:	Associate

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-14

Goldman Sachs Bank USA, as a Bank
By:	/s/ Mark Walton
	Name:	Mark Walton
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-15

ROYAL BANK OF CANADA, as a Bank
By:	/s/ Thomas Casey
	Name:	Thomas Casey
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-16

UBS AG, Stamford Branch, as a Bank
By:	/s/ Irja R. Otsa
	Name:	Irja R. Otsa
	Title:	Associate Director
By:	/s/ Mary E. Evans
	Name:	Mary E. Evans
	Title:	Associate Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-17

MIZUHO CORPORATE BANK, LTD. as a Bank
By:	/s/ Leon Mo
	Name:	Leon Mo
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-18

PNC BANK, NATIONAL ASSOCIATION, as a Bank
By:	/s/ Christian S. Brown
	Name:	Christian S. Brown
	Title:	Senior Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-19

SUMITOMO MITSUI BANKING CORPORATION, as a Bank
By:	/s/ Hiroshi Higuma
	Name:	Hiroshi Higuma
	Title:	Joint General Manager

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-20

U.S. Bank National Association, as a Bank
By:	/s/ Eric J. Cosgrove
	Name:	Eric J. Cosgrove
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-21

The Bank of New York Mellon, as a Bank
By:	/s/ Richard K. Fronapfel, Jr.
	Name:	Richard K. Fronapfel, Jr.
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-22

CoBank, ACB, as a Bank
By:	/s/ Josh Batchelder
	Name:	Josh Batchelder
	Title:	Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-23

Banco Bilbao Vizcaya Argentaria, SA- New York Branch, as a Bank
By:	/s/ Michael Oka
	Name:	Michael Oka
	Title:	Executive Director
By:	/s/ Michael D’Anna
	Name:	Michael D’Anna
	Title:	Executive Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-24

CIBC Inc., as a Bank
By:	/s/ Robert W. Casey, Jr.
	Name:	Robert Casey
	Title:	Authorized Signatory
By:	/s/ Josh Hogarth
	Name:	Josh Hogarth
	Title:	Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-25

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Bank
By:	/s/ Tom Byargeon
	Name:	Tom Byargeon
	Title:	Managing Director
By:	/s/ Sharada Manne
	Name:	Sharada Manne
	Title:	Director

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-26

Sovereign Bank, as a Bank
By:	/s/ Robert D. Lanigan
	Name:	Robert D. Lanigan
	Title:	SVP

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-27

THE HUNTINGTON NATIONAL BANK, as a Bank
By:	/s/ Brian H. Gallagher
	Name:	Brian H. Gallagher
	Title:	Senior Vice President

[Signature Page to FirstEnergy Solutions Corp./Allegheny Energy Supply Company, LLC Credit Agreement]

S-28

SCHEDULE I

List of Commitments and Lending Offices

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
JPMorgan Chase Bank, N.A.	$	111,111,111.11	1111 Fannin, 10th Floor	Same as Domestic
			Houston, TX 77002-6925	Lending Office
			Account Manager: Leslie Hill
			Phone: (713) 750-2318
			Fax: (713) 427-6307
			Email: leslie.d.hill@chase.com
Bank of America, N.A.	$	111,111,111.11	104 N Tryon Street, Floor 17	Same as Domestic
			Charlotte, NC 28155-0001	Lending Office
			Contact: Mike Mason
			Phone: (980) 683-1839
			Fax: (980) 233-7196
			Email: Michael.mason@baml.com
Barclays Bank PLC	$	111,111,111.11	745 Seventh Avenue	Same as Domestic
			New York, NY 10019	Lending Office
			Contact: Adam Stewart
			Phone: (201) 499-3220
			Fax: (212) 412-7401
			Email: adam.stewart@barcap.com
			Group Email: xrausloanops1@barclayscapital.com
The Royal Bank of Scotland plc	$	111,111,111.11	600 Washington Boulevard, Stamford,	Same as Domestic
			Connecticut 06901	Lending Office
			Contact: John Ferrante
			Phone: (203) 897-7623
			Fax: (203) 873-5300
			Email: john.ferrante@rbs.com
			Group Email: gbmnaagency@rbs.com
Citibank, N.A.	$	111,111,111.11	399 Park Ave, 16th Floor 5	Same as Domestic
			New York, NY 10043	Lending Office
			Contact: Loan Administration
			Phone: (302) 894-6052
			Fax: (212) 994-0847
			Email: GLOriginationOps@citi.com

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
KeyBank National Association	$	111,111,111.11	124 Public Square	Same as Domestic
			Cleaveland, OH 44114	Lending Office
			Contact: Yvette Dyson-Owens
			Phone: (216) 689-4815
			Fax: (216) 370-6119
			Email: Yvette_M_Dyson-Owens@Keybank.com
The Bank of Nova Scotia	$	111,111,111.11	1 Liberty Plaza	Same as Domestic
			New York, NY 10006	Lending Office
			Contact: Melissa McMillan
			Phone: (212) 225-5705
			Fax: (212) 225-5709
			Email: mellissa_mcmillan@scotiacapital.com
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$	55,555,555.56	1251 Avenue of the Americas	Same as Domestic
			New York, NY 10020-1104	Lending Office
			Contact: Mr. Jamie Velez
			Phone: (201) 413-8586
			Fax: (201) 521-2304
Union Bank, N.A.	$	55,555,555.56	445 S. Figueroa Street, 15th Floor	Same as Domestic
			Los Angeles, CA 90071	Lending Office
			Contact: Commercial Loan Operations
			Fax: (800) 446-9951
			Email: synd@unionbank.com
Wells Fargo Bank, National Association	$	111,111,111.11	301 S. College St., 15th Floor	Same as Domestic
			MAC: D1053-150	Lending Office
			Charlotte, NC 28202
			Contact: Michelle P Field
			Phone: (303) 863-5411
			Fax: (303) 863-2729
			Email: Michelle.p.field@wellsfargo.com
Morgan Stanley Bank, N.A.	$	108,333,333.33	1000 Lancaster Street	Same as Domestic
			Baltimore, MD 21202	Lending Office
			Phone: (443) 627-4355
			Fax: (718) 233-2140
			Email: msloanservicing@morganstanley.com

2

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
BNP Paribas	$	108,333,333.33	787 Seventh Avenue	Same as Domestic
			New York, NY 10019	Lending Office
			Contact: Denis O’Meara
			Phone: (212) 471-8108
			Fax: (212) 841-2745
			Email: denis.omeara@us.bnpparibas.com
Credit Suisse AG	$	108,333,333.33	Eleven Madison Avenue	Same as Domestic
			New York, NY 10010	Lending Office
			Contact: Vijaykumar Kalji
			Phone: +91 20 6673 4371
			Fax: (866) 469-3871
			Email: vijaykumar.kalji@credit-suisse.com
Goldman Sachs Bank USA	$	108,333,333.33	200 West Street	Same as Domestic
			New York, NY 10282	Lending Office
			Contact: Operations
			Phone: (212) 902-1099
			Fax: (212) 977-3966
			Email: gs-sbd-admin-contacts@ny.email.gs.com
Royal Bank of Canada	$	108,333,333.33	Three World Financial Center	Same as Domestic
			5th Floor	Lending Office
			New York, NY 10281
			Contact: Manager, Loans Administration
			Phone: (212) 428-6322
			Fax: (212) 428-2372
UBS AG, Stamford Branch	$	108,333,333.33	677 Washington Blvd.	Same as Domestic
			Stamford, CT 06901	Lending Office
			Contact: Samantha Mason
			Phone: (203) 719-4839
			Fax: (203) 719-3390
			Email: Samantha.mason@ubs.com
Mizuho Corporate Bank, LTD.	$	92,777,777.78	1251 Avenue of the Americas	Same as Domestic
			New York, NY 10020	Lending Office

3

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
PNC Bank, National Association	$	92,777,777.78	249 First Avenue	Same as Domestic
			Pittsburgh, PA 15222	Lending Office
			Contact: Maja Kuljic
			Phone: (440) 546-7364
			Fax: (877) 728-2851
			Email: Participationla8brv@pnc.com
Sumitomo Mitsui Banking Corporation	$	92,777,777.78	277 Park Avenue	Same as Domestic
			6th Floor	Lending Office
			New York, NY 10172
			Contact: Delma Mitchell
			Phone: (212) 224-4387
			Fax: (212) 224-4391
			Email: Delma_c_mitchell@smbcgroup.com
U.S. Bank National Association	$	92,777,777.78	National Corporate Banking	Same as Domestic
			CN-OH-W8	Lending Office
			425 Walnut Street, 8th Floor
			Cincinnati, OH 45202
			Contact: Eric Cosgrove
			Phone: (513) 632-3033
			Fax: (513) 632-2068
			Email: eric.cosgrove@usbank.com
The Bank of New York Mellon	$	92,777,777.78	1 Wall Street, 19th Floor	Same as Domestic
			New York, NY 10286	Lending Office
			Contact: Amber Mierek
			Phone: (315) 765-4300
			Fax: (315) 765-4782
			Email: amber.mierek@bnymellon.com
CoBank, ACB	$	69,444,444.44	5500 South Quebec St.	Same as Domestic
			Greenwood Village, CO 80111	Lending Office
			Contact: Graham Kaiser
			Phone: (303) 740-4386
			Fax: (303) 740-4021
			Email: agencybank@cobank.com

4

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
Banco Bilbao	$	66,666,666.67	1345 Avenue of the Americas	Same as Domestic
Vizcaya Argentaria, S.A.			45th Floor	Lending Office
			New York, NY 10105
			Contact: C&I Banking
			Phone: (212) 728-2382
			Fax: (212) 333-2926
			Email: cibny@grupobbva.com
CIBC	$	66,666,666.67	425 Lexington Avenue, 4th Floor	Same as Domestic
			New York, NY 10017	Lending Office
			Contact: Angela Tom
			Phone: (416) 542-4446
			Fax: (905) 948-1934
			Email: Angela.Tom@cibc.ca
Credit Agricole	$	66,666,666.67	1301 Avenue of the Americas	Same as Domestic
Corporate and			New York, NY 10019	Lending Office
Investment Bank
			Contact: Dixon Schultz
			Phone: (713) 890-8607
			Fax: (713) 890-8668
			Email: dixon.schultz@ca-cib.com
Sovereign Bank	$	66,666,666.67	75 State Street	Same as Domestic
			Boston, MA 02109	Lending Office
			Contact: Roxaine Ovid
			Phone: (610) 988-1261
			Fax: (484) 338-2831
			Email: participations@sovereignbank.com
The Huntington	$	50,000,000.00	41 South High Street	Same as Domestic
National Bank			Columbus, OH 43215	Lending Office
			Contact: Shefali Patel
			Phone: (614) 480-5677
			Fax: (614) 480-2249
			Email: Shefali.patel@huntington.com
TOTAL	$	2,500,000,000

5

SCHEDULE II

List of L/C Fronting Bank Commitments

		L/C Fronting Bank
Fronting Bank	Fronting Bank Address	Commitment
JPMorgan Chase Bank, N.A.	Global Trade Services,	$	257,200,000
	10420 Highland Manor Drive
	Floor 4, Tampa, FL 33610-9128
	Attention: Letter of Credit Department
	Fax: (813) 432-5162
	Email: James.Alonzo@jpmchase.com
Bank of America, N.A.	100 North Tryon Street	$	357,200,000
	Charlotte, NC 28255
	Contact: John Yzeik
	Phone: (570) 330-4315
	Fax: (800) 755-4186
	Email: john.p.yzeik@baml.com
The Royal Bank of Scotland plc	600 Washington Boulevard, Stamford,	$	100,000,000
	Connecticut 06901
	Contact: Richard Emmich
	Phone: (203) 897-7619
	Fax: (212) 401-1494
	Email: richard.emmich@rbs.com
Citibank, N.A.	399 Park Ave, 16th Floor 5	$	357,200,000
	New York, NY 10043
	Contact: Loan Administration
	Phone: (302) 894-6052
	Fax: (212) 994-0847
	Email: GLOriginationOps@citi.com
KeyBank National Association	127 Public Square	$	357,200,000
	Cleveland, OH 44114
	Contact: Yvette Dyson-Owens
	Phone: (216) 689-4815
	Fax: (216) 370-6119
	Email: Yvette_M_Dyson-Owens@Keybank.com

		L/C Fronting Bank
Fronting Bank	Fronting Bank Address	Commitment
The Bank of Nova Scotia	1 Liberty Plaza	$	357,200,000
	New York, NY 10006
	Contact: Melissa McMillan
	Phone: (212) 225-5705
	Fax: (212) 225-5709
	Email: mellissa_mcmillan@scotiacapital.com
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	1251 Avenue of the Americas	$	357,200,000
	New York, NY 10020-1104
	Contact: Mr. Jamie Velez
	Phone: (201) 413-8586
	Fax: (201) 521-2304
Wells Fargo Bank, National Association	301 S. College Street, 15th Floor	$	357,200,000
	MAC: D1053-150
	Charlotte, NC 28202
	Contact: Elaine Shue
	Phone: (704) 715-3133
	Fax: (877) 487-0377
	Email: Elaine.Shue@wachovia.com

2

SCHEDULE III

List of Swing Line Commitments

Swing Line Lender	Swing Line Commitment
JPMorgan Chase Bank, N.A.	$	125,000,000
Bank of America, N.A.	$	125,000,000

SCHEDULE IV

Letters of Credit

Please see attached.

SCHEDULE V

Existing Facilities

1. $1,000,000,000 Credit Agreement, dated as of September 24, 2009, among Allegheny, the banks, financial institutions and other institutional lenders party thereto, Bank of America, N.A. and The Bank of Nova Scotia, as the initial issuing banks for the letters of credit issued or to be issued thereunder, and Bank of America, N.A., as Administrative Agent.

2. $2,750,000,000 Credit Agreement, dated as of August 24, 2006, as amended as of November 2, 2007, among FES, certain other borrowers named therein, the lenders and fronting banks parties thereto and Citibank, N.A., as administrative agent.

SCHEDULE VI

Disclosure Documents

None.

EXHIBIT A
Form of Assignment and Assumption

ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [the][each]¹ Assignor identified in item 1 below ([the][each, an] “Assignor”) and [the][each]² Assignee identified in item 2 below ([the][each, an] “Assignee”). [It is understood and agreed that the rights and obligations of [the Assignors][the Assignees]³ hereunder are several and not joint.]⁴ Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, the “Credit Agreement”), receipt of a copy of which is hereby acknowledged by [the][each] Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, [the][each] Assignor hereby irrevocably sells and assigns to [the Assignee][the respective Assignees], and [the][each] Assignee hereby irrevocably purchases and assumes from [the Assignor][the respective Assignors], subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of [the Assignor’s][the respective Assignors’] rights and obligations in [its capacity as a Lender][their respective capacities as Lenders] under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of [the Assignor][the respective Assignors] under the respective facilities identified below (including without limitation any letters of credit, guarantees, and swing line loans included in such facilities), and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of [the Assignor (in its capacity as a Lender)][the respective Assignors (in their respective capacities as Lenders)] against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by [the][any] Assignor to [the][any] Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as [the][an] “Assigned Interest”). Each such sale and assignment is without recourse to [the][any] Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by [the][any] Assignor.

1.	Assignor[s]:                  __________________
	__________________
	[Assignor [is] [is not] a Defaulting Lender]

1	For bracketed language here and elsewhere in this form relating to the Assignor(s), if the assignment is from a single Assignor, choose the first bracketed language. If the assignment is from multiple Assignors, choose the second bracketed language.
2	For bracketed language here and elsewhere in this form relating to the Assignee(s), if the assignment is to a single Assignee, choose the first bracketed language. If the assignment is to multiple Assignees, choose the second bracketed language.
3	Select as appropriate.
4	Include bracketed language if there are either multiple Assignors or multiple Assignees.

2.	Assignee[s]:
	[for each Assignee, indicate [Affiliate][Approved Fund] of [identify Lender]
3.	Borrowers: Company, LLC	FirstEnergy Solutions Corp. and Allegheny Energy Supply
4.	Administrative Agent:	JPMorgan Chase Bank, .N.A. as the administrative agent under the Credit Agreement
5.	Credit Agreement:	The $2,500,000,000 Credit Agreement dated as of June 17, 2011 among FirstEnergy Solutions Corp. and Allegheny Energy Supply Company, LLC, as Borrowers, the Lenders parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the fronting banks and swing line lenders party thereto
6.	Assigned Interest[s]:

			Amount of	Percentage
		Aggregate Amount of	Commitment/	Assigned of
		Commitment/Advances	Advances	Commitment/		CUSIP
Assignor[s]5	Assignee[s]6	for all Lenders7	Assigned8	Advances8		Number
		$	$		%
		$	$		%
		$	$		%

[7. Trade Date:  _________]⁹

[Page break]

5	List each Assignor, as appropriate.
6	List each Assignee, as appropriate.
7	Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.
8	Set forth, to at least 9 decimals, as a percentage of the Commitment/Advances of all Lenders thereunder.
9	To be completed if the Assignor(s) and the Assignee(s) intend that the minimum assignment amount is to be determined as of the Trade Date.

A-2

Effective Date: ______  _____, 201____  [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR[S]10 [NAME OF ASSIGNOR]
By:
	Name:
	Title:
[NAME OF ASSIGNOR]
By:
	Name:
	Title:
ASSIGNEE[S]11 [NAME OF ASSIGNEE]
By:
	Name:
	Title:
[NAME OF ASSIGNEE]
By:
	Name:
	Title:

[Consented to and]¹² Accepted:

10	Add additional signature blocks as needed. Include both Fund/Pension Plan and manager making the trade (if applicable).
11	Add additional signature blocks as needed. Include both Fund/Pension Plan and manager making the trade (if applicable).

A-3

JPMORGAN CHASE BANK, N.A., as   Administrative Agent
By:
	Name:
	Title:
Consented to:
[LIST ALL FRONTING BANKS]., as a Fronting Bank
By:
	Name:
	Title:
[LIST ALL SWING LINE LENDERS], as a Swing Line Lender
By:
	Name:
	Title:
[FIRSTENERGY CORP.
By:
	Name:
	Title:
ALLEGHENY ENERGY SUPPLY COMPANY, LLC
By:
	Name:
	Title: ]13

12	To be added only if the consent of the Administrative Agent is required by the terms of the Credit Agreement.
13	To be added only if the consent of the Borrowers are required by the terms of the Credit Agreement.

A-4

ANNEX 1

$2,500,000,000 Credit Agreement, dated as of June 17, 2011, among FirstEnergy Solutions Corp. and Allegheny Energy Supply Company, LLC, as Borrowers, the Lenders parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, and the fronting banks and swing line lenders party thereto

STANDARD TERMS AND CONDITIONS FOR
ASSIGNMENT AND ASSUMPTION

1. Representations and Warranties.

1.1 Assignor[s]. [The][Each] Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of [the][the relevant] Assigned Interest, (ii) [the][such] Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and (iv) it is [not] a Defaulting Lender; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrowers, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document, or (iv) the performance or observance by the Borrowers, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2. Assignee[s]. [The][Each] Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all the requirements to be an assignee under Section 8.08(b)(iii), (v) and (vi) of the Credit Agreement (subject to such consents, if any, as may be required under Section 8.08(b)(iii) of the Credit Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of [the][the relevant] Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 5.01(g) thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, (vi) it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, and (vii) if it is not a U.S. Person, attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement (including pursuant to Section 2.16(e)(ii) of the Credit Agreement), duly completed and executed by [the][such] Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, [the][any] Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2. Payments. From and after the Effective Date, the Administrative Agent shall make all payments in respect of [the][each] Assigned Interest (including payments of principal, interest, fees and other amounts) to [the][the relevant] Assignor for amounts which have accrued to but excluding the Effective Date and to [the][the relevant] Assignee for amounts which have accrued from and after the Effective Date. Notwithstanding the foregoing, the Administrative Agent shall make all payments of interest, fees or other amounts paid or payable in kind from and after the Effective Date to [the][the relevant] Assignee.

3. General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by telecopy shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of New York.

EXHIBIT B
Form of Note

PROMISSORY NOTE

U.S.$[_____]  _____  _____, 20____ 

FOR VALUE RECEIVED, the undersigned, [FIRSTENERGY SOLUTIONS CORP., an Ohio corporation] [ALLEGHENY ENERGY SUPPLY COMPANY, LLC, a Delaware limited liability company] (the “Borrower”), HEREBY PROMISES TO PAY to [_____] (the “Lender”) for the account of its Applicable Lending Office (such term and other capitalized terms herein being used as defined in the Credit Agreement referred to below), or its registered assigns, the principal sum of U.S.$[_____] or, if less, the aggregate principal amount of the Advances made by the Lender to the Borrower pursuant to the Credit Agreement outstanding on the Termination Date, payable on the Termination Date.

The Borrower promises to pay interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount is paid in full, at such interest rates, and payable at such times, as are specified in the Credit Agreement.

Both principal and interest are payable in lawful money of the United States of America to JPMorgan Chase Bank, N.A., as Administrative Agent, at [INSERT PAYMENT ADDRESS], in same day funds. Each Advance made by the Lender to the Borrower pursuant to the Credit Agreement, and all payments made on account of principal thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto which is part of this Promissory Note.

This Promissory Note is one of the Notes referred to in, and is entitled to the benefits of, the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Borrower, [FirstEnergy Solutions Corp.,] [Allegheny Energy Supply Company, LLC,] the banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time. The Credit Agreement, among other things, (i) provides for the making of Advances by the Lender to the Borrower from time to time in an aggregate amount not to exceed at any time outstanding the Dollar amount first above mentioned, the indebtedness of the Borrower resulting from each such Advance being evidenced by this Promissory Note, and (ii) contains provisions for acceleration of the maturity hereof upon the happening of certain stated events and also for prepayments on account of principal hereof prior to the maturity hereof upon the terms and conditions therein specified.

The Borrower hereby waives presentment, demand, protest and notice of any kind. No failure to exercise, and no delay in exercising, any rights hereunder on the part of the holder hereof shall operate as a waiver of such rights.

THIS PROMISSORY NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[FIRSTENERGY SOLUTIONS CORP.]
[ALLEGHENY ENERGY SUPPLY COMPANY, LLC]
By:
	Name: Title:

B-2

EXHIBIT C
Form of Notice of Pro-Rata Borrowing

JPMorgan Chase Bank, N.A., as Administrative Agent
  for the Lenders party to the Credit Agreement
  referred to below

 _____ _____, 200____ 

Ladies and Gentlemen:

The undersigned refers to the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, [FirstEnergy Solutions Corp.,] [Allegheny Energy Supply Company, LLC,] the banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Credit Agreement that the undersigned hereby requests [a] Pro-Rata Borrowing[s] under the Credit Agreement, and in that connection sets forth below the information relating to such Pro-Rata Borrowing[s] (the “Proposed Borrowing[s]”) as required by Section 2.02(a) of the Credit Agreement:

(i) The Business Day of the Proposed Borrowing[s] is  _____,  _____.

(ii) The Type of Pro-Rata Advance to be made in connection with the [First] Proposed Borrowing is [an Alternate Base Rate Pro-Rata Advance] [a Eurodollar Rate Advance]. The aggregate amount of such Proposed Borrowing is $_____. [The Interest Period for each Eurodollar Rate Advance made as part of such Proposed Borrowing is  _____  [week][month[s]].]

[(iii) The Type of Pro-Rata Advance to be made in connection with the [Second] Proposed Borrowing is [an Alternate Base Rate Pro-Rata Advance] [a Eurodollar Rate Advance]. The aggregate amount of such Proposed Borrowing is $_____. [The Interest Period for each Eurodollar Rate Advance made as part of such Proposed Borrowing is  _____  [week][month[s]].]

[(iii)][(iv)] The Borrower requesting the Proposed Borrowing[s] is  _____.

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing[s]:

(A) the representations and warranties of such Borrower contained in Section 4.01 [(other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof)]* of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing[s] and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of the Proposed Borrowing[s], in which case, such representation and warranty is true and correct as of such specific date);

(B) no event has occurred and is continuing, or would result from such Proposed Borrowing[s] or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower; and

(C) immediately following such Proposed Borrowing[s], (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment and (3) the Outstanding Credits for the account of any Borrower shall not exceed the Borrower Sublimit for such Borrower.

Please transfer or credit the funds to the following account:

Bank:  _____ 

Address:  _____ 

ABA #:  _____ 

Account #:  _____ 

Beneficiary:  _____ 

[remainder of page intentionally left blank]

* Delete for initial Extension of Credit.

C-2

Very truly yours,
[FIRSTENERGY SOLUTIONS CORP.]
[ALLEGHENY ENERGY SUPPLY COMPANY, LLC]**
By:
	Name: Title:

** Please use a separate Notice of Pro-Rata Borrowing for each Borrower.

C-3

EXHIBIT D
Form of Notice of Swing Line Borrowing

JPMorgan Chase Bank, N.A., as Administrative Agent
  for the Lenders party to the Credit Agreement
  referred to below

 _____ _____, 200____ 

Ladies and Gentlemen:

The undersigned refers to the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, [FirstEnergy Solutions Corp.,] [Allegheny Energy Supply Company, LLC,] the banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time, and hereby gives you notice, irrevocably, pursuant to Section 2.03 of the Credit Agreement that the undersigned hereby requests a Swing Line Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Swing Line Borrowing (the “Proposed Borrowing”) as required by Section 2.03(b) of the Credit Agreement:

(i) The Business Day of the Proposed Borrowing is  _____,  _____.

(ii) The aggregate amount of the Proposed Borrowing is $_____.

(iii) The Borrower requesting the Proposed Borrowing is  _____.

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing:

(A) the representations and warranties of such Borrower contained in Section 4.01 [(other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof)]* of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of the Proposed Borrowing, in which case, such representation and warranty is true and correct as of such specified date);

* Delete for initial Extension of Credit.

(B) no event has occurred and is continuing, or would result from such Proposed Borrowing or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower ; and

(C) immediately following such Proposed Borrowing, (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment, (3) the Outstanding Credits for the account of any Borrower shall not exceed the Borrower Sublimit for such Borrower, and (4) the aggregate principal amount of the Swing Line Advances outstanding shall not exceed the Swing Line Sublimit.

Please transfer or credit the funds to the following account:

Bank:  _____ 

Address:  _____ 

ABA #:  _____ 

Account #:  _____ 

Beneficiary:  _____ 

Very truly yours,
[FIRSTENERGY SOLUTIONS CORP.]
[ALLEGHENY ENERGY SUPPLY COMPANY, LLC]
By:
	Name: Title:

D-2

EXHIBIT E
Form of Letter of Credit Request

 _____ _____, 200_____ 

JPMorgan Chase Bank, N.A., as Administrative Agent
[INSERT ADMINISTRATIVE AGENT’S ADDRESS]
Attn:  _____ 

[_____, as Fronting Bank
[ADDRESS]]

Ladies and Gentlemen:

The undersigned, [FIRSTENERGY SOLUTIONS CORP. an Ohio corporation], [ALLEGHENY ENERGY SUPPLY COMPANY, LLC, a Delaware limited liability company] (the “Borrower”), refer to that certain Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among FirstEnergy Solutions Corp., Allegheny Energy Supply Company, LLC, the banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time. Capitalized terms used herein, and not otherwise defined herein, shall have their respective defined meanings as set forth in the Credit Agreement.

Pursuant to Section 2.04(d) of the Credit Agreement, the Borrower irrevocably requests that the Fronting Bank to which this Letter of Credit Request is addressed issue a Letter of Credit on the following terms:

1. Date of Issuance:

2. Expiration Date:

3. Stated Amount:

4. Beneficiary:

5. Account Party:

and the terms set forth in the attached application for said Letter of Credit.

The Borrower hereby further certifies that (i) as of the date hereof, (ii) as of the Date of Issuance and (iii) after the issuance of the Letter of Credit requested hereby:

(A) the representations and warranties of such Borrower contained in Section 4.01 [(other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof)]* of the Credit Agreement are true and correct on and as of the date hereof, before and after giving effect to the issuance of such Letter of Credit and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of the issuance of such Letter of Credit, in which case, such representation and warranty is true and correct as of such specified date);

(B) no event has occurred and is continuing, or would result from the issuance of the Letter of Credit requested hereby or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower; and

(C) immediately following the issuance of such Letter of Credit, (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment [and] [,] (3) the Stated Amount thereof, when aggregated with (x) the Stated Amount of each other Letter of Credit that is outstanding or with respect to which a Letter of Credit Request has been received and (y) the outstanding Reimbursement Obligations, shall not exceed the L/C Commitment Amount [and (2) the aggregate Stated Amount of all outstanding Letters of Credit issued by the Fronting Bank will not exceed $]**.

If notice of the request for the above referenced Letter of Credit has been given by the Borrower previously by telephone, then this notice shall be considered a written confirmation of such telephone notice as required by Section 2.04(d) of the Credit Agreement.

[FIRSTENERGY SOLUTIONS CORP.]
[ALLEGHENY ENERGY SUPPLY COMPANY, LLC]
By:
	Name: Title:

*	Delete for initial Extension of Credit.
**	Insert applicable Fronting Bank L/C Fronting Bank Commitment.

E-2

EXHIBIT F
Form of Opinion of Wendy E. Stark, Associate General Counsel of FE

[LETTERHEAD OF FIRSTENERGY CORP.]

June 17, 2011

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto

Re: Credit Agreement, dated as of June 17, 2011

Ladies and Gentlemen:

I am Associate General Counsel of FirstEnergy Corp., an Ohio corporation (“FE”) and have acted as counsel to its subsidiaries, FirstEnergy Solutions Corp., an Ohio corporation (“FES”), and Allegheny Energy Supply Company, LLC, a Delaware limited liability company (“Allegheny”, and together with FES, the “Borrowers” and each a “Borrower”), in connection with the transactions contemplated by the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Borrowers, the banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto and the swing line lenders party thereto. Capitalized terms used herein but not otherwise defined herein shall have the respective meanings assigned to them in the Credit Agreement. This opinion is being furnished to you pursuant to Section 3.01(a)(v) of the Credit Agreement. The Credit Agreement and the Notes are sometimes referred to in this opinion collectively as the “Loan Documents” and each individually as a “Loan Document”.

For purposes of this opinion, I or persons under my supervision and control have reviewed executed originals or copies of executed originals of the Credit Agreement and each Note delivered on the date hereof. I or persons under my supervision and control have also reviewed originals or copies of such corporate records and other documents and matters and have made such investigation of fact and law as I have considered relevant or necessary as a basis for this opinion. In such review, I have assumed the accuracy and completeness of all agreements, documents, records, certificates and other materials submitted to us, the conformity with the originals of all such materials submitted to us as copies (whether or not certified and including facsimiles), the authenticity of the originals of such materials and all materials submitted to us as originals, the genuineness of all signatures (other than those on behalf of the Borrowers) and the legal capacity of all natural persons.

G-1

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 2

I have also assumed (a) the due organization, valid existence and good standing under the laws of its jurisdiction of incorporation of each party (other than FES) to each Loan Document, (b) the corporate or other power and due authorization of each Person (other than FES) not a natural person to execute, deliver and perform its obligations under each Loan Document to which it is a party, (c) the due execution and delivery of each Loan Document by each party thereto (other than FES), and (d) that each Loan Document constitutes the valid and binding obligation of each party thereto, enforceable against such party in accordance with its terms. As to various questions of fact relevant to this opinion, I have relied, without independent investigation, upon certificates of public officials, certificates of officers of the Borrowers and representations and warranties of the Borrowers contained in the Credit Agreement.

I am a member of the Bar of the State of Ohio, and, for purposes of this opinion, I do not hold myself out as an expert on the laws of any jurisdiction other than the laws of the State of Ohio. I express no opinion herein as to the application or effect of the laws of any jurisdiction other than the laws of the State of Ohio.

Based on the foregoing and such legal considerations as I have deemed necessary or advisable to express this opinion, I am of the opinion that:

1. FES is a corporation duly incorporated, validly existing and in good standing under the laws of the State of Ohio, is duly qualified to do business as a foreign corporation in and is in good standing under the laws of each other state in which the ownership of its properties or the conduct of its business makes such qualification necessary, except where the failure to be so qualified would not have a Material Adverse Effect, and has all corporate powers to carry on its business as now conducted and to maintain and operate its property and business.

2. No Governmental Action is or will be required under laws of the State of Ohio for (a) the due execution or delivery by FES of any Loan Document or the performance by FES of its obligations thereunder or (b) the consummation by FES of any transaction contemplated by the Loan Documents, other than (1) such Governmental Action as may be required as a condition to the exercise by FES of its rights under Section 2.06(b) or Section 2.07 of the Credit Agreement and (2) such Governmental Action as may be required after the date hereof in connection with the performance by FES of the general covenants set forth in Sections 5.01(a) and (b) of the Credit Agreement.

3. The execution and delivery by FES of each of the Loan Documents to which it is a party, the performance by FES of its obligations under such Loan Documents, the consummation by FES of the transactions contemplated by any such Loan Document, and compliance by FES with the provisions thereof, will not result in (a) a breach or contravention of any of the provisions of the Organizational Documents of FES or (b) a breach or contravention of any Applicable Law of the State of Ohio.

F-2

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 3

4. The execution and delivery by each Borrower of each of the Loan Documents to which it is a party, the performance by such Borrower of its obligations under such Loan Documents, the consummation by such Borrower of the transactions contemplated by any such Loan Document, and compliance by such Borrower with the provisions thereof, will not result in (a) a breach or contravention of any of the provisions of any indenture, mortgage, lease or other agreement or instrument to which such Borrower or any Subsidiary of such Borrower is a party or by which any of its property is bound or (b) the creation or imposition of any Lien upon any property of such Borrower or of any Subsidiary of such Borrower, except in each case to the extent such breach or contravention, or the creation or imposition of any such Lien, would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect with respect to such Borrower.

5. The execution, delivery and performance by FES of each of the Loan Documents to which it is a party are within its corporate powers, have been duly authorized by all necessary corporate action on the part of FES and do not, and will not, require the consent or approval of FES’s shareholders, other than such consents and approvals as have been duly obtained, given or accomplished.

6. The Credit Agreement and each Note executed and delivered by FES on the date hereof has been duly executed and delivered by FES.

Except as disclosed in any Borrower’s Disclosure Documents, there is no pending or, to the best of my knowledge, threatened action or proceeding (including, without limitation, any proceeding relating to or arising out of Environmental Laws) affecting directly such Borrower or any of its Subsidiaries before any court, governmental agency or arbitrator that would reasonably be expected to have a material adverse effect on such Borrower’s ability to perform its obligations under the Loan Documents to which it is a party.

The opinions set forth herein are qualified in their entirety and subject to the following:

A. No examination has been made of, and no opinion is expressed as to the effect of, any zoning ordinance or permit pertaining to the authority of the Borrowers to operate their properties or conduct their businesses.

B. I also express no opinion with respect to (i) the solvency of any Borrower; or (ii) the compliance of the Credit Agreement or any other Loan Document or the transactions contemplated thereby with, or the effect of any of the foregoing with respect to, Federal and state securities Laws, rules and regulations.

F-3

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 4

C. This opinion and the matters addressed herein are as of the date hereof or such earlier date as is specified herein, and I undertake no, and hereby disclaim any, obligation to advise you of any change in any matter set forth herein, whether based on a change in the law, a change in any fact relating to the Borrowers or any other Person, or any other circumstance occurring after the date hereof.

D. I have assumed that no fraud, dishonesty, forgery, coercion, duress or breach of fiduciary duty exists with respect to any of the matters relevant to this opinion.

E. This opinion is limited to the matters expressly set forth herein and no opinion is to be implied or may be inferred beyond the matters expressly stated herein.

F. This opinion is solely for the benefit of the addressees hereof in connection with the transactions contemplated by the Credit Agreement and may not be relied on by the addressees hereof for any other purpose or furnished or quoted to or relied on by any other Person (other than the permitted successors and assigns of such addressees under the Credit Agreement) for any purpose without my prior written consent.

Respectfully submitted,

Wendy E. Stark
Associate General Counsel

F-4

EXHIBIT G
Form of Opinion of Akin Gump Strauss Hauer & Feld LLP

June 17, 2011

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto

Re: Credit Agreement, dated as of June 17, 2011

Ladies and Gentlemen:

We have acted as special New York counsel to FirstEnergy Solutions Corp., an Ohio corporation (“FES”), and Allegheny Energy Supply Company, LLC, a Delaware limited liability company (“Allegheny”, together with FES, the “Borrowers” and each a “Borrower”), in connection with the execution and delivery of the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Borrowers, the banks party thereto, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto and the swing line lenders party thereto. Capitalized terms used herein but not otherwise defined herein shall have the respective meanings assigned to them in the Credit Agreement. This opinion is being furnished to you at the request of the Borrowers pursuant to Section 3.01(a)(vi) of the Credit Agreement. The Credit Agreement and the Notes are sometimes referred to in this opinion collectively as the “Loan Documents” and each individually as a “Loan Document”.

The document listed on Schedule I hereto is hereinafter referred to in this opinion as the “Certificate of Good Standing.”

In connection with this opinion, we have reviewed executed originals or copies of executed originals of the Certificate of Good Standing, the Credit Agreement and the form of the Notes attached thereto. We have also reviewed copies of the Approvals and originals or certified copies of such corporate and company records of each Borrower and other certificates and documents of officials of each Borrower and certain of their affiliates, public officials and others as we have deemed appropriate for purposes of this opinion, and relied upon them to the extent we deem appropriate. As to various questions of fact relevant to this opinion, we have relied, without independent investigation, upon certificates of public officials, certificates of officers of each Borrower, and representations and warranties of each Borrower contained in the Credit Agreement. In addition, we have made no inquiry of any Borrower or any other Person (including Governmental Authorities) regarding any judgments, orders, decrees, franchises, licenses, certificates, registrations, permits or other public records or agreements to which any Borrower is a party other than those described herein, and our knowledge of any such matters is accordingly limited.

G-1

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 2

We have assumed the genuineness of all signatures, the authenticity of all documents submitted to us as originals, and the conformity to authentic original documents of all copies submitted to us as conformed, certified or reproduced copies. We have also assumed (i) the due organization, valid existence and good standing under the laws of its jurisdiction of incorporation of each party to each Loan Document (other than, with respect to valid existence and good standing, Allegheny), (ii) the legal capacity of natural persons, (iii) the corporate or other power and due authorization of each Person (other than Allegheny) not a natural person to execute, deliver and perform its obligations under each Loan Document to which it is a party, (iv) the due execution and delivery of each Loan Document by all parties thereto (other than Allegheny), (v) that each Loan Document constitutes the valid and binding obligation of each party thereto (other than the Borrowers), enforceable against such party in accordance with its terms, (vi) that the execution, delivery and performance by each party to the Loan Documents (other than Allegheny) do not, and will not, require the consent or approval of its shareholders or members, as the case may be, and will not result in a breach or violation of, or conflict with, any of the provisions of its Organizational Documents, (vii) that the execution, delivery and performance by any party to the Loan Documents will not result in (a) a breach or contravention of, or conflict with, any of the provisions of any indenture, mortgage, lease or other agreement or instrument to which it is a party or (b) a breach or violation of, or conflict with, any law (other than, in the case of any Borrower, any Included Law (as defined herein)) or any order, rule, regulation or determination of any Governmental Authority applicable to it (other than, in the case of any Borrower, its Approval) and (vii) that all required Governmental Action (other than, in the case of any Borrower, under any Included Law) for the execution and delivery by each party to any Loan Document, the performance by it of its obligations thereunder or the consummation by it of any transaction contemplated thereby have been obtained or taken.

Based upon the foregoing and subject to the assumptions, exceptions, qualifications and limitations set forth herein, we are of the opinion that:

1. Allegheny is duly existing as a limited liability company, in good standing under the laws of the State of Delaware, and has the limited liability company power and authority to enter into and perform its obligations under each of the Loan Documents to which it is a party.

2. Each of the Loan Documents to which Allegheny is a party (a) has been duly authorized by all necessary limited liability company action by Allegheny and (b) has been duly executed and delivered by Allegheny.

3. No Governmental Action is or will be required under any Included Law for the due execution and delivery by each Borrower of each Loan Document to which it is a party or the performance by it of its obligations thereunder, other than (i) the Approvals, each of which is in full force and effect as of the date hereof, and (ii) such Governmental Action as may be required after the date hereof in connection with the performance by such Borrower of the general covenants set forth in Sections 5.01(a) and (b) of the Credit Agreement.

G-2

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 3

4. The execution and delivery by each Borrower of each Loan Document to which it is a party do not, and the performance by such Borrower of its obligations under each such Loan Document will not, result in a breach or violation of (i) any Included Law, (ii) the Approvals, or (iii) the Organizational Documents of Allegheny listed on Schedule II hereto.

5. The Credit Agreement constitutes a valid and binding obligation of each Borrower, enforceable against each Borrower in accordance with its terms.

6. Each Note, when properly completed and executed by the applicable Borrower and delivered in exchange for value, will constitute a valid and binding obligation of such Borrower, enforceable against such Borrower in accordance with its terms.

The opinions set forth herein are qualified in their entirety and subject to the following:

A. We express no opinion as to the Laws (as defined below) of any jurisdiction other than the Included Laws. We have made no special investigation or review of any published constitutions, treaties, laws, rules or regulations or judicial or administrative decisions (“Laws”), other than a review of (i) the Laws of the State of New York, (ii) the Delaware Limited Liability Company Act, as amended, and (iii) the Federal Laws of the United States of America. For purposes of this opinion, the term “Included Laws” means the items described in (a) clause (ii) of the preceding sentence and (b) clauses (i) and (iii) of the preceding sentence that are, in our experience, normally applicable to transactions of the type contemplated by the Loan Documents. The term Included Laws specifically excludes (i) Laws of any counties, cities, towns, municipalities and special political subdivisions and any agencies thereof; (ii) zoning, land use, building and construction Laws; (iii) Federal Reserve Board margin regulations; and (iv) any environmental, labor, tax, pension, employee benefit, antiterrorism, money laundering, insurance, antitrust, securities or intellectual property Laws.

B. When used in this opinion, the phrases “known to us”, “to our knowledge” and similar phrases (i) mean the conscious awareness of facts or other information by (a) the lawyer in our firm who signed this letter, (b) any lawyer in our firm actively involved in negotiating and preparing the Loan Documents and (c) solely as to information relevant to a particular opinion, issue or confirmation regarding a particular factual matter, any lawyer in our firm who is primarily responsible for providing the response concerning that particular opinion, issue or confirmation, and (ii) do not require or imply (a) any examination of this firm’s, such lawyer’s or any other Person’s files, (b) that any inquiry be made of the client, any lawyer (other than the lawyers described above), or any other Person, or (c) any review or examination of any agreements, documents, certificates, instruments or other papers (including, but not limited to, the exhibits and schedules to the Loan Documents and the various papers referred to in or contemplated by the Loan Documents and the respective exhibits and schedules thereto) other than the Loan Documents.

G-3

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 4

C. The opinion expressed in paragraph 1 herein as to the valid existence and good standing of Allegheny is given solely on the basis of the Certificate of Good Standing and speaks only as of the date thereof rather than the date hereof. Such opinion is limited to the meaning ascribed to such Certificate of Good Standing by the State agency or official issuing such Certificate of Good Standing and applicable Law.

D. The matters expressed in this opinion are subject to and qualified and limited by (i) applicable bankruptcy, insolvency, fraudulent transfer and conveyance, reorganization, moratorium and similar laws affecting creditors’ rights and remedies generally from time to time in effect; (ii) general principles of equity (regardless of whether enforcement is sought in a proceeding at law or in equity); (iii) principles of commercial reasonableness and unconscionability and an implied covenant of good faith and fair dealing; (iv) the power of the courts to award damages in lieu of equitable remedies; and (v) securities Laws and public policy underlying such Laws with respect to rights to indemnification and contribution. Although it appears that the requirements of Section 5-1401 of the New York General Obligations Law have been met, we express no opinion on whether the choice of law provision in Section 8.09 of the Credit Agreement or in each Note would raise any issues under the United States constitution or in equity that would affect whether courts in New York would enforce the choice of New York law to govern the Credit Agreement or such Note. We have also assumed that the choice of law of the State of New York as the governing law of the Credit Agreement and each Note would not result in a violation of an important public policy of another state having greater contacts with the transactions contemplated by the Loan Documents than the State of New York.

E. The opinions expressed herein are as of the date hereof or such earlier date as is specified herein, and we undertake no, and hereby disclaim any, obligation to advise you of any change in any matter set forth herein, whether based on a change in the Law, a change in any fact relating to any Borrower or any other Person, or any other circumstance occurring after the date hereof. This opinion is limited to the matters expressly stated herein and no opinions are to be inferred or may be implied beyond the opinions expressly set forth herein.

F. We have assumed that no fraud, dishonesty, forgery, coercion, duress or breach of fiduciary duty exists with respect to any of the matters relevant to the opinions expressed in this letter.

G. We express no opinion as to (i) the compliance of the transactions contemplated by the Loan Documents with any Laws applicable to any Person other than the Borrowers; (ii) the financial condition or solvency of any Borrower; (iii) the ability (financial or otherwise) of any Borrower or any other Person to meet its obligations under the Loan Documents; (iv) the compliance of the Loan Documents or the transactions contemplated thereby with, or the effect on any of the opinions expressed herein of, the antifraud provisions of Federal and state securities Laws; (v) the conformity of the Loan Document to any term sheet or commitment letter; or (vi) any provision of any Loan Document which would, to the extent not permitted by applicable Law, restrict, waive access to or vary legal or equitable remedies or defenses (including, but not limited to, a right to notice of and hearing on matters relating to prejudgment remedies, service of process, proper jurisdiction and venue, forum non conveniens and the right to trial by jury) or the right to collect damages (including, but not limited to, actual, consequential, special, indirect, incidental, exemplary and punitive damages).

G-4

To the Banks party to the within-mentioned Credit Agreement,
JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 5

H. For purposes of this letter, the phrase “transactions of the type contemplated by the Loan Documents” and similar phrases mean (i) the making of Advances and the issuance of Letters of Credit by the banks party to the Credit Agreement and (ii) the performance by the Borrowers of their respective obligations under the Loan Documents.

I. This letter is solely for your benefit, and no other Person (other than your permitted successors and assigns under the Credit Agreement) shall be entitled to rely upon this opinion. Without our prior written consent, this opinion may not be quoted in whole or in part or otherwise referred to in any document and may not be furnished or otherwise disclosed to or used by any other Person, except for (i) delivery of copies hereof to counsel for the addressees hereof and (ii) inclusion of copies hereof in a closing file relating to the Credit Agreement.

Very truly yours,

AKIN, GUMP, STRAUSS, HAUER & FELD, L.L.P.

G-5

SCHEDLE I

CERTIFICATE OF GOOD STANDING

Certificate of Good Standing of Allegeny, issued by the Secretary of State of the State of Delaware on June 14, 2011.

G-6

SCHEDLE II

ORGANIZATIONAL DOCUMENTS

1.	Certificate of Formation of Allegheny, filed with the Secretary of State of the State of Delaware on November 12, 1999.
2.	Fifth Amended and Restated Limited Liability Company Agreement of Allegheny, effective as of September 4, 2003.

G-7

EXHIBIT H
Form of Opinion of
Special New York Counsel to the Administrative Agent

June 17, 2011

JPMorgan Chase Bank, N.A., as
administrative agent, the fronting banks, the
swing line lenders and the lenders party to
the Credit Agreement defined below

Re: FirstEnergy Solutions Corp. and Allegheny Energy Supply Company, LLC

Ladies and Gentlemen:

We have acted as special New York counsel to JPMorgan Chase Bank, N.A., individually and as administrative agent (the “Administrative Agent”), in connection with the preparation, execution and delivery of the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among FirstEnergy Solutions Corp., an Ohio corporation (“FES”), Allegheny Energy Supply Company, LLC, a Delaware limited liability Company (“Allegheny”, and together with FES, the “Borrowers”), JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto, the swing line lenders party thereto and the Banks party thereto. Unless otherwise defined herein, terms defined in the Credit Agreement are used herein as therein defined. This opinion is being delivered pursuant to Section 3.01(a)(vii) of the Credit Agreement.

In that connection, we have examined (i) counterparts of the Credit Agreement, executed by the Borrowers, the Banks, the Swing Line Lenders, the Administrative Agent and the Fronting Banks, (ii) a form of the Notes and (iii) the other documents furnished to the Administrative Agent pursuant to Section 3.01(a) of the Credit Agreement, including (without limitation) the opinions of Wendy E. Stark, Associate General Counsel of FE, counsel to the Borrowers, and Akin Gump Strauss Hauer & Feld LLP, special counsel to the Borrowers (such opinions referred to hereinafter, collectively, as the “Borrowers’ Counsel Opinions”).

In our examination of the documents referred to above, we have assumed the authenticity of all such documents submitted to us as originals, the genuineness of all signatures, the due authority of the parties executing such documents and the conformity to the originals of all such documents submitted to us as copies. We have also assumed that each of the Banks, the Swing Line Lenders, the Fronting Banks and the Administrative Agent have duly executed and delivered, with all necessary power and authority (corporate and otherwise), the Credit Agreement. We have further assumed that you have evaluated, and are satisfied with, the creditworthiness of the Borrowers and the business and financial terms evidenced by the Loan Documents.

To the extent that our opinions expressed below involve conclusions as to matters governed by law other than the law of the State of New York and the Federal law of the United States, we have relied upon the Borrowers’ Counsel Opinions and have assumed without independent investigation the correctness of the matters set forth therein, our opinions expressed below being subject to the assumptions, qualifications and limitations set forth in the Borrowers’ Counsel Opinions. As to matters of fact, we have relied solely upon the documents we have examined. We note that we do not represent the Borrowers, and accordingly, are not privy to the nature or character of their business. Accordingly, we have assumed that the Borrowers are subject only to statutes, rules, regulations, judgments, orders and other requirements of law generally applicable to corporations doing business in the State of New York.

Based upon the foregoing, and subject to the qualifications set forth below, we are of the opinion that:

(i) The Credit Agreement is, and each of the Notes when executed and delivered for value received will be, the legal, valid and binding obligation of each Borrower that is a party thereto enforceable against such Borrower in accordance with their respective terms.

(ii) While we have not independently considered the matters covered by the Borrowers’ Counsel Opinions to the extent necessary to enable us to express the conclusions stated therein, each of the Borrowers’ Counsel Opinions and the other documents furnished to the Administrative Agent pursuant to Section 3.01(a) of the Credit Agreement are substantially responsive to the corresponding requirements set forth in Section 3.01(a) of the Credit Agreement pursuant to which the same have been delivered.

Our opinions are subject to the following qualifications:

(a) Our opinion in paragraph (i) above is subject to the effect of any applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or similar law affecting creditors’ rights generally.

(b) Our opinion in paragraph (i) above is subject to the effect of general principles of equity, including (without limitation) concepts of materiality, reasonableness, good faith and fair dealing (regardless of whether considered in a proceeding in equity or at law).

(c) We note further that, in addition to the application of equitable principles described above, courts have imposed an obligation on contracting parties to act reasonably and in good faith in the exercise of their contractual rights and remedies, and may also apply public policy considerations in limiting the right of parties seeking to obtain indemnification under circumstances where the conduct of such parties in the circumstances in question is determined to have constituted negligence.

(d) We express no opinion herein as to (i) Section 8.06 of the Credit Agreement, (ii) the enforceability of provisions purporting to grant to a party conclusive rights of determination, (iii) the availability of specific performance or other equitable remedies, (iv) the enforceability of rights to indemnity under Federal or state securities laws and (v) the enforceability of waivers by parties of their respective rights and remedies under law.

H-2

(e) Our opinion in paragraph (i) is limited to the law of the State of New York and the Federal law of the United States, and we do not express any opinion herein concerning any other law. Without limiting the generality of the foregoing, we express no opinion as to the effect of the law of any jurisdiction other than the State of New York wherein any Lender may be located or wherein enforcement of the Credit Agreement or the Notes may be sought that limits the rates of interest legally chargeable or collectible.

(f) In connection with any provision of the Credit Agreement or the Notes whereby any Borrower submits to the jurisdiction of any court of competent jurisdiction, we note the limitations of 28 U.S.C. §§1331 and 1332 on Federal court of jurisdiction.

The foregoing opinion is solely for your benefit and may not be relied upon by any other Person other than any Person that may become a Lender under the Credit Agreement after the date hereof.

Very truly yours,

MEO:kty:mg

H-3

EXHIBIT I

TERMS AND CONDITIONS OF SUBORDINATION
FOR INDEBTEDNESS TO AFFILIATES

All Indebtedness (such term and other capitalized terms used herein, unless otherwise defined herein, shall have the meaning specified in the Credit Agreement to which this Exhibit I is attached), including, without limitation, under the Money Pool, incurred by any Borrower and owing to any Affiliate of such Borrower (other than any Subsidiary of such Borrower) shall be subject to the following terms and conditions, which shall be incorporated in a written agreement between the Borrower and any Affiliate to which any such Indebtedness is owed.

Section 1. Subordination of Liabilities. [Name of Company] (the “Company”), for itself, its successors and assigns, covenants and agrees and each holder of the indebtedness evidenced by [DESCRIBE INDEBTEDNESS DOCUMENTATION] (the “Subordinated Indebtedness”), by its acceptance thereof likewise covenants and agrees that the payment of the principal of, and interest on, and all other amounts owing in respect of, the Subordinated Indebtedness is hereby expressly subordinated, to the extent and in the manner hereinafter set forth, to the prior payment in full of Senior Indebtedness (as defined in Section 8) in cash. The subordination provisions set forth herein shall constitute a continuing offer to all persons who, in reliance upon such provisions, become holders of, or continue to hold, Senior Indebtedness, and such provisions are made for the benefit of the holders of Senior Indebtedness, and such holders are hereby made obligees hereunder to the same extent as if their names were written herein as such, and they and/or each of them may proceed to enforce such provisions.

SECTION 2. Company Not to Make Payments with Respect to Subordinated Indebtedness in Certain Circumstances. (a) Upon the maturity of any Senior Indebtedness (including interest thereon or fees or any other amounts owing in respect thereof), whether at stated maturity, by acceleration or otherwise, all principal thereof and premium, if any, and interest thereon or fees or any other amounts owing in respect thereof, in each case to the extent due and owing at such time, shall first be paid in full in cash, or such payment duly provided for in cash or in a manner satisfactory to the holder or holders of such Senior Indebtedness, before any payment is made on account of the principal of (including installments thereof), or interest on, or any amount otherwise owing in respect of, the Subordinated Indebtedness. Each holder of the Subordinated Indebtedness hereby agrees that, so long as any Specified Event of Default (as defined below) has occurred and is continuing, it will not ask, demand, sue for, or otherwise take, accept or receive, any amounts owing in respect of the Subordinated Indebtedness. As used herein, the term “Specified Event of Default” shall mean any Event of Default described in Section 6.01(a), (e), (f) or (j) of the Credit Agreement, and any Event of Default described in Section 6.01(c) of the Credit Agreement relating to a breach of Section 5.01(i) or (j), Section 5.02 or Section 5.03(a), (b) or (c) of the Credit Agreement.

(b) In the event that notwithstanding the provisions of the preceding subsection (a) of this Section 2, the Company shall make any payment on account of the principal of, or interest on, or amounts otherwise owing in respect of, the Subordinated Indebtedness at a time when payment is not permitted by said subsection (a), such payment shall be held by the holder of the Subordinated Indebtedness, in trust for the benefit of, and shall be paid forthwith over and delivered to, the holders of Senior Indebtedness or their representative or representatives under the agreements pursuant to which the Senior Indebtedness may have been issued, as their respective interests may appear, for application pro rata to the payment of all Senior Indebtedness remaining unpaid to the extent necessary to pay all Senior Indebtedness in full in cash in accordance with the terms of such Senior Indebtedness, after giving effect to any concurrent payment or distribution to or for the holders of Senior Indebtedness.

SECTION 3. Subordinated Indebtedness Subordinated to Prior Payment of all Senior Indebtedness on Dissolution, Liquidation or Reorganization of Company. Upon any distribution of assets of the Company upon any dissolution, winding up, liquidation or reorganization of the Company (whether in bankruptcy, insolvency or receivership proceedings or upon an assignment for the benefit of creditors or otherwise):

(a) the holders of all Senior Indebtedness shall first be entitled to receive payment in full in cash or in a manner satisfactory to the holder or holders of such Senior Indebtedness of the principal thereof, premium, if any, and interest (including, without limitation, all interest accruing after the commencement of any bankruptcy, insolvency, receivership or similar proceeding at the rate provided in the governing documentation whether or not such interest is an allowed claim in such proceeding) and all other amounts due thereon before the holder of the Subordinated Indebtedness is entitled to receive any payment on account of the principal of or interest on or any other amount owing in respect of the Subordinated Indebtedness;

(b) any payment or distribution of assets of the Company of any kind or character, whether in cash, property or securities to which the holder of the Subordinated Indebtedness would be entitled in respect of the Subordinated Indebtedness except for the subordination provisions set forth herein, shall be paid by the liquidating trustee or agent or other person making such payment or distribution, whether a trustee or agent, directly to the holders of Senior Indebtedness or their representative or representatives under the agreements pursuant to which the Senior Indebtedness may have been issued, to the extent necessary to make payment in full of all Senior Indebtedness remaining unpaid, after giving effect to any concurrent payment or distribution to the holders of such Senior Indebtedness; and

(c) in the event that, notwithstanding the foregoing provisions of this Section 3, any payment or distribution of assets of the Company of any kind or character, whether in cash, property or securities, shall be received by the holder of the Subordinated Indebtedness on account of principal of, or interest or other amounts due on, the Subordinated Indebtedness before all Senior Indebtedness is paid in full in cash or in a manner satisfactory to the holder or holders of such Senior Indebtedness, or effective provisions made for its payment, such payment or distribution shall be received and held in trust for and shall be paid over to the holders of the Senior Indebtedness remaining unpaid or unprovided for or their representative or representatives under the agreements pursuant to which the Senior Indebtedness may have been issued, for application to the payment of such Senior Indebtedness until all such Senior Indebtedness shall have been paid in full in cash or in a manner satisfactory to the holder or holders of such Senior Indebtedness, after giving effect to any concurrent payment or distribution to the holders of such Senior Indebtedness.

2

SECTION 4. In Furtherance of Subordination. Each holder of the Subordinated Indebtedness agrees as follows:

(a) If any proceeding referred to in Section 3 above is commenced by or against the Company:

(i) the Administrative Agent, acting on behalf of each holder of the Senior Indebtedness, is hereby irrevocably authorized and empowered (in its own name or in the name of the holder of the Subordinated Indebtedness or otherwise), but shall have no obligation, to demand, sue for, collect and receive every payment or distribution referred to in Section 3(b) and give acquittance therefor and to file claims and proofs of claim and take such other action (including, without limitation, voting the claims arising under the Subordinated Indebtedness or enforcing any security interest or other lien securing payment of the Subordinated Indebtedness) as it may deem necessary or advisable for the exercise or enforcement of any of the rights or interests of the holders of the Senior Indebtedness hereunder; and

(ii) each holder of the Subordinated Indebtedness shall duly and promptly take such action as the holders of the Senior Indebtedness may request (A) to collect the Subordinated Indebtedness for the account of the holders of the Senior Indebtedness and to file appropriate claims or proofs of claim in respect of the Subordinated Indebtedness, (B) to execute and deliver to the holders of the Senior Indebtedness such powers of attorney, assignments, or other instruments as the holders of the Senior Indebtedness may request in order to enable the holders of the Senior Indebtedness to enforce any and all claims with respect to, and any security interests and other liens securing payment of, the Subordinated Indebtedness, and (C) to collect and receive any and all payments or distributions that may be payable or deliverable upon or with respect to the Subordinated Indebtedness.

(b) The holders of the Senior Indebtedness are hereby authorized to demand specific performance of this Agreement, whether or not the Company shall have complied with any of the provisions hereof applicable to it, at any time when the holder of the Subordinated Indebtedness shall have failed to comply with any of the provisions of this Agreement applicable to it. The holder of the Subordinated Indebtedness hereby irrevocably waives any defense based on the adequacy of a remedy at law that might be asserted as a bar to such remedy of specific performance.

3

SECTION 5. Subrogation. Subject to the prior payment in full of all Senior Indebtedness in cash, the holder of the Subordinated Indebtedness shall be subrogated to the rights of the holders of Senior Indebtedness to receive payments or distributions of assets of the Company applicable to the Senior Indebtedness until all amounts owing in respect of the Subordinated Indebtedness shall be paid in full, and for the purpose of such subrogation no payments or distributions to the holders of the Senior Indebtedness by or on behalf of the Company or by or on behalf of the holder of the Subordinated Indebtedness by virtue of the subordination provisions set forth herein that otherwise would have been made to the holder of the Subordinated Indebtedness, shall be deemed to be payment by the Company to or on account of the Senior Indebtedness, it being understood that the subordination provisions set forth herein are and are intended solely for the purpose of defining the relative rights of the holder of the Subordinated Indebtedness, on the one hand, and the holders of the Senior Indebtedness, on the other hand.

SECTION 6. Obligation of the Company Unconditional. Nothing contained in the subordination provisions set forth herein or in the documents evidencing the Subordinated Indebtedness is intended to or shall impair, as between the Company and the holder of the Subordinated Indebtedness, the obligation of the Company, which is absolute and unconditional, to pay to the holder of the Subordinated Indebtedness the principal of, interest on and all other amounts in respect of the Subordinated Indebtedness as and when the same shall become due and payable in accordance with its terms, or is intended to or shall affect the relative rights of the holder of the Subordinated Indebtedness and creditors of the Company other than the holders of the Senior Indebtedness, nor shall anything herein or therein prevent the holder of the Subordinated Indebtedness from exercising all remedies otherwise permitted by applicable law, subject to the rights, if any, under the subordination provisions set forth herein of the holders of Senior Indebtedness in respect of cash, property, or securities of the Company received upon the exercise of any such remedy. Upon any distribution of assets of the Company referred to herein, the holder of the Subordinated Indebtedness shall be entitled to rely upon any order or decree made by any court of competent jurisdiction in which such dissolution, winding up, liquidation or reorganization proceedings are pending, or a certificate of the liquidating trustee or agent or other person making any distribution to the holder of the Subordinated Indebtedness, for the purpose of ascertaining the persons entitled to participate in such distribution, the holders of the Senior Indebtedness and other indebtedness of the Company, the amount thereof or payable thereon, the amount or amounts paid or distributed thereon and all other facts pertinent thereto or hereto.

SECTION 7. Subordination Rights Not Impaired by Acts or Omissions of Company or Holders of Senior Indebtedness. No rights of any present or future holders of any Senior Indebtedness to enforce subordination as herein provided shall at any time in any way be prejudiced or impaired by an act or failure to act on the part of the Company or by any act or failure to act in good faith by any such holder, or by any noncompliance by the Company with the terms and provisions of the Subordinated Indebtedness, regardless of any knowledge thereof which any such holder may have or be otherwise charged with. The holders of the Senior Indebtedness may, without in any way affecting the obligations of the holder of the Subordinated Indebtedness with respect thereto, at any time or from time to time and in their absolute discretion, change the manner, place or terms of payment of, change or extend the time of payment of, or renew or alter, any Senior Indebtedness, or amend, modify or supplement any agreement or instrument governing or evidencing such Senior Indebtedness or any other document referred to therein, or exercise or refrain from exercising any other of their rights under the Senior Indebtedness including, without limitation, the waiver of a default thereunder and the release of any collateral securing such Senior Indebtedness, all without notice to or assent from the holder of the Subordinated Indebtedness.

4

SECTION 8. Senior Indebtedness. (a) The term “Senior Indebtedness” shall mean all Obligations (as defined below) of the Company under, or with respect to, the Credit Agreement (as defined below).

(b) As used in this Agreement, the terms set forth below shall have the respective meanings provided below:

“Credit Agreement” shall mean the Credit Agreement, dated as of June 17, 2011, among FES, Allegheny, the various financial institutions from time to time party thereto (the “Lenders”), JPMCB, as Administrative Agent, and certain other parties thereto acting as fronting banks and swing line lenders, together with the related documents thereto (including, without limitation, any guarantees and security documents), as same may be amended, modified, extended, renewed, restated or supplemented from time to time, and including any agreement extending the maturity of, refinancing or restructuring all or any portion of, or increasing the principal amount of, the indebtedness under such agreement or of any successor agreements.

“Obligations” shall mean any principal, interest, premium, penalties, fees, expenses, indemnities and other liabilities and obligations payable under the documentation governing the Senior Indebtedness (including, without limitation, all interest accruing after the commencement of any bankruptcy, insolvency, receivership or similar proceeding at the rate provided in the governing documentation, whether or not such interest is an allowed claim in such proceeding).

5

EXECUTION COPY

U.S. $2,000,000,000

CREDIT AGREEMENT

Dated as of June 17, 2011,

Among

FIRSTENERGY CORP.,

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY,

METROPOLITAN EDISON COMPANY,

OHIO EDISON COMPANY,

PENNSYLVANIA POWER COMPANY,

THE TOLEDO EDISON COMPANY,

AMERICAN TRANSMISSION SYSTEMS, INCORPORATED,

JERSEY CENTRAL POWER & LIGHT COMPANY,

MONONGAHELA POWER COMPANY,

PENNSYLVANIA ELECTRIC COMPANY,

THE POTOMAC EDISON COMPANY,

and

WEST PENN POWER COMPANY,
as Borrowers,

THE BANKS NAMED HEREIN,
as Banks,

THE ROYAL BANK OF SCOTLAND PLC,
as Administrative Agent,

THE FRONTING BANKS
PARTY HERETO FROM TIME TO TIME
as Fronting Banks

and

THE SWING LINE LENDERS PARTY
HERETO FROM TIME TO TIME
as Swing Line Lenders

RBS SECURITIES INC.	CITIGROUP GLOBAL MARKETS INC.
BARCLAYS CAPITAL	KEYBANK NATIONAL ASSOCIATION
J.P. MORGAN SECURITIES LLC	THE BANK OF NOVA SCOTIA
MERRILL LYNCH, PIERCE, FENNER & SMITH INCORPORATED	UNION BANK, N.A.
	THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
	WELLS FARGO SECURITIES, LLC

Joint Lead Arrangers

	CITIBANK, N.A.
	UNION BANK, N.A.
BARCLAYS CAPITAL	THE BANK OF NOVA SCOTIA
J.P. MORGAN SECURITIES LLC	THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.
MERRILL LYNCH, PIERCE, FENNER & SMITH INCORPORATED	KEYBANK NATIONAL ASSOCIATION
Syndication Agents	WELLS FARGO BANK, NATIONAL ASSOCIATION
	Documentation Agents

TABLE OF CONTENTS

	Page
ARTICLE I DEFINITIONS AND ACCOUNTING TERMS
SECTION 1.01. Certain Defined Terms		1
SECTION 1.02. Computation of Time Periods		23
SECTION 1.03. Accounting Terms		23
SECTION 1.04. Terms Generally		23
ARTICLE II AMOUNTS AND TERMS OF THE ADVANCES AND LETTERS OF CREDIT
SECTION 2.01. The Pro-Rata Advances		23
SECTION 2.02. Making the Pro-Rata Advances		24
SECTION 2.03. Swing Line Advances		25
SECTION 2.04. Letters of Credit		28
SECTION 2.05. Fees		36
SECTION 2.06. Reduction of the Commitments; Borrower Sublimits		37
SECTION 2.07. Repayment of Advances		37
SECTION 2.08. Interest on Advances		37
SECTION 2.09. Additional Interest on Advances		38
SECTION 2.10. Interest Rate Determination		38
SECTION 2.11. Conversion of Advances		39
SECTION 2.12. Prepayments		40
SECTION 2.13. Increased Costs		41
SECTION 2.14. Illegality		42
SECTION 2.15. Payments and Computations		43
SECTION 2.16. Taxes		45
SECTION 2.17. Sharing of Payments, Etc.		47
SECTION 2.18. Noteless Agreement; Evidence of Indebtedness		48
SECTION 2.19. Extension of Termination Date		48
SECTION 2.20. Several Obligations		50
SECTION 2.21. Defaulting Lenders		51
ARTICLE III CONDITIONS OF LENDING AND ISSUING LETTERS OF CREDIT
SECTION 3.01. Conditions Precedent to Initial Extension of Credit		52
SECTION 3.02. Conditions Precedent to Each Extension of Credit		54
ARTICLE IV REPRESENTATIONS AND WARRANTIES
SECTION 4.01. Representations and Warranties of the Borrowers		55
ARTICLE V COVENANTS OF THE BORROWERS
SECTION 5.01. Affirmative Covenants of the Borrowers		58
SECTION 5.02. Debt to Capitalization Ratio		61
SECTION 5.03. Negative Covenants of the Borrowers		62

i

	Page
ARTICLE VI EVENTS OF DEFAULT
SECTION 6.01. Events of Default		65
ARTICLE VII THE ADMINISTRATIVE AGENT
SECTION 7.01. Authorization and Action		68
SECTION 7.02. Administrative Agent’s Reliance, Etc.		68
SECTION 7.03. RBS and the Fronting Banks and Swing Line Lenders		69
SECTION 7.04. Lender Credit Decision; No Other Duties		69
SECTION 7.05. Indemnification		70
SECTION 7.06. Successor Administrative Agent		70
SECTION 7.07. Delegation of Duties		71
ARTICLE VIII MISCELLANEOUS
SECTION 8.01. Amendments, Etc.		71
SECTION 8.02. Notices, Etc.		72
SECTION 8.03. Electronic Communications		72
SECTION 8.04. No Waiver; Remedies		74
SECTION 8.05. Costs and Expenses; Indemnification		74
SECTION 8.06. Right of Set-off		76
SECTION 8.07. Binding Effect		76
SECTION 8.08. Assignments and Participations		76
SECTION 8.09. Governing Law		81
SECTION 8.10. Consent to Jurisdiction; Waiver of Jury Trial		81
SECTION 8.11. Severability		82
SECTION 8.12. Entire Agreement		82
SECTION 8.13. Execution in Counterparts		82
SECTION 8.14. USA PATRIOT Act Notice		82
SECTION 8.15. No Fiduciary Duty		83

ii

SCHEDULES AND EXHIBITS

Schedule I	—	List of Commitments and Lending Offices
Schedule II	—	List of L/C Fronting Bank Commitments
Schedule III	—	List of Swing Line Commitments
Schedule IV	—	Letters of Credit
Schedule V	—	Existing Facilities
Schedule VI	—	Disclosure Documents
Exhibit A	—	Form of Assignment and Assumption
Exhibit B	—	Form of Note
Exhibit C	—	Form of Notice of Pro-Rata Borrowing
Exhibit D	—	Form of Notice of Swing Line Borrowing
Exhibit E	—	Form of Letter of Credit Request
Exhibit F	—	Form of Opinion of Wendy E. Stark, Associate General Counsel of FE
Exhibit G	—	Form of Opinion of Akin Gump Strauss Hauer & Feld LLP
Exhibit H	—	Form of Opinion of King & Spalding LLP

iii

CREDIT AGREEMENT

CREDIT AGREEMENT, dated as of June 17, 2011, among FIRSTENERGY CORP. (“FE”), THE CLEVELAND ELECTRIC ILLUMINATING COMPANY (“CEI”), METROPOLITAN EDISON COMPANY (“Met-Ed”), OHIO EDISON COMPANY (“OE”), PENNSYLVANIA POWER COMPANY (“Penn”), THE TOLEDO EDISON COMPANY (“TE”), AMERICAN TRANSMISSION SYSTEMS, INCORPORATED (“ATSI”), JERSEY CENTRAL POWER & LIGHT COMPANY (“JCP&L”), MONONGAHELA POWER COMPANY (“MP”), PENNSYLVANIA ELECTRIC COMPANY (“Penelec”), THE POTOMAC EDISON COMPANY (“PE”) and WEST PENN POWER COMPANY (“West-Penn”, and together with FE, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec and PE, the “Borrowers”), the banks and other financial institutions (the “Banks”) listed on the signature pages hereof, The Royal Bank of Scotland plc (“RBS”), as Administrative Agent (the “Administrative Agent”) for the Lenders hereunder, the fronting banks party hereto from time to time and the swing line lenders party hereto from time to time.

PRELIMINARY STATEMENTS

(1) The Borrowers have requested that the Lenders establish a five-year unsecured revolving credit facility in the amount of $2,000,000,000 in favor of the Borrowers, all of which may be used for general corporate purposes and $700,000,000 of which may be used for the issuance of Letters of Credit.

(2) Subject to the terms and conditions of this Agreement, the Lenders severally, to the extent of their respective Commitments (as defined herein), are willing to establish the requested revolving credit facility in favor of the Borrowers.

NOW, THEREFORE, in consideration of the premises, the parties hereto agree as follows:

ARTICLE I
DEFINITIONS AND ACCOUNTING TERMS

SECTION 1.01. Certain Defined Terms.

As used in this Agreement, the following terms shall have the following meanings (such meanings to be equally applicable to both the singular and plural forms of the terms defined):

“Account Party” has the meaning set forth in Section 2.04(a).

“Additional Commitment Lender” has the meaning set forth in Section 2.19(d).

“Administrative Agent” has the meaning set forth in the preamble hereto.

“Administrative Questionnaire” means an Administrative Questionnaire in a form supplied by the Administrative Agent.

“Advance” means a Pro-Rata Advance or a Swing Line Advance.

“AESC” means Allegheny Energy Supply Company, LLC, a Delaware limited liability company, and any successor thereto.

“Affiliate” means, as to any Person, any other Person that, directly or indirectly, controls, is controlled by or is under common control with such Person or is a director or officer of such Person.

“Agreement” means this Credit Agreement, as amended, modified and supplemented from time to time.

“Alternate Base Rate” means, for any period, a fluctuating interest rate per annum as shall be in effect from time to time, which rate per annum shall at all times be equal to the highest of (i) the rate of interest per annum announced publicly by RBS from time to time, as its “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum (rounded upwards, if necessary, to the nearest 1/32 of 1%) appearing on Telerate Page 3750 (or any successor page) as displaying the London interbank offered rate for deposits in Dollars at approximately 11:00 a.m. (London time) such day for a term of one month plus 1%; provided, however, if more than one rate is specified on such service, the applicable rate shall be the arithmetic mean of all such rates plus 1%.

“Alternate Base Rate Advance” means an Alternate Base Rate Pro-Rata Advance or a Swing Line Advance.

“Alternate Base Rate Pro-Rata Advance” means a Pro-Rata Advance that bears interest as provided in Section 2.08(a).

“Anniversary Date” has the meaning set forth in Section 2.19(a).

“Applicable Law” means all applicable laws, statutes, treaties, rules, codes, ordinances, regulations, permits, certificates, orders, interpretations, licenses and permits of any Governmental Authority and judgments, decrees, injunctions, writs, orders or like action of any court, arbitrator or other judicial or quasi-judicial tribunal of competent jurisdiction (including those pertaining to health, safety or the environment or otherwise).

“Applicable Lending Office” means, with respect to each Lender, such Lender’s Domestic Lending Office in the case of an Alternate Base Rate Advance, and such Lender’s Eurodollar Lending Office in the case of a Eurodollar Rate Advance.

2

“Applicable Margin” means, for any Alternate Base Rate Advance or any Eurodollar Rate Advance made to any Borrower, the interest rate per annum set forth in the relevant row of the table below, determined by reference to the Reference Ratings for such Borrower from time to time in effect:

LEVEL 6

Reference

LEVEL 2

LEVEL 3

LEVEL 4

LEVEL 5

Ratings

Reference

Reference

Reference

Reference

lower than

LEVEL 1

Ratings lower

Ratings of

Ratings lower

Ratings

BB+ by S&P

Reference

than Level 1

lower than

than Level 3

lower than

and Ba1 by

Ratings at

but at least

Level 2 but at

but at least

Level 4 but at

Moody’s, or

least A- by

BBB+ by

least BBB by

BBB- by S&P

least BB+ by

no

BASIS FOR

S&P or A3 by

S&P or Baa1

S&P or Baa2

or Baa3 by

S&P or Ba1

Reference

PRICING

Moody’s.

by Moody’s.

by Moody’s.

Moody’s.

by Moody’s.

Ratings.

Applicable Margin for Eurodollar Rate Advances

1.25

%

1.50

%

1.75

%

2.00

%

2.25

%

2.50

%

Applicable Margin for Alternate Base Rate Advances

0.25

%

0.50

%

0.75

%

1.00

%

1.25

%

1.50

%

For purposes of the foregoing, (i) if there is a difference of one level in Reference Ratings of S&P and Moody’s and the higher of such Reference Ratings falls in Level 1, Level 2, Level 3, Level 4 or Level 5, then the higher Reference Rating will be used to determine the pricing level and (ii) if there is a difference of more than one level in Reference Ratings of S&P and Moody’s, the Reference Rating that is one level above the lower of such Reference Ratings will be used to determine the pricing level, unless the lower of such Reference Ratings falls in Level 6, in which case the lower of such Reference Ratings will be used to determine the pricing level. If there exists only one Reference Rating, such Reference Rating will be used to determine the pricing level.

“Approval” means (i) with respect to CEI, the CEI PUCO Order; (ii) with respect to Met-Ed, the Met-Ed FERC Order; (iii) with respect to OE, the OE PUCO Order; (iv) with respect to Penn, the Penn FERC Order, subject to any borrowing limitations contained in the Organizational Documents of Penn; (v) with respect to TE, the TE PUCO Order; (vi) with respect to ATSI, the ATSI PUCO Order; (vii) with respect to JCP&L, the JCP&L FERC Order, subject to any borrowing limitations contained in the Organizational Documents of JCP&L; (viii) with respect to MP, the MP FERC Order; (ix) with respect to Penelec, the Penelec FERC Order; (x) with respect to PE, the PE FERC Order and (xi) with respect to West-Penn, the West-Penn FERC Order, in each case as amended, extended, supplemented, replaced or renewed from time to time to authorize the performance by such Borrower of this Agreement and each other Loan Document to which it is, or is to become, a party and the consummation by such Borrower of the transactions contemplated hereby and thereby, including, without limitation, the Borrowings hereunder.

3

“Approved Fund” means any Fund that is administered or managed by (i) a Lender, (ii) an Affiliate of a Lender or (iii) an entity or an Affiliate of an entity that administers or manages a Lender.

“Assignment and Assumption” means an assignment and assumption entered into by a Lender and an assignee of such Lender, and accepted by the Administrative Agent, in substantially the form of Exhibit A hereto.

“ATSI” has the meaning set forth in the preamble hereto.

“ATSI PUCO Order” means the order of the PUCO, dated December 8, 2010, that authorizes ATSI to obtain Extensions of Credit until December 31, 2011, as amended, extended, supplemented, replaced or renewed from time to time.

“Attributable Securitization Obligations” has the meaning set forth in the definition of “Permitted Securitization”.

“Authorized Officer” means, with respect to any notice, certificate or other communication to be delivered by any Borrower hereunder, the chief executive officer, president, chief financial officer, treasurer, assistant treasurer or controller of such Borrower, which officer shall have all necessary corporate or limited liability company authorization to deliver such notice, certificate or other communication.

“Available Commitment” means, for each Lender, the excess of such Lender’s Commitment over such Lender’s Percentage of the Outstanding Credits. “Available Commitments” shall refer to the aggregate of the Lenders’ Available Commitments hereunder.

“Bankruptcy Code” means the Bankruptcy Reform Act of 1978, as amended from time to time, and any Federal law with respect to bankruptcy, insolvency, reorganization, liquidation, moratorium or similar laws affecting creditors’ rights generally.

“Bankruptcy Event” means, with respect to any Person, such Person has become the subject of a bankruptcy or insolvency proceeding, or has had a receiver, conservator, trustee, administrator, custodian, assignee for the benefit of creditors or similar Person charged with the reorganization or liquidation of its business appointed for it, or, in the good faith determination of the Administrative Agent, has taken any action in furtherance of, or indicating its consent to, approval of, or acquiescence in, any such proceeding or appointment, provided that a Bankruptcy Event shall not result solely by virtue of any ownership interest, or the acquisition of any ownership interest, in such Person by a Governmental Authority or instrumentality thereof, provided, further, that such ownership interest does not result in or provide such Person with immunity from the jurisdiction of courts within the United States or from the enforcement of judgments or writs of attachment on its assets or permit such Person (or such Governmental Authority or instrumentality) to reject, repudiate, disavow or disaffirm any contracts or agreements made by such Person.

4

“Banks” has the meaning set forth in the preamble hereto.

“Beneficiary” means any Person designated by an Account Party to whom a Fronting Bank is to make payment, or on whose order payment is to be made, under a Letter of Credit.

“Borrower” has the meaning set forth in the preamble hereto.

“Borrower Extension Notice Date” has the meaning set forth in Section 2.19(a).

“Borrower Sublimit” means, as to any Borrower, the amount set forth opposite such Borrower’s name below:

Borrower	Borrower Sublimit
FE	$	2,000,000,000
CEI	$	500,000,000
Met-Ed	$	300,000,000
OE	$	500,000,000
Penn	$	50,000,000
TE	$	500,000,000
ATSI	$	100,000,000
JCP&L	$	425,000,000
MP	$	150,000,000
Penelec	$	300,000,000
PE	$	150,000,000
West-Penn	$	200,000,000

“Borrowing” means a Pro-Rata Borrowing or a Swing Line Borrowing.

“Business Day” means a day of the year on which banks are not required or authorized to close in New York City or Akron, Ohio and, if the applicable Business Day relates to any Eurodollar Rate Advances, a day on which dealings are carried on in the London interbank market.

“CEI” has the meaning set forth in the preamble hereto.

“CEI PUCO Order” means the order of the PUCO, dated December 8, 2010, that authorizes CEI to obtain Extensions of Credit until December 31, 2011, as amended, extended, supplemented, replaced or renewed from time to time.

5

“Change in Law” means the occurrence, after the date of this Agreement, of any of the following: (i) the adoption or taking effect of any law, rule, regulation or treaty, (ii) any change (other than any change by way of imposition or increase of reserve requirements included in the Eurodollar Rate Reserve Percentage) in any law, rule, regulation or treaty or in the administration, interpretation or application thereof by any Governmental Authority or (iii) the making or issuance of any request, guideline or directive (whether or not having the force of law) by any Governmental Authority; provided, however, the Dodd-Frank Wall Street Reform and Consumer Protection Act, and all requests, rules, guidelines and directives promulgated thereunder, and all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to have been introduced or adopted after the date of this Agreement, regardless of the date enacted or adopted.

“Change of Control” has the meaning set forth in Section 6.01(j).

“Code” means the United States Internal Revenue Code of 1986, as amended from time to time, and the applicable regulations thereunder.

“Commitment” means, as to any Lender, the amount set forth opposite such Lender’s name on Schedule I hereto or, if such Lender has entered into any Assignment and Assumption, set forth for such Lender in the Register maintained by the Administrative Agent pursuant to Section 8.08(c), as such amount may be reduced pursuant to Section 2.06.

“Commodity Trading Obligations” means the obligations of any Person under any commodity swap agreement, commodity future agreement, commodity option agreement, commodity cap agreement, commodity floor agreement, commodity collar agreement, commodity hedge agreement, commodity forward contract or derivative transaction and any put, call or other agreement, arrangement or transaction, including natural gas, power, emissions forward contracts, renewable energy credits, or any combination of any such arrangements, agreements and/or transactions, employed in the ordinary course of such Person’s business, including such Person’s energy marketing, trading and asset optimization business. The term “commodity” shall include electric energy and/or capacity, transmission rights, coal, petroleum, natural gas, fuel transportation rights, emissions allowances, weather derivatives and related products and by-products and ancillary services.

“Communications” has the meaning set forth in Section 8.03(a).

“Consolidated Debt” means, with respect to any Borrower at any date of determination the aggregate Indebtedness of such Borrower and its Consolidated Subsidiaries determined on a consolidated basis in accordance with GAAP, but shall not include (i) Nonrecourse Indebtedness of such Borrower and any of its Subsidiaries, (ii) obligations under leases that shall have been or should be, in accordance with GAAP, recorded as operating leases in respect of which such Borrower or any of its Consolidated Subsidiaries is liable as a lessee, (iii) the aggregate principal and/or face amount of Attributable Securitization Obligations of such Borrower and its Consolidated Subsidiaries and (iv) the aggregate principal amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Obligations not exceeding 15% of the Total Capitalization of such Borrower and its Consolidated Subsidiaries (determined, for purposes of such calculation, without regard to the amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Debt Obligations outstanding of such Borrower); provided that the amount of any mandatory principal amortization or defeasance of Trust Preferred Securities or Junior Subordinated Deferred Interest Debt Obligations prior to the Termination Date shall be included in this definition of Consolidated Debt.

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“Consolidated Subsidiary” means, as to any Person, any Subsidiary of such Person the accounts of which are or are required to be consolidated with the accounts of such Person in accordance with GAAP.

“Controlled Group” means all members of a controlled group of corporations and all trades or businesses (whether or not incorporated) under common control that, together with any Borrower and its Subsidiaries, are treated as a single employer under Section 414(b), (c) or (m) or 414(o) of the Code.

“Convert”, “Conversion” and “Converted” each refers to a conversion of Pro-Rata Advances of one Type into Pro-Rata Advances of another Type or the selection of a new, or the renewal of the same, Interest Period for Eurodollar Rate Advances pursuant to Section 2.10 or 2.11.

“Credit Parties” has the meaning set forth in Section 8.15 hereto.

“Cross-Default Provision” has the meaning set forth in Section 5.03(f) hereto.

“Date of Issuance” means the date of issuance by a Fronting Bank of a Letter of Credit under this Agreement.

“Debt to Capitalization Ratio” means, for any Borrower, the ratio of Consolidated Debt of such Borrower to Total Capitalization of such Borrower.

“Defaulting Lender” means any Lender that (i) has failed, within three Business Days of the date required to be funded or paid, to (A) fund any portion of its Advances, (B) fund any portion of its participations in Letters of Credit or Swing Line Advances or (C) pay over to the Administrative Agent, any Fronting Bank or any Swing Line Lender any other amount required to be paid by it hereunder, unless, in the case of clause (A) or (B) above, such Lender notifies the Administrative Agent in writing that such failure is the result of such Lender’s good faith determination that a condition precedent to funding (specifically identified and including the particular default, if any) has not been satisfied, (ii) has notified any Borrower or the Administrative Agent, any Fronting Bank or any Swing Line Lender in writing, or has made a public statement to the effect, that it does not intend or expect to comply with any of its funding obligations under this Agreement (unless such writing or public statement indicates that such position is based on such Lender’s good faith determination that a condition precedent (specifically identified and including the particular default, if any) to funding a loan under this Agreement cannot be satisfied) or generally under other agreements in which it commits to extend credit, (iii) has failed, within three Business Days after written request by the Administrative Agent, any Fronting Bank or any Swing Line Lender, acting in good faith, to provide a certification in writing from an authorized officer of such Lender that it will comply with its obligations to fund prospective Advances and participations in then outstanding Letters of Credit and Swing Line Advances under this Agreement, provided that such Lender shall cease to be a Defaulting Lender pursuant to this clause (iii) upon the Administrative Agent’s, such Fronting Bank’s or such Swing Line Lender’s (as applicable) receipt of such certification in form and substance reasonably satisfactory to it and the Administrative Agent, or (iv) has become the subject of a Bankruptcy Event.

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“Disclosure Documents” means (i) with respect to any Borrower that is required to file reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, such Borrower’s Annual Report on Form 10-K for the year ended December 31, 2010, Quarterly Report on Form 10-Q for the quarter ended March 31, 2011 and Current Reports on Form 8-K filed in 2011 prior to the date hereof and (ii) with respect to any Borrower that is not required to file reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, (A) such Borrower’s consolidated balance sheets as of December 31, 2010, and the related consolidated statements of income, retained earnings and cash flows for the fiscal year then ended, certified by PricewaterhouseCoopers LLP or Deloitte & Touche LLP, as applicable, and unaudited consolidated balance sheets as of March 31, 2011 and related consolidated statements of income, retained earnings and cash flows for the three-month period then ended, with, in each case (except for ATSI and Penn), any accompanying notes, all prepared in accordance with GAAP, and (B) the matters described in the portion of Schedule VI hereto applicable to such Borrower as indicated thereon.

“Dollars” and “$” each means lawful currency of the United States of America.

“Domestic Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Domestic Lending Office” opposite its name on Schedule I hereto or in the Assignment and Assumption pursuant to which it became a Lender, or such other office of such Lender as such Lender may from time to time specify to the Administrative Agent.

“Drawing” means a drawing by a Beneficiary under any Letter of Credit.

“Environmental Laws” means any federal, state or local laws, ordinances or codes, rules, orders, or regulations relating to pollution or protection of the environment, including, without limitation, laws relating to hazardous substances, laws relating to reclamation of land and waterways and laws relating to emissions, discharges, releases or threatened releases of pollutants, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes into the environment (including, without limitation, ambient air, surface water, ground water, land surface or subsurface strata) or otherwise relating to the manufacture, processing, distribution, use, treatment, storage, disposal, transport or handling of pollution, contaminants, chemicals, or industrial, toxic or hazardous substances or wastes.

“ERISA” means the Employee Retirement Income Security Act of 1974, and the regulations promulgated and rulings issued thereunder, each as amended, modified and in effect from time to time.

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“Eurocurrency Liabilities” has the meaning assigned to that term in Regulation D of the Board of Governors of the Federal Reserve System, as in effect from time to time.

“Eurodollar Lending Office” means, with respect to any Lender, the office of such Lender specified as its “Eurodollar Lending Office” opposite its name on Schedule I hereto or in the Assignment and Assumption pursuant to which it became a Lender (or, if no such office is specified, its Domestic Lending Office), or such other office of such Lender as such Lender may from time to time specify to the Administrative Agent.

“Eurodollar Rate” means, for the Interest Period for any Eurodollar Rate Advance made in connection with any Borrowing, the rate of interest per annum (rounded upward to the nearest 1/32 of 1%) appearing on Telerate Page 3750 (or any successor page) as the London interbank offered rate for deposits in Dollars at approximately 11:00 a.m. (London time) two Business Days before the first day of such Interest Period for a period equal to such Interest Period. If, for any reason, such rate is not available, the term “Eurodollar Rate” for such Interest Period shall mean an interest rate per annum equal to the average rate per annum (rounded upward to the nearest 1/32 of 1%) at which deposits in Dollars are offered by the Reference Banks to prime banks in the London interbank eurodollar market at 11:00 a.m. (London time) two Business Days before the first day of such Interest Period in an amount substantially equal to the Reference Banks’ respective Percentages of such Borrowing to be outstanding during such Interest Period and for a period equal to such Interest Period.

“Eurodollar Rate Advance” means an Advance that bears interest as provided in Section 2.08(b).

“Eurodollar Rate Reserve Percentage” of any Lender for the Interest Period for any Eurodollar Rate Advance means the reserve percentage applicable during such Interest Period (or if more than one such percentage shall be so applicable, the daily average of such percentages for those days in such Interest Period during which any such percentage shall be so applicable) under regulations issued from time to time by the Board of Governors of the Federal Reserve System (or any successor) for determining the maximum reserve requirement (including, without limitation, any emergency, supplemental or other marginal reserve requirement) for such Lender with respect to liabilities or assets consisting of or including Eurocurrency Liabilities having a term equal to such Interest Period.

“Event of Default” has the meaning set forth in Section 6.01.

“Exchange Act” means the Securities Exchange Act of 1934, and the regulations promulgated thereunder, in each case as amended and in effect from time to time.

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“Excluded Taxes” means, with respect to any Recipient of any payment to be made by or on account of any obligation of any Borrower hereunder, (i) income or franchise taxes imposed on (or measured by) the Recipient’s net income by the United States, or by the jurisdiction under the laws of which such Recipient is organized or in which its principal office is located or, in the case of any Lender, in which its Applicable Lending Office is located, (ii) any branch profits taxes imposed by the United States or any similar tax imposed by any other jurisdiction in which such Recipient is located, and (iii) any withholding taxes that (A) are imposed on amounts payable to such Recipient at the time such Recipient becomes a Recipient under this Agreement or designates a new lending office, except in each case to the extent that amounts with respect to such taxes were payable either (i) to such Recipient’s assignor immediately before such Recipient became a Recipient under this Agreement, or (ii) to such Recipient immediately before it designated a new lending office, (B) are attributable to such Recipient’s failure to comply with Section 2.16(e), or (C) are imposed as a result of a failure by such Recipient to satisfy the conditions for avoiding withholding under FATCA.

“Existing Facilities” means the credit facilities listed on Schedule V hereto.

“Existing Termination Date” has the meaning set forth in Section 2.19(a).

“Expiration Date” means, with respect to a Letter of Credit, its stated expiration date.

“Extension of Credit” means the making of any Advance or the issuance, extension or renewal, or any amendment that increases the Stated Amount, of a Letter of Credit.

“FATCA” means Sections 1471 through 1474 of the Code as of the date of this Agreement and any current or future regulations or official interpretations thereof.

“FE” has the meaning set forth in the preamble hereto.

“Federal Funds Rate” means, for any period, a fluctuating interest rate per annum equal for each day during such period to the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System arranged by Federal funds brokers, as published for such day (or, if such day is not a Business Day, for the next preceding Business Day) by the Federal Reserve Bank of New York, or, if such rate is not so published for any day that is a Business Day, the average (rounded upward to the nearest whole multiple of 1/100 of 1% per annum, if such average is not such a multiple) of the quotations for such day on such transactions received by the Administrative Agent from three Federal funds brokers of recognized standing selected by it.

“Fee Letters” means (i) the letter agreement, dated as of April 27, 2011, between FE and RBS, (ii) the letter agreement, dated as of April 27, 2011, among the Borrowers, RBS, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Bank of America, N.A., Barclays Bank PLC, J.P. Morgan Securities LLC, JPMorgan Chase Bank, N.A. and RBS Securities Inc., and (iii) the letter agreement, dated as of May 2, 2011, among the Borrowers, Citigroup Global Markets Inc., KeyBank National Association, The Bank of Nova Scotia, Union Bank, N.A., The Bank of Tokyo-Mitsubishi UFJ, Ltd., Wells Fargo Bank, National Association and Wells Fargo Securities, LLC, in each case, as amended, modified or supplemented from time to time.

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“FERC” means the Federal Energy Regulatory Commission or successor organization.

“FES” means FirstEnergy Solutions Corp., an Ohio corporation.

“FES/AESC Credit Agreement” means the Credit Agreement, dated as of June 17, 2011, among FES, AESC, the financial institutions from time to time party thereto as lenders, JPMorgan Chase Bank, N.A., as administrative agent, and the fronting banks and swing line lenders party thereto from time to time, as amended, restated, amended and restated, supplemented or otherwise modified from time to time.

“First Mortgage Indenture” means a first mortgage indenture pursuant to which any Borrower or any Subsidiary of a Borrower may issue bonds, notes or similar instruments secured by a lien on all or substantially all of such Borrower’s or such Subsidiary’s fixed assets, as the case may be.

“Foreign Lender” means any Lender that is organized under the laws of a jurisdiction other than that in which the Borrowers are resident for tax purposes. For purposes of this definition, the United States of America, each State thereof and the District of Columbia shall be deemed to constitute a single jurisdiction.

“Fraction” means, for any Borrower at any time, a fraction, the numerator of which shall be the Borrower Sublimit of such Borrower at such time, and the denominator of which shall be the sum of the Borrower Sublimits of all Borrowers at such time.

“Fronting Bank” means each Lender identified as a “Fronting Bank” on Schedule II and any other Lender (in each case, acting directly or through an Affiliate) that delivers an instrument in form and substance satisfactory to the Borrowers and the Administrative Agent whereby such other Lender (or its Affiliate) agrees to act as “Fronting Bank” hereunder and that specifies the maximum aggregate Stated Amount of Letters of Credit that such other Lender (or its Affiliates) will agree to issue hereunder.

“Fronting Bank Fee Letter” has the meaning set forth in Section 3.01(b).

“Fund” means any Person (other than a natural person) that is (or will be) engaged in making, purchasing, holding or otherwise investing in commercial loans and similar extensions of credit in the ordinary course of its business.

“GAAP” means generally accepted accounting principles in the United States in effect from time to time.

“Governmental Action” means all authorizations, consents, approvals, waivers, exceptions, variances, orders, licenses, exemptions, publications, filings, notices to and declarations of or with any Governmental Authority (other than requirements the failure to comply with which will not affect the validity or enforceability of any Loan Document or have a material adverse effect on the transactions contemplated by any Loan Document or any material rights, power or remedy of any Person thereunder or any other action in respect of any Governmental Authority).

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“Governmental Authority” means the government of the United States of America or any other nation, or of any political subdivision thereof, whether state or local, and any agency, authority, instrumentality, regulatory body, court, central bank or other entity exercising executive, legislative, judicial, taxing, regulatory or administrative powers or functions of or pertaining to government (including any supra-national bodies such as the European Union or the European Central Bank) and any group or body charged with setting financial accounting or regulatory capital rules or standards (including, without limitation, the Financial Accounting Standards Board, the Bank for International Settlements or the Basel Committee on Banking Supervision or any successor or similar authority to any of the foregoing).

“Hedging Obligations” mean, with respect to any Person, the obligations of such Person under any interest rate or currency swap agreement, interest rate or currency future agreement, interest rate collar agreement, interest rate or currency hedge agreement, and any put, call or other agreement or arrangement designed to protect such Person against fluctuations in interest rates or currency exchange rates.

“Hostile Acquisition” means any Target Acquisition (as defined below) involving a tender offer or proxy contest that has not been recommended or approved by the board of directors (or similar governing body) of the Person that is the subject of such Target Acquisition. As used in this definition, the term “Target Acquisition” means any transaction, or any series of related transactions, by which any Person directly or indirectly (i) acquires all or substantially all of the assets or ongoing business of any other Person, whether through purchase of assets, merger or otherwise, (ii) acquires (in one transaction or as the most recent transaction in a series of transactions) control of at least a majority in ordinary voting power of the securities of any such Person that have ordinary voting power for the election of directors or (iii) otherwise acquires control of more than a 50% ownership interest in any such Person.

“Indebtedness” of any Person means at any date, without duplication, (i) all obligations of such Person for borrowed money, or with respect to deposits or advances of any kind, or for the deferred purchase price of property or services other than trade accounts payable, (ii) all obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (iii) all obligations of such Person upon which interest charges are customarily paid, (iv) all obligations under leases that shall have been or should be, in accordance with GAAP, recorded as capital leases in respect of which such Person is liable as lessee, (v) withdrawal liability incurred under ERISA by such Person or any of its affiliates to any Multiemployer Plan, (vi) reimbursement obligations of such Person (whether contingent or otherwise) in respect of letters of credit, bankers acceptances, surety or other bonds and similar instruments, (vii) all Indebtedness of others secured by a Lien on any asset of such Person, whether or not such Indebtedness is assumed by such Person and (viii) obligations of such Person under direct or indirect guaranties in respect of, and obligations (contingent or otherwise) to purchase or otherwise acquire, or otherwise to assure a creditor against loss in respect of, indebtedness or obligations of others of the kinds referred to above.

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“Indemnified Person” has the meaning set forth in Section 8.05(c) hereto.

“Indemnified Taxes” means all Taxes (including Other Taxes) other than Excluded Taxes.

“Interest Period” means, for each Eurodollar Rate Advance made to any Borrower as part of the same Borrowing, the period commencing on the date of such Eurodollar Rate Advance or the date of the Conversion of any Pro-Rata Advance into such Eurodollar Rate Advance and ending on the last day of the period selected by such Borrower pursuant to the provisions below and, thereafter in the case of Pro-Rata Advances, each subsequent period commencing on the last day of the immediately preceding Interest Period and ending on the last day of the period selected by such Borrower pursuant to the provisions below. The duration of each such Interest Period shall be, in the case of any Eurodollar Rate Advance, one week or one, two, three or six months, in each case, as the applicable Borrower may select by notice to the Administrative Agent pursuant to Section 2.02(a) or Section 2.11(a); provided, however, that:

(i) no Borrower may select any Interest Period that ends after the latest Termination Date;

(ii) Interest Periods commencing on the same date for Advances made as part of the same Borrowing shall be of the same duration;

(iii) no more than five different Interest Periods shall apply to outstanding Eurodollar Rate Advances with respect to any Borrower on any date of determination, and no more than 20 different Interest Periods shall apply to outstanding Eurodollar Rate Advances with respect to all Borrowers on any date of determination; and

(iv) whenever the last day of any Interest Period would otherwise occur on a day other than a Business Day, the last day of such Interest Period shall be extended to occur on the next succeeding Business Day, provided, that if such extension would cause the last day of such Interest Period to occur in the next following calendar month, the last day of such Interest Period shall occur on the next preceding Business Day.

“ISDA Master Agreement” means the printed form of the 1992 ISDA Master Agreement (Multicurrency — Cross Border) or the 2002 ISDA Master Agreement (Multicurrency — Cross Border), as applicable, including any Schedule and Credit Support Annex thereto, as published by the International Swaps and Derivatives Association, Inc.

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“JCP&L” has the meaning set forth in the preamble hereto.

“JCP&L FERC Order” means the order of the FERC, dated March 10, 2010, that authorizes JCP&L to obtain Extensions of Credit until May 31, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

“Junior Subordinated Deferred Interest Debt Obligations” means subordinated deferrable interest debt obligations of any Borrower or any of its Subsidiaries (i) for which the maturity date is subsequent to the Termination Date and (ii) that are fully subordinated in right of payment to the Indebtedness hereunder.

“L/C Commitment Amount” means $700,000,000 as the same may be reduced permanently from time to time pursuant to Section 2.06.

“L/C Fronting Bank Commitment” means, with respect to any Fronting Bank, the aggregate Stated Amount of all Letters of Credit that such Fronting Bank agrees to issue, as modified from time to time pursuant to an agreement signed by such Fronting Bank. With respect to each Lender that is a Fronting Bank on the date hereof, such Fronting Bank’s L/C Fronting Bank Commitment shall equal such Fronting Bank’s “L/C Fronting Bank Commitment” listed on Schedule II, and (ii) with respect to any Lender that becomes a Fronting Bank after the date hereof, such Lender’s L/C Fronting Bank Commitment shall equal the amount agreed upon between the Borrowers and such Lender at the time that such Lender becomes a Fronting Bank, in each case as such L/C Fronting Bank Commitment may be modified in accordance with the terms of this Agreement.

“Lender Extension Notice Date” has the meaning set forth in Section 2.19(b).

“Lenders” means the Banks listed on the signature pages hereof and each assignee of a Bank or another Lender that shall become a party hereto pursuant to Section 8.08 and, as the context requires, includes the Swing Line Lenders.

“Letter of Credit” has the meaning set forth in Section 2.04(a).

“Letter of Credit Cash Cover” has the meaning set forth in Section 6.01.

“Letter of Credit Request” has the meaning set forth in Section 2.04(c).

“Lien” means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset. For the purposes of this Agreement, a Person or any of its Subsidiaries shall be deemed to own, subject to a Lien, any asset that it has acquired or holds subject to the interest of a vendor or lessor under any conditional sale agreement, capital lease or other title retention agreement relating to such asset.

“Loan Documents” means this Agreement, any Note, the Fee Letters and the Fronting Bank Fee Letters.

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“Majority Lenders” means, at any time prior to the Termination Date, Lenders having in the aggregate more than 50% of the Commitments (without giving effect to any termination in whole of the Commitments pursuant to Section 6.01) and at any time on or after the Termination Date, Lenders having more than 50% of the then aggregate Outstanding Credits of the Lenders; provided, that for purposes hereof, no Borrower, nor any of its Affiliates, if a Lender, shall be included in (i) the Lenders having such amount of the Commitments or the Advances or (ii) determining the total amount of the Commitments or the Outstanding Credits.

“Margin Stock” has the meaning assigned to that term in Regulation U issued by the Board of Governors of the Federal Reserve System, and as amended and in effect from time to time.

“Material Adverse Effect” means, with respect to any Borrower, (i) any material adverse effect on the business, property, operations or financial condition of such Borrower and its Consolidated Subsidiaries, taken as a whole, or (ii) any material adverse effect on the validity or enforceability against such Borrower of this Agreement or any Note.

“Met-Ed” has the meaning set forth in the preamble hereto.

“Met-Ed FERC Order” means the order of the FERC, dated March 10, 2010, that authorizes Met-Ed to obtain Extensions of Credit until May 31, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

“Moody’s” means Moody’s Investors Service, Inc.

“MP” has the meaning set forth in the preamble hereto.

“MP FERC Order” means the order of the FERC, dated June 29, 2010, that authorizes MP to obtain Extensions of Credit until June 29, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

“Multiemployer Plan” means a “multiemployer plan” as defined in Section 4001(a)(3) of ERISA to which any Borrower or any member of the Controlled Group is or may reasonably be expected to have an obligation to make, contributions, or with respect to which any Borrower may reasonably be expected to incur liability.

“New Fronting Bank” has the meaning set forth in Section 2.04(r).

“Nonconsenting Lender” has the meaning set forth in Section 2.19(b).

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“Nonrecourse Indebtedness” means, with respect to any Borrower and its Subsidiaries, (i) any Indebtedness that finances the acquisition, development, construction or improvement of an asset in respect of which the Person to which such Indebtedness is owed has no recourse whatsoever to such Borrower or any of its Affiliates and (ii) any Indebtedness existing on the date of this Agreement that finances the ownership or operation of an asset in respect of which the Person to which such Indebtedness is owed has no recourse whatsoever to such Borrower or any of its Affiliates, in each case of clauses (i) and (ii), other than:

(A)	recourse to the named obligor with respect to such Indebtedness (the “Debtor”) for amounts limited to the cash flow or net cash flow (other than historic cash flow) from the asset; and
(B)	recourse to the Debtor for the purpose only of enabling amounts to be claimed in respect of such Indebtedness in an enforcement of any security interest or lien given by the Debtor over the asset or the income, cash flow or other proceeds deriving from the asset (or given by any shareholder or the like in the Debtor over its shares or like interest in the capital of the Debtor) to secure the Indebtedness, but only if the extent of the recourse to the Debtor is limited solely to the amount of any recoveries made on any such enforcement; and
(C)	recourse to the Debtor generally or indirectly to any Affiliate of the Debtor, under any form of assurance, undertaking or support, which recourse is limited to a claim for damages (other than liquidated damages and damages required to be calculated in a specified way) for a breach of an obligation (other than a payment obligation or an obligation to comply or to procure compliance by another with any financial ratios or other tests of financial condition) by the Person against which such recourse is available.

“Note” means any promissory note issued at the request of a Lender pursuant to Section 2.18 in the form of Exhibit B hereto.

“Notice of Pro-Rata Borrowing” means a notice of a Pro-Rata Borrowing pursuant to Section 2.02(a), which shall be substantially in the form of Exhibit C.

“Notice of Swing Line Borrowing” means a notice of a Swing Line Borrowing pursuant to Section 2.03 which, if in writing, shall be substantially in the form of Exhibit D.

“OE” has the meaning set forth in the preamble hereto.

“OE PUCO Order” means the order of the PUCO, dated December 8, 2010, that authorizes OE to obtain Extensions of Credit until December 31, 2011, as amended, extended, supplemented, replaced or renewed from time to time.

“OECD” means the Organization for Economic Cooperation and Development.

“Organizational Documents” means, as applicable to any Person, the charter, code of regulations, articles of incorporation, by-laws, certificate of formation, operating agreement, certificate of partnership, limited liability company agreement, operating agreement, partnership agreement, certificate of limited partnership, limited partnership agreement or other constitutive documents of such Person.

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“Original Fronting Banks” has the meaning set forth in Section 2.04(r).

“Other Taxes” means any and all present or future stamp, court or documentary, intangible, recording, filing or similar Taxes that arise from any payment made hereunder or under any other Loan Document or from the execution, delivery, performance or enforcement or registration of, from the receipt or perfection of a security interest under, or otherwise with respect to, this Agreement or any other Loan Document.

“Outstanding Credits” means, on any date of determination, an amount equal to (i) the aggregate principal amount of all Advances outstanding on such date plus (ii) the aggregate undrawn amount of all issued Letters of Credit outstanding on such date plus (iii) the aggregate amount of Reimbursement Obligations outstanding on such date (excluding Reimbursement Obligations that, on such date of determination, are repaid with the proceeds of Advances made in accordance with Sections 2.04 (f) and (g), to the extent the principal amount of such Advances is included in the determination of the aggregate principal amount of all outstanding Advances as provided in clause (i) of this definition). The Outstanding Credits of a Lender on any date of determination shall be an amount equal to the outstanding Advances made by such Lender plus the amount of such Lender’s participation interest in outstanding Letters of Credit, Reimbursement Obligations and Swing Line Advances included in the definition of “Outstanding Credits”.

“Parent” means, with respect to any Lender, any Person as to which such Lender is, directly or indirectly, a subsidiary.

“Participant” has the meaning set forth in Section 8.08(d).

“Participant Register” has the meaning set forth in Section 8.08(d).

“Patriot Act” means the USA Patriot Act (Title III of Pub. L. 107-56 (signed into law October 26, 2001), as in effect from time to time.

“Payment Date” means the date on which payment of a Drawing is made by a Fronting Bank.

“PBGC” means the Pension Benefit Guaranty Corporation and any entity succeeding to any or all of its functions under ERISA.

“PE” has the meaning set forth in the preamble hereto.

“PE FERC Order” means the order of the FERC, dated March 22, 2011, that authorizes PE to obtain Extensions of Credit until May 31, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

“Penelec” has the meaning set forth in the preamble hereto.

“Penelec FERC Order” means the order of the FERC, dated March 10, 2010, that authorizes Penelec to obtain Extensions of Credit until May 31, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

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“Penn” has the meaning set forth in the preamble hereto.

“Penn FERC Order” means the order of the FERC, dated March 10, 2010, that authorizes Penn to obtain Extensions of Credit until May 31, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

“Percentage” means, in respect of any Lender on any date of determination, the percentage obtained by dividing such Lender’s Commitment on such day by the total of the Commitments on such day, and multiplying the quotient so obtained by 100%.

“Permitted Obligations” mean (i) nonspeculative Hedging Obligations of any Person and its subsidiaries arising in the ordinary course of business and in accordance with such Person’s established risk management policies that are designed to protect such Person against, among other things, fluctuations in interest rates or currency exchange rates and which in the case of agreements relating to interest rates shall have a notional amount no greater than the payments due with respect to the applicable obligations being hedged and (ii) Commodity Trading Obligations. For the avoidance of doubt, such transactions shall be considered nonspeculative if undertaken in conformance with FE’s Corporate Risk Management Policy then in effect, as approved by FE’s Audit Committee, together with the Approved Business Unit Risk Management Policies referenced thereunder, including, but not limited to, the FES Commodity Portfolio Risk Management Policy.

“Permitted Securitization” means, for any Borrower and its Subsidiaries, any sale, assignment, conveyance, grant and/or contribution, or series of related sales, assignments, conveyances, grants and/or contributions, by such Borrower or any of its Subsidiaries of Receivables (or purported sale, assignment, conveyance, grant and/or contribution) to a trust, corporation or other entity, where the purchase of such Receivables may be funded or exchanged in whole or in part by the incurrence or issuance by the applicable Securitization SPV, if any, of Indebtedness or securities (such Indebtedness and securities being “Attributable Securitization Obligations”) that are to be secured by or otherwise satisfied by payments from, or that represent interests in, the cash flow derived primarily from such Receivables (provided, however, that “Indebtedness” as used in this definition shall not include Indebtedness incurred by a Securitization SPV owed to any Borrower or any of its Subsidiaries, which Indebtedness represents all or a portion of the purchase price or other consideration paid by such Securitization SPV for such receivables or interests therein), where (i) any representation, warranty, covenant, recourse, repurchase, hold harmless, indemnity or similar obligations of such Borrower or any of its Subsidiaries, as applicable, in respect of Receivables sold, assigned, conveyed, granted or contributed, or payments made in respect thereof, are customary for transactions of this type, and do not prevent the characterization of the transaction as a true sale under applicable laws (including debtor relief laws) and (ii) any representation, warranty, covenant, recourse, repurchase, hold harmless, indemnity or similar obligations of any Securitization SPV in respect of Receivables sold, assigned, conveyed, granted or contributed or payments made in respect thereof, are customary for transactions of this type.

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“Person” means an individual, partnership, corporation (including a business trust), limited liability company, joint stock company, trust, unincorporated association, joint venture or other entity, or a government or any political subdivision or agency thereof.

“Plan” means, at any time, an “employee pension benefit plan” (as defined in Section 3(2) of ERISA), other than a Multiemployer Plan, that is covered by Title IV of ERISA or subject to the minimum funding standards under Section 412 or 430 of the Code, (i) that is (A) maintained by or contributed to by (or to which there is or may be an obligation to contribute to by) any Borrower or any member of the Controlled Group for employees of any Borrower or a member of the Controlled Group, or (B) maintained pursuant to a collective bargaining agreement or any other arrangement under which more than one employer makes contributions, and (ii) each such plan as to which any Borrower or a member of the Controlled Group has within the preceding five plan years maintained, contributed to or had an obligation to contribute to.

“Platform” has the meaning set forth in Section 8.03(b).

“Pro-Rata Advance” means an advance by a Lender to any Borrower as part of a Pro-Rata Borrowing pursuant to Section 2.01 and refers to an Alternate Base Rate Pro-Rata Advance or a Eurodollar Rate Advance, subject to Conversion pursuant to Section 2.10 or 2.11.

“Pro-Rata Borrowing” means a borrowing consisting of simultaneous Pro-Rata Advances of the same Type made by each of the Lenders pursuant to Section 2.01 or Converted pursuant to Section 2.10 or 2.11.

“PUCO” means The Public Utilities Commission of Ohio.

“RBS” has the meaning set forth in the preamble hereto.

“Receivables” means any accounts receivable, payment intangibles, notes receivable, rights to receive future payments and related rights (whether now existing or arising or acquired in the future, whether constituting accounts, chattel paper, instruments, general intangibles or otherwise, and including the right to payment of any interest or finance charges), including (i) financial transmission rights (“FTRs”) or any other rights to payment from PJM Interconnection LLC or another regional transmission authority of the Borrower or any of its Subsidiaries or (ii) the right to impose, charge, collect and receive special, irrevocable, nonbypassable charges based upon the consumption of electricity imposed pursuant to Applicable Law on a Borrower’s or any of its Subsidiaries’ ratepayers, and any supporting obligations and other financial assets related thereto (including all collateral securing such accounts receivables, FTRs or other assets, contracts and contract rights, all guarantees with respect thereto, and all proceeds thereof) that are transferred, or in respect of which security interests are granted in one or more transactions that are customary for asset securitizations of such Receivables.

“Recipient” means, as applicable, (i) the Administrative Agent, (ii) any Lender, (iii) any Fronting Bank and (iv) any Swing Line Lender.

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“Reference Banks” means RBS and any Lender as may be selected from time to time to act as a replacement or additional Reference Bank hereunder by the Administrative Agent.

“Reference Ratings” means, with respect to any Borrower, the ratings assigned by S&P and Moody’s to the senior unsecured non-credit enhanced debt of such Borrower; provided that, if there is no such rating, “Reference Ratings” shall mean the ratings that are one level below the ratings assigned by S&P and Moody’s to the senior secured debt of such Borrower.

“Register” has the meaning set forth in Section 8.08(c).

“Reimbursement Obligation” means the obligation of each Borrower to reimburse a Fronting Bank for any Drawing paid by such Fronting Bank pursuant to Section 2.04(g).

“Related Parties” means, with respect to any Person, such Person’s Affiliates and the partners, directors, officers, employees, agents, trustees, administrators, managers, advisors and representatives of such Person and of such Person’s Affiliates.

“Required Reimbursement Date” has the meaning set forth in Section 2.04(f)(i).

“S&P” means Standard & Poor’s Ratings Services, a division of The McGraw-Hill Companies, Inc.

“SEC” means the United States Securities and Exchange Commission.

“Securitization SPV” means any trust, partnership or other Person established by a Borrower or a Subsidiary of such Borrower to implement a Permitted Securitization.

“Significant Subsidiaries” means (i) with respect to FE, each of CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec, PE, West-Penn, FES and AESC, and any successor to any of them, and (ii) with respect to any Borrower, any significant subsidiary (as such term is defined in Regulation S-X of the SEC (17 C.F.R. §210.1-02(w)), or any successor provision) of such Borrower (excluding Securitization SPVs).

“Specified Date” has the meaning set forth in Section 2.19(c).

“Stated Amount” means the maximum amount available to be drawn by a Beneficiary under a Letter of Credit.

“Subsidiary” means, with respect to any Person, any corporation or other entity of which securities or other ownership interests having ordinary voting power to elect a majority of the Board of Directors or other persons performing similar functions are at the time directly or indirectly owned by such a Person, or one or more Subsidiaries, or by such Person and one or more of its Subsidiaries.

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“Swing Line Advance” means an Advance made by a Swing Line Lender to any Borrower as part of a Swing Line Borrowing pursuant to Section 2.03.

“Swing Line Borrowing” means a borrowing consisting of a Swing Line Advance made by a Swing Line Lender pursuant to Section 2.03.

“Swing Line Commitment” means, with respect to any Swing Line Lender, the aggregate amount of Swing Line Advances that such Swing Line Lender agrees to make, as modified from time to time pursuant to an agreement signed by such Swing Line Lender. With respect to each Lender that is a Swing Line Lender on the date hereof, such Swing Line Lender’s Swing Line Commitment shall equal the “Swing Line Commitment” listed for such Swing Line Lender on Schedule III and, with respect to any Lender that becomes a Swing Line Lender after the date hereof, such Lender’s Swing Line Commitment shall equal the amount agreed upon between the Borrowers and such Lenders at the time such Lender becomes a Swing Line Lender.

“Swing Line Lender” means each of the Lenders identified as a “Swing Line Lender” on Schedule III and any other Lender or Affiliate thereof that may be appointed from time to time by the Borrowers to provide Swing Line Advances under this Agreement, that is reasonably acceptable to the Administrative Agent and that accepts such appointment.

“Swing Line Sublimit” means an amount equal to the lesser of (i) $250,000,000 and (ii) the aggregate Commitments. The Swing Line Sublimit is part of, and not in addition to, the aggregate Commitments.

“Taxes” means any and all present or future taxes, levies, imposts, duties, deductions, assessments, fees, charges or withholdings imposed by any Governmental Authority, including any interest, additions to tax or penalties applicable thereto.

“TE” has the meaning set forth in the preamble hereto.

“TE PUCO Order” means the order of the PUCO, dated December 8, 2010, that authorizes TE to obtain Extensions of Credit until December 31, 2011, as amended, extended, supplemented, replaced or renewed from time to time.

“Termination Date” means June 17, 2016, subject, for certain Lenders, to the extension described in Section 2.19 hereof, or, in any case, the earlier date of termination in whole of the Commitments pursuant to Section 2.06 or Section 6.01 hereof.

“Termination Event” means (i) a Reportable Event described in Section 4043 of ERISA and the regulations issued thereunder (other than a Reportable Event not subject to the provision for 30-day notice to the PBGC under such regulations), or (ii) the withdrawal of any member of the Controlled Group from a Plan during a plan year in which it was a “substantial employer” as defined in Section 4001(a)(2) of ERISA, or (iii) the filing of a notice of intent to terminate a Plan or the treatment of a Plan amendment as a termination under Section 4041 or 4042 of ERISA, or (iv) the institution of proceedings to terminate a Plan by the PBGC, or (v) any other event or condition that might constitute grounds under Section 4042 of ERISA for the termination of, or the appointment by a court of competent jurisdiction of a trustee to administer, any Plan.

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“Total Capitalization” means, with respect to any Borrower at any date of determination the sum, without duplication, of (i) Consolidated Debt of such Borrower, (ii) the capital stock (but excluding treasury stock and capital stock subscribed and unissued) and other equity accounts (including retained earnings and paid in capital but excluding accumulated other comprehensive income and loss) of such Borrower and its Consolidated Subsidiaries, (iii) consolidated equity of the preference stockholders of such Borrower and its Consolidated Subsidiaries, and (iv) the aggregate principal amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Debt Obligations of such Borrower and its Consolidated Subsidiaries.

“Trust Preferred Securities” means any securities, however denominated, (i) issued by any Borrower or any Consolidated Subsidiary of any Borrower, (ii) that are not subject to mandatory redemption or the underlying securities, if any, of which are not subject to mandatory redemption, (iii) that are perpetual or mature no less than 30 years from the date of issuance, (iv) the indebtedness issued in connection with which, including any guaranty, is subordinate in right of payment to the unsecured and unsubordinated indebtedness of the issuer of such indebtedness or guaranty, and (v) the terms of which permit the deferral of the payment of interest or distributions thereon to a date occurring after the Termination Date.

“Type” means the designation of a Borrowing or an Advance as a Eurodollar Rate Borrowing or Advance or as an Alternate Base Rate Borrowing or Advance.

“Union Bank Facility” means the $250,000,000 Credit Agreement, dated as of April 30, 2010, among Allegheny Energy, Inc., the banks, financial institutions and other institutional lenders party thereto, the letter of credit issuing banks party thereto and Union Bank, N.A., as administrative agent.

“Unmatured Default” means any event that, with the giving of notice or the passage of time, or both, would constitute an Event of Default.

“U.S. Person” means any Person that is a “United States person” as defined in Section 7701(a)(30) of the Code.

“U.S. Tax Compliance Certificate” has the meaning set forth in Section 2.16(e)(ii)(C).

“West-Penn” has the meaning set forth in the preamble hereto.

“West-Penn FERC Order” means the order of the FERC, dated March 22, 2011, that authorizes PE to obtain Extensions of Credit until May 31, 2012, as amended, extended, supplemented, replaced or renewed from time to time.

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SECTION 1.02. Computation of Time Periods.

In this Agreement in the computation of periods of time from a specified date to a later specified date, the word “from” means “from and including” and the words “to” and “until” each means “to but excluding”.

SECTION 1.03. Accounting Terms.

All accounting terms not specifically defined herein shall be construed in accordance with GAAP consistent with those applied in the preparation of the financial statements referred to in Section 4.01(g).

SECTION 1.04. Terms Generally.

Whenever the context may require, any pronoun shall include the corresponding masculine, feminine and neuter forms. The words “include”, “includes” and “including” shall be deemed to be followed by the phrase “without limitation”. The word “will” shall be construed to have the same meaning and effect as the word “shall”. Unless the context requires otherwise, (i) any definition of or reference to any agreement, instrument or other document herein shall be construed as referring to such agreement, instrument or other document as from time to time amended, amended and restated, supplemented or otherwise modified (subject to any restrictions on such amendments, restatements, supplements or modifications set forth herein), (ii) any reference herein to any Person shall be construed to include such Person’s successors and assigns, (iii) the words “herein”, “hereof” and “hereunder”, and words of similar import, shall be construed to refer to this Agreement in its entirety and not to any particular provisions hereof, (iv) all references herein to Articles, Sections, Exhibits and Schedules shall be construed to refer to Articles and Sections of, and Exhibits and Schedules to, this Agreement, and (v) the definitions of terms herein shall apply equally to the singular and plural forms of the terms defined.

ARTICLE II
AMOUNTS AND TERMS OF THE ADVANCES AND LETTERS OF CREDIT

SECTION 2.01. The Pro-Rata Advances.

Each Lender severally agrees, on the terms and conditions hereinafter set forth, to make Pro-Rata Advances to each Borrower in Dollars only from time to time on any Business Day during the period from the date hereof until the Termination Date in an aggregate amount not to exceed at any time outstanding the Available Commitment of such Lender. Each Pro-Rata Borrowing shall be in an aggregate amount not less than $5,000,000 or an integral multiple of $1,000,000 in excess thereof and shall consist of Advances of the same Type and, in the case of Eurodollar Rate Advances, having the same Interest Period made or Converted on the same day by the Lenders ratably according to their respective Commitments. Within the limits of each Lender’s Available Commitment, and subject to the conditions set forth in Article III and the other terms and conditions hereof, each Borrower may from time to time borrow, prepay pursuant to Section 2.12 and reborrow under this Section 2.01; provided, that in no case shall any Lender be required to make a Pro-Rata Advance to a Borrower hereunder if (i) the amount of such Pro-Rata Advance would exceed such Lender’s Available Commitment, (ii) the making of such Pro-Rata Advance, together with the making of the other Pro-Rata Advances constituting part of the same Pro-Rata Borrowing, would cause the total amount of all Outstanding Credits to exceed the aggregate amount of the Commitments or (iii) the amount of such Pro-Rata Advance, together with all other Outstanding Credits for the account of such Borrower, would exceed such Borrower’s Borrower Sublimit.

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SECTION 2.02. Making the Pro-Rata Advances.

(a) Each Pro-Rata Borrowing shall be made on notice, given (i) in the case of a Pro-Rata Borrowing comprising Eurodollar Rate Advances, not later than 11:00 a.m. (New York time) on the third Business Day prior to the date of the proposed Borrowing, and (ii) in the case of a Pro-Rata Borrowing comprising Alternate Base Rate Pro-Rata Advances, not later than 11:00 a.m. (New York time) on the date of the proposed Pro-Rata Borrowing, by any Borrower to the Administrative Agent, which shall give to each Lender prompt notice thereof. Each such Notice of Pro-Rata Borrowing by a Borrower shall be by telecopier, in substantially the form of Exhibit C hereto, specifying therein the requested (A) date of such Pro-Rata Borrowing, (B) Type of Pro-Rata Advances to be made in connection with such Pro-Rata Borrowing, (C) aggregate amount of such Pro-Rata Borrowing, (D) in the case of a Pro-Rata Borrowing comprising Eurodollar Rate Advances, the initial Interest Period for each such Pro-Rata Advance, which Pro-Rata Borrowing shall be subject to the limitations stated in the definition of “Interest Period” in Section 1.01, and (E) the identity of the Borrower requesting such Pro-Rata Borrowing. Each Borrower may request that more than one Borrowing be made on any date. Each Lender shall, before 1:00 p.m. (New York time) on the date of such Pro-Rata Borrowing, make available for the account of its Applicable Lending Office to the Administrative Agent at its address referred to in Section 8.02, in same day funds, such Lender’s Percentage of such Pro-Rata Borrowing. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Administrative Agent will make such funds available to such Borrower at the Administrative Agent’s aforesaid address.

(b) Each Notice of Pro-Rata Borrowing delivered by any Borrower shall be irrevocable and binding on such Borrower. In the case of any Notice of Pro-Rata Borrowing delivered by any Borrower requesting Eurodollar Rate Advances, such Borrower shall indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure by such Borrower to fulfill on or before the date specified in such Notice of Pro-Rata Borrowing the applicable conditions set forth in Article III, including, without limitation, any loss (including loss of anticipated profits), cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by such Lender to fund the Pro-Rata Advance to be made by such Lender as part of such Borrowing when such Pro-Rata Advance, as a result of such failure, is not made on such date.

(c) Unless the Administrative Agent shall have received written notice via facsimile transmission from a Lender prior to (A) 5:00 p.m. (New York time) one Business Day prior to the date of a Pro-Rata Borrowing comprising Eurodollar Rate Advances or (B) 12:00 noon (New York time) on the date of a Pro-Rata Borrowing comprising Alternate Base Rate Pro-Rata Advances that such Lender will not make available to the Administrative Agent such Lender’s Percentage of such Pro-Rata Borrowing, the Administrative Agent may assume that such Lender has made such portion available to the Administrative Agent on the date of such Pro-Rata Borrowing in accordance with subsection (a) of this Section 2.02 and the Administrative Agent may, in reliance upon such assumption, make available to the applicable Borrower on such date a corresponding amount. If and to the extent that such Lender shall not have so made such Percentage of such Pro-Rata Borrowing available to the Administrative Agent, such Lender and such Borrower severally agree to repay to the Administrative Agent forthwith on demand such corresponding amount together with interest thereon, for each day from the date such amount is made available to such Borrower until the date such amount is repaid to the Administrative Agent, at (i) in the case of such Borrower, the interest rate applicable at the time to Pro-Rata Advances made in connection with such Pro-Rata Borrowing and (ii) in the case of such Lender, the Federal Funds Rate. If such Lender shall repay to the Administrative Agent such corresponding amount, such amount so repaid shall constitute such Lender’s Pro-Rata Advance as part of such Pro-Rata Borrowing for purposes of this Agreement.

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(d) The failure of any Lender to make the Pro-Rata Advance to be made by it as part of any Pro-Rata Borrowing shall not relieve any other Lender of its obligation, if any, hereunder to make its Pro-Rata Advance on the date of such Pro-Rata Borrowing, but no Lender shall be responsible for the failure of any other Lender to make the Pro-Rata Advance to be made by such other Lender on the date of any Borrowing.

SECTION 2.03. Swing Line Advances.

(a) The Swing Line. Subject to the terms and conditions set forth herein, each Swing Line Lender agrees to make Swing Line Advances to any Borrower in Dollars only from time to time on any Business Day during the period from the date hereof until the Termination Date in an aggregate amount not to exceed at any time the amount of such Swing Line Lender’s Swing Line Commitment; provided, however, no Swing Line Lender shall be required to make a Swing Line Advance hereunder if (i) the amount of such Swing Line Advance, together with the aggregate principal amount of all other Swing Line Advances outstanding would exceed the Swing Line Sublimit, (ii) the making of such Swing Line Advance, together with the making of the other Swing Line Advances constituting part of the same Swing Line Borrowing, would cause the total amount of all Outstanding Credits to exceed the aggregate amount of the Commitments or (iii) the amount of such Swing Line Advance would exceed such Borrower’s Borrower Sublimit. Within the foregoing limits, and subject to the other terms and conditions hereof, each Borrower may borrow under this Section 2.03, prepay under Section 2.12, and reborrow under this Section 2.03. Immediately upon the making of a Swing Line Advance, each Lender shall be deemed to, and hereby irrevocably and unconditionally agrees to, purchase from the applicable Swing Line Lender a risk participation in such Swing Line Advance in an amount equal to such Lender’s Percentage of the amount of such Swing Line Advance. No more than five Swing Line Advances may be outstanding hereunder at any time.

(b) Borrowing Procedures. Each Swing Line Borrowing shall be made upon any Borrower’s irrevocable notice to the applicable Swing Line Lender and the Administrative Agent, which may be given by telephone. Each such notice must be received by the applicable Swing Line Lender and the Administrative Agent not later than 11:00 a.m. (New York time) on the date of the proposed Swing Line Borrowing, or at such later time as a Swing Line Lender may agree, and shall specify (i) the date of such Swing Line Borrowing, (ii) the amount of such Swing Line Borrowing, which shall be not less than $1,000,000 or an integral multiple of $1,000,000 in excess thereof, and (iii) the identity of the Borrower requesting such Swing Line Borrowing. Each such telephonic notice must be confirmed promptly by delivery to the relevant Swing Line Lender and the Administrative Agent of a written Notice of Swing Line Borrowing, appropriately completed and signed by such Borrower. Promptly after receipt by such Swing Line Lender of any telephonic Notice of Swing Line Borrowing, such Swing Line Lender will confirm with the Administrative Agent (by telephone or in writing) that the Administrative Agent has also received such Notice of Swing Line Borrowing and, if not, such Swing Line Lender will notify the Administrative Agent (by telephone or in writing) of the contents thereof. Unless such Swing Line Lender has received notice (by telephone or in writing) from the Administrative Agent (including at the request of any Lender) prior to 12:00 p.m. (New York time) on the date of the proposed Swing Line Borrowing (A) directing such Swing Line Lender not to make such Swing Line Advance as a result of the limitations set forth in the first sentence of Section 2.03(a) or (B) that one or more of the applicable conditions specified in Article III is not then satisfied, then, subject to the terms and conditions hereof, such Swing Line Lender will, not later than 1:00 p.m. on the borrowing date specified in such Notice of Swing Line Borrowing, make the amount of its Swing Line Advance available to the applicable Borrower at its office by crediting the account of such Borrower on the books of such Swing Line Lender in immediately available funds.

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(c) Refinancing of Swing Line Advances.

(i) Each Swing Line Lender at any time in its sole and absolute discretion may request, on behalf of any Borrower (each of which hereby irrevocably authorizes each Swing Line Lender to so request on its behalf), that each Lender make an Alternate Base Rate Pro-Rata Advance in an amount equal to such Lender’s Percentage of the amount of Swing Line Advances made by such Swing Line Lender then outstanding to such Borrower. Such request shall be made in writing (which written request shall be deemed to be a Notice of Pro-Rata Borrowing for purposes hereof) and in accordance with the requirements of Sections 2.01 and 2.02, without regard to the minimum and multiples specified therein for the principal amount of Alternate Base Rate Pro-Rata Advances, but subject to the unutilized portion of the Commitments and the conditions set forth in Section 3.02. Such Swing Line Lender shall furnish such Borrower with a copy of the applicable Notice of Pro-Rata Borrowing promptly after delivering such notice to the Administrative Agent. Each Lender shall, before 1:00 p.m. (New York time) on the date of such Borrowing, make available for the account of its Applicable Lending Office to the Administrative Agent at its address referred to in Section 8.02, in same day funds, such Lender’s Percentage of such Pro-Rata Borrowing. After the Administrative Agent’s receipt of such funds and upon fulfillment of the applicable conditions set forth in Article III, the Administrative Agent will make such funds available to such Borrower at the Administrative Agent’s aforesaid address, whereupon, subject to Section 2.03(c)(ii), each Lender that so makes funds available shall be deemed to have made an Alternate Base Rate Pro-Rata Advance to such Borrower in such amount. The Administrative Agent shall remit the funds so received to the applicable Swing Line Lender.

(ii) If for any reason any Swing Line Advance cannot be refinanced by a Pro-Rata Borrowing in accordance with Section 2.03(c)(i), the request for Alternate Base Rate Pro-Rata Advances submitted by a Swing Line Lender as set forth herein shall be deemed to be a request by such Swing Line Lender that each Lender fund its risk participation in the relevant Swing Line Advances, and each Lender’s payment to the Administrative Agent for the account of such Swing Line Lender pursuant to Section 2.03(c)(i) shall be deemed payment in respect of such participation.

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(iii) If any Lender fails to make available to the Administrative Agent for the account of any Swing Line Lender any amount required to be paid by such Lender pursuant to the foregoing provisions of this Section 2.03(c) by the time specified in Section 2.03(c)(i), such Swing Line Lender shall be entitled to recover from such Lender (acting through the Administrative Agent), on demand, such amount with interest thereon for the period from the date such payment is required to the date on which such payment is immediately available to such Swing Line Lender at a rate per annum equal to the greater of the Federal Funds Rate and a rate determined by such Swing Line Lender in accordance with banking industry rules on interbank compensation. A certificate of such Swing Line Lender submitted to any Lender (through the Administrative Agent) with respect to any amounts owing under this clause (iii) shall be conclusive absent manifest error.

(iv) Each Lender’s obligation to make Pro-Rata Advances or to purchase and fund risk participations in Swing Line Advances pursuant to this Section 2.03(c) shall be absolute and unconditional and shall not be affected by any circumstance, including (A) any setoff, counterclaim, recoupment, defense or other right that such Lender may have against any Swing Line Lender, any Borrower or any other Person for any reason whatsoever, (B) the occurrence or continuance of an Unmatured Default or Event of Default, or (C) any other occurrence, event or condition, whether or not similar to any of the foregoing; provided, however, that each Lender’s obligation to make Pro-Rata Advances pursuant to this Section 2.03(c) is subject to the conditions set forth in Section 3.02. No such funding of risk participations shall relieve or otherwise impair the obligation of any Borrower to repay Swing Line Advances, together with interest as provided herein.

(d) Repayment of Participations.

(i) At any time after any Lender has purchased and funded a risk participation in a Swing Line Advance, if the applicable Swing Line Lender receives any payment on account of such Swing Line Advance, such Swing Line Lender will distribute to such Lender its Percentage of such payment (appropriately adjusted, in the case of interest payments, to reflect the period of time during which such Lender’s risk participation was funded) in the same funds as those received by such Swing Line Lender.

(ii) If any payment received by any Swing Line Lender in respect of principal or interest on any Swing Line Advance is required to be returned by such Swing Line Lender under any of the circumstances described in Section 2.15(g) (including pursuant to any settlement entered into by the Swing Line Lender in its discretion), each Lender shall pay to such Swing Line Lender its Percentage thereof on demand of the Administrative Agent, plus interest thereon from the date of such demand to the date such amount is returned, at a rate per annum equal to the Federal Funds Rate. The Administrative Agent will make such demand upon the request of such Swing Line Lender. The obligations of the Lenders under this clause shall survive the payment in full of the obligations hereunder and the termination of this Agreement.

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(e) Interest for Account of Swing Line Lenders. Each Swing Line Lender shall be responsible for invoicing the applicable Borrower for interest on the Swing Line Advances made to such Borrower. Until each Lender funds its Alternate Base Rate Pro-Rata Advance or risk participation pursuant to this Section 2.03 to refinance such Lender’s Percentage of any Swing Line Advance, interest in respect of such Percentage interest shall be solely for the account of such Swing Line Lender.

(f) Payments Directly to Swing Line Lenders. Each Borrower with outstanding Swing Line Advances shall make all payments of principal and interest in respect of such Swing Line Advances directly to the Swing Line Lender that made such Advances.

SECTION 2.04. Letters of Credit.

(a) Agreement of Fronting Banks. Subject to the terms and conditions of this Agreement, each Fronting Bank agrees to issue and amend (including, without limitation, to extend or renew) for the account of any Borrower or any Subsidiary thereof (each such Person, an “Account Party”) one or more standby letters of credit (individually, a “Letter of Credit” and collectively, the “Letters of Credit”) from and including the date hereof to the third Business Day preceding the Termination Date, in an aggregate Stated Amount at any time outstanding not to exceed such Fronting Bank’s LC Fronting Bank Commitment, up to a maximum aggregate Stated Amount of all Letters of Credit at any one time outstanding equal to the L/C Commitment Amount minus Reimbursement Obligations outstanding at such time. Each Letter of Credit may be renewable (if so requested by the applicable Borrower), shall have a Stated Amount not less than $100,000 and shall have an Expiration Date of no later than the earlier of (x) the third Business Day preceding the latest Termination Date and (y) the date occurring one year after the Date of Issuance of such Letter of Credit; provided, however, that no Fronting Bank will issue or amend a Letter of Credit if, immediately following such issuance or amendment, (i) the Stated Amount of such Letter of Credit would (A) exceed the Available Commitments or (B) when aggregated with (1) the Stated Amounts of all other outstanding Letters of Credit and (2) the outstanding Reimbursement Obligations, exceed the L/C Commitment Amount or (ii) the total amount of all Outstanding Credits would exceed the aggregate amount of the Commitments. Letters of Credit shall be denominated in Dollars only. Notwithstanding that any Letter of Credit issued or outstanding hereunder may be in support of any obligations of, or for the account of, a Subsidiary of a Borrower, any Borrower that requests the issuance of any such Letter of Credit in support of any obligations of, or for the account of, any of its Subsidiaries shall be obligated to reimburse the applicable Fronting Bank for any and all drawings under such Letter of Credit. Each Borrower that requests the issuance of any such Letter of Credit hereby acknowledges that the issuance of Letters of Credit for the account of its Subsidiaries inures to such Borrower’s benefit and that such Borrower’s business derives substantial benefits from the businesses of such Subsidiary. No Fronting Bank shall be under any obligation to issue any Letter of Credit if (A) any order, judgment or decree of any Governmental Authority or arbitrator shall by its terms purport to enjoin or restrain such Fronting Bank from issuing such Letter of Credit, (B) any law applicable to such Fronting Bank or any request or directive (whether or not having the force of law) from any Governmental Authority with jurisdiction over such Fronting Bank shall prohibit, or request that such Fronting Bank refrain from, the issuance of letters of credit generally or such Letter of Credit in particular or shall impose upon such Fronting Bank with respect to such Letter of Credit any restriction, reserve or capital requirement (for which such Fronting Bank is not otherwise compensated hereunder) not in effect on the date hereof, or shall impose upon such Fronting Bank any unreimbursed loss, cost or expense that was not applicable on the date hereof and that such Fronting Bank in good faith deems material to it, (C) the issuance of such Letter of Credit would violate one or more policies of such Fronting Bank or (D) such Fronting Bank is not required to make any Extension of Credit in connection with a Letter of Credit under Section 2.21(d).

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(b) Forms. Each Letter of Credit shall be in a form customarily used by the Fronting Bank that is to issue such Letter of Credit or in such other form as has been approved by such Fronting Bank. At the time of issuance or amendment, subject to the terms and conditions of this Agreement, the amount and the terms and conditions of each Letter of Credit shall be subject to approval by the applicable Fronting Bank and the applicable Borrower.

(c) Notice of Issuance; Application. The applicable Borrower shall give the applicable Fronting Bank and the Administrative Agent written notice, or telephonic notice confirmed in writing, in any case, at least two Business Days (or such shorter period as such Fronting Bank may agree in its sole discretion) prior to the requested Date of Issuance of a Letter of Credit, such notice to be in substantially the form of Exhibit E hereto (a “Letter of Credit Request”). Such Borrower shall also execute and deliver such customary letter of credit application forms as requested from time to time by such Fronting Bank. Such application forms shall indicate the identity of the Account Party and that such Borrower is the “Applicant” or shall otherwise indicate that such Borrower is the obligor in respect of any Letter of Credit to be issued thereunder. If the terms or conditions of the application forms conflict with any provision of this Agreement, the terms of this Agreement shall govern.

(d) Issuance. Provided that the applicable Borrower has given the notice prescribed by Section 2.04(c) and subject to the other terms and conditions of this Agreement, including the satisfaction of the applicable conditions precedent set forth in Article III, the applicable Fronting Bank shall issue the requested Letter of Credit on the requested Date of Issuance as set forth in the applicable Letter of Credit Request for the benefit of the stipulated Beneficiary and shall deliver the original of such Letter of Credit to the Beneficiary at the address specified in the notice. At the request of the applicable Borrower, such Fronting Bank shall deliver a copy of each Letter of Credit to such Borrower within a reasonable time after the Date of Issuance thereof. Upon the request of such Borrower, such Fronting Bank shall deliver to such Borrower a copy of any Letter of Credit proposed to be issued hereunder prior to the issuance thereof.

(e) Notice of Drawing. Each Fronting Bank shall promptly notify the applicable Borrower by telephone, facsimile or other telecommunication of any Drawing under a Letter of Credit issued for the account of such Borrower by such Fronting Bank.

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(f) Payments. Each Borrower hereby agrees to pay to each Fronting Bank, in the manner provided in subsection (g) below:

(i) on the date of receipt by such Borrower of notice of any Drawing pursuant to a subsection (e) above, if such notice is received not later than 11:00 a.m. (New York City time), or on the first Business Day following receipt of such notice by such Borrower, if such notice is received later than 11:00 a.m. (New York City time), an amount equal to the amount paid by such Fronting Bank in connection with such Drawing (such date being the “Required Reimbursement Date”); and

(ii) if any Drawing shall be reimbursed to any Fronting Bank after 12:00 noon (New York time) on the applicable Payment Date, interest on any and all amounts required to be paid pursuant to clause (i) of this subsection (f) from and after such Payment Date until payment in full, payable on demand, at the annual rate of interest applicable to Alternate Base Rate Advances as in effect from time to time, provided, however, that from and after the Required Reimbursement Date with respect to such Drawing until payment in full, such interest rate shall be increased by 2.00%.

(g) Method of Reimbursement. Each Borrower shall reimburse each Fronting Bank for each Drawing under any Letter of Credit issued for the account of such Borrower by such Fronting Bank pursuant to subsection (f) above in the following manner:

(i) such Borrower shall reimburse such Fronting Bank in the manner described in subsection (f) above and Section 2.15; or

(ii) if (A) such Borrower has not reimbursed such Fronting Bank pursuant to paragraph (i) above, (B) the applicable conditions to Borrowing set forth in Articles II and III have been fulfilled, and (C) the Available Commitments in effect at such time exceed the amount of the Drawing to be reimbursed, such Borrower may reimburse such Fronting Bank for such Drawing with the proceeds of an Alternate Base Rate Pro-Rata Advance or, if the conditions specified in the foregoing clauses (A), (B) and (C) have been satisfied and a Notice of Borrowing requesting a Eurodollar Rate Advance has been given in accordance with Section 2.02 three Business Days prior to the relevant Payment Date, with the proceeds of a Eurodollar Rate Advance.

(h) Nature of Fronting Banks’ Duties. In determining whether to honor any Drawing under any Letter of Credit issued by any Fronting Bank, such Fronting Bank shall be responsible only to determine that the documents and certificates required to be delivered under such Letter of Credit have been delivered and that they comply on their face with the requirements of such Letter of Credit. Each Borrower otherwise assumes all risks of the acts and omissions of, or misuse of any Letter of Credit issued by any Fronting Bank for the account of such Borrower by, the Beneficiary of such Letter of Credit. In furtherance and not in limitation of the foregoing, but consistent with applicable law, no Fronting Bank shall be responsible, absent gross negligence or willful misconduct, (i) for the form, validity, sufficiency, accuracy, genuineness or legal effects of any document submitted by any party in connection with the application for and issuance of any drawing honored under a Letter of Credit, even if it should in fact prove to be in any or all respects invalid, insufficient, inaccurate, fraudulent or forged; (ii) for the validity or sufficiency of any instrument transferring or assigning or purporting to transfer or assign any such Letter of Credit, or the rights or benefits thereunder or proceeds thereof, in whole or in part, which may prove to be invalid or ineffective for any reason; (iii) for errors, omissions, interruptions or delays in transmission or delivery of any messages, by mail, cable, telegraph, telex, facsimile or otherwise, whether or not they be in cipher; (iv) for errors in interpretation of technical terms; (v) for any loss or delay in the transmission or otherwise of any document required in order to make a drawing under any such Letter of Credit, or the proceeds thereof; (vi) for the misapplication by the Beneficiary of any such Letter of Credit or of the proceeds of any drawing honored under such Letter of Credit; and (vii) for any consequences arising from causes beyond the control of such Fronting Bank. None of the above shall affect, impair or prevent the vesting of any of such Fronting Bank’s rights or powers hereunder. Not in limitation of the foregoing, any action taken or omitted to be taken by any Fronting Bank under or in connection with any Letter of Credit shall not create against such Fronting Bank any liability to the Borrowers or any Lender, except for actions or omissions resulting from the gross negligence or willful misconduct of such Fronting Bank or any of its agents or representatives, and such Fronting Bank shall not be required to take any action that exposes such Fronting Bank to personal liability or that is contrary to this Agreement or applicable law.

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(i) Obligations of Borrowers Absolute. The obligation of each Borrower to reimburse each Fronting Bank for Drawings honored under the Letters of Credit issued for the account of such Borrower by such Fronting Bank shall be unconditional and irrevocable and shall be paid strictly in accordance with the terms of this Agreement under all circumstances including, without limitation, the following circumstances:

(i) any lack of validity or enforceability of any Letter of Credit;

(ii) the existence of any claim, set-off, defense or other right that any Borrower, any Account Party or any Affiliate of any Borrower or any Account Party may have at any time against a Beneficiary or any transferee of any Letter of Credit (or any Persons or entities for whom any such Beneficiary or transferee may be acting), such Fronting Bank or any other Person, whether in connection with this Agreement, the transactions contemplated herein or any unrelated transaction;

(iii) any draft, demand, certificate or any other documents presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect;

(iv) the surrender or impairment of any security for the performance or observance of any of the terms of any of the Loan Documents;

(v) any non-application or misapplication by the Beneficiary of the proceeds of any Drawing under a Letter of Credit; or

(vi) the fact that an Event of Default or an Unmatured Default shall have occurred and be continuing.

No payment made under this Section shall be deemed to be a waiver of any claim any Borrower may have against any Fronting Bank or any other Person.

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(j) Participations by Lenders. By the issuance of a Letter of Credit and without any further action on the part of any Fronting Bank or any Lender in respect thereof, each Fronting Bank shall hereby be deemed to have granted to each Lender, and each Lender shall hereby be deemed to have acquired from such Fronting Bank, an undivided interest and participation in such Letter of Credit (including any letter of credit issued by such Fronting Bank in substitution or exchange for such Letter of Credit pursuant to the terms thereof) equal to such Lender’s Percentage of the Stated Amount of such Letter of Credit, effective upon the issuance of such Letter of Credit. In consideration and in furtherance of the foregoing, each Lender hereby absolutely and unconditionally agrees to pay to such Fronting Bank, in accordance with this subsection (j), such Lender’s Percentage of each payment made by such Fronting Bank in respect of an unreimbursed Drawing under a Letter of Credit. Such Fronting Bank shall notify the Administrative Agent of the amount of such unreimbursed Drawing honored by it not later than (x) 12:00 noon (New York time) on the date of payment of a draft under a Letter of Credit, if such payment is made at or prior to 11:00 a.m. (New York time) on such day, and (y) the close of business (New York time) on the date of payment of a draft under a Letter of Credit, if such payment is made after 11:00 a.m. (New York time) on such day, and the Administrative Agent shall notify each Lender of the date and amount of such unreimbursed Drawing under such Letter of Credit honored by such Fronting Bank and the amount of such Lender’s Percentage therein no later than (1) 1:00 p.m. (New York time) on such day, if such payment is made at or prior to 11:00 a.m. (New York time) on such day, and (2) 11:00 a.m. (New York time) on the next following Business Day, if such payment is made after 11:00 a.m. (New York time) on such day. Not later than 2:00 p.m. (New York time) on the date of receipt of a notice of an unreimbursed Drawing by a Lender, such Lender agrees to pay to such Fronting Bank an amount equal to the product of (A) such Lender’s Percentage and (B) the amount of the payment made by such Fronting Bank in respect of such unreimbursed Drawing.

If payment of the amount due pursuant to the preceding sentence from a Lender is received by such Fronting Bank after the close of business on the date it is due, such Lender agrees to pay to such Fronting Bank, in addition to (and along with) its payment of the amount due pursuant to the preceding sentence, interest on such amount at a rate per annum equal to (i) for the period from and including the date such payment is due to but excluding the second succeeding Business Day, the Federal Funds Rate, and (ii) for the period from and including the second Business Day succeeding the date such payment is due to but excluding the date on which such amount is paid in full, the Federal Funds Rate plus 2.00%.

(k) Obligations of Lenders Absolute. Each Lender acknowledges and agrees that (i) its obligation to acquire a participation in any Fronting Bank’s liability in respect of the Letters of Credit and (ii) its obligation to make the payments specified herein, and the right of each Fronting Bank to receive the same, in the manner specified herein, are absolute and unconditional and shall not be affected by any circumstances whatsoever, including, without limitation, (A) the occurrence and continuance of any Event of Default or Unmatured Default; (B) any other breach or default by any Borrower, the Administrative Agent or any Lender hereunder; (C) any lack of validity or enforceability of any Letter of Credit or any Loan Document; (D) the existence of any claim, setoff, defense or other right that the Lender may have at any time against any Borrower, any other Account Party, any Beneficiary, any Fronting Bank or any other Lender; (E) the existence of any claim, setoff, defense or other right that any Borrower may have at any time against any Beneficiary, any Fronting Bank, the Administrative Agent, any Lender or any other Person, whether in connection with this Agreement or any other documents contemplated hereby or any unrelated transactions; (F) any amendment or waiver of, or consent to any departure from, all or any of the Letters of Credit or this Agreement; (G) any statement or any document presented under any Letter of Credit proving to be forged, fraudulent, invalid or insufficient in any respect or any statement therein being untrue or inaccurate in any respect; (H) payment by any Fronting Bank under any Letter of Credit against presentation of a draft or certificate that does not comply with the terms of such Letter of Credit, so long as such payment is not the consequence of such Fronting Bank’s gross negligence or willful misconduct in determining whether documents presented under a Letter of Credit comply with the terms thereof; (I) the occurrence of the Termination Date; or (J) any other circumstance or happening whatsoever, whether or not similar to any of the foregoing. Nothing herein shall prevent the assertion by any Lender of a claim by separate suit or compulsory counterclaim, nor shall any payment made by a Lender under Section 2.04 hereof be deemed to be a waiver of any claim that a Lender may have against any Fronting Bank or any other Person.

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(l) Proceeds of Reimbursements. Upon receipt of a payment from a Borrower pursuant to subsection (f) hereof, the applicable Fronting Bank shall promptly transfer to each Lender that has funded its participation in the applicable Drawing pursuant to subsection (j) above, such Lender’s pro rata share (determined in accordance with such Lender’s Percentage) of such payment. All payments due to the Lenders from any Fronting Bank pursuant to this subsection (l) shall be made to the Lenders if, as, and, to the extent possible, when such Fronting Bank receives payments in respect of Drawings under the Letters of Credit pursuant to subsection (f) hereof, and in the same funds in which such amounts are received; provided that if any Lender to which such Fronting Bank is required to transfer any such payment (or any portion thereof) pursuant to this subsection (l) does not receive such payment (or portion thereof) prior to (i) the close of business on the Business Day on which such Fronting Bank received such payment from such Borrower, if such Fronting Bank received such payment prior to 1:00 p.m. (New York time) on such day, or (ii) 1:00 p.m. (New York time) on the Business Day next succeeding the Business Day on which such Fronting Bank received such payment from the Borrower, if such Fronting Bank received such payment after 1:00 p.m. (New York time) on such day, such Fronting Bank agrees to pay to such Lender, along with its payment of the portion of such payment due to such Lender, interest on such amount at a rate per annum equal to (A) for the period from and including the Business Day when such payment was required to be made to the Lenders to but excluding the second succeeding Business Day, the Federal Funds Rate and (B) for the period from and including the second Business Day succeeding the Business Day when such payment was required to be made to the Lenders to but excluding the date on which such amount is paid in full, the Federal Funds Rate plus 2.00%.

(m) Concerning the Fronting Banks. Each Fronting Bank will exercise and give the same care and attention to the Letters of Credit issued by it as it gives to its other letters of credit and similar obligations, and each Lender agrees that each Fronting Bank’s sole liability to such Lender shall be (i) to distribute promptly, as and when received by such Fronting Bank, and in accordance with the provisions of subsection (l) above, such Lender’s Percentage of any payments to such Fronting Bank by the Borrowers pursuant to subsection (f) above in respect of Drawings under the Letters of Credit issued by such Fronting Bank, (ii) to exercise or refrain from exercising any right or to take or to refrain from taking any action under this Agreement or any Letter of Credit issued by such Fronting Bank as may be directed in writing by the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders) or the Administrative Agent acting at the direction and on behalf of the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders), except to the extent required by the terms hereof or thereof or by applicable law, and (iii) as otherwise expressly set forth in this Section 2.04. No Fronting Bank shall be liable for any action taken or omitted at the request or with approval of the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders) or of the Administrative Agent acting on behalf of the Majority Lenders (or, when expressly required by the terms of this Agreement, all of the Lenders) or for the nonperformance of the obligations of any other party under this Agreement, any Letter of Credit or any other document contemplated hereby or thereby. Without in any way limiting any of the foregoing, each Fronting Bank may rely upon the advice of counsel concerning legal matters and upon any written communication or any telephone conversation that it believes to be genuine or to have been signed, sent or made by the proper Person and shall not be required to make any inquiry concerning the performance by any Borrower, any Beneficiary or any other Person of any of their respective obligations and liabilities under or in respect of this Agreement, any Letter of Credit or any other documents contemplated hereby or thereby. No Fronting Bank shall have any obligation to make any claim, or assert any Lien, upon any property held by such Fronting Bank or assert any offset thereagainst in satisfaction of all or any part of the obligations of the Borrowers hereunder; provided that each Fronting Bank shall, if so directed by the Majority Lenders or the Administrative Agent acting on behalf of and with the consent of the Majority Lenders, have an obligation to make a claim, or assert a Lien, upon property held by such Fronting Bank in connection with this Agreement, or assert an offset thereagainst.

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Each Fronting Bank may accept deposits from, make loans or otherwise extend credit to, and generally engage in any kind of banking or trust business with the Borrowers or any of their Affiliates, or any other Person, and receive payment on such loans or extensions of credit and otherwise act with respect thereto freely and without accountability in the same manner as if it were not a Fronting Bank hereunder.

Each Fronting Bank makes no representation or warranty and shall have no responsibility with respect to: (i) the genuineness, legality, validity, binding effect or enforceability of this Agreement or any other documents contemplated hereby; (ii) the truthfulness, accuracy or performance of any of the representations, warranties or agreements contained in this Agreement or any other documents contemplated hereby; (iii) the collectibility of any amounts due under this Agreement; (iv) the financial condition of the Borrowers or any other Person; or (v) any act or omission of any Beneficiary with respect to its use of any Letter of Credit or the proceeds of any Drawing under any Letter of Credit.

(n) Indemnification of Fronting Banks by Lenders. To the extent that any Fronting Bank is not reimbursed and indemnified by the Borrowers under Section 8.05 hereof, each Lender agrees to reimburse and indemnify such Fronting Bank on demand, pro rata in accordance with such Lender’s Percentage, for and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by or asserted against such Fronting Bank, in any way relating to or arising out of this Agreement, any Letter of Credit or any other document contemplated hereby or thereby, or any action taken or omitted by such Fronting Bank under or in connection with this Agreement, any Letter of Credit or any other document contemplated hereby or thereby; provided, however, that such Lender shall not be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from such Fronting Bank’s gross negligence or willful misconduct; and provided further, however, that such Lender shall not be liable to such Fronting Bank or any other Lender for the failure of any Borrower to reimburse such Fronting Bank for any drawing made under a Letter of Credit issued for the account of such Borrower with respect to which such Lender has paid such Fronting Bank such Lender’s pro rata share (determined in accordance with such Lender’s Percentage), or for such Borrower’s failure to pay interest thereon. Each Lender’s obligations under this subsection (n) shall survive the payment in full of all amounts payable by such Lender under subsection (j) above, and the termination of this Agreement and the Letters of Credit. Nothing in this subsection (n) is intended to limit any Lender’s reimbursement obligation contained in subsection (j) above.

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(o) Representations of Lenders. As between any Fronting Bank and the Lenders, by its execution and delivery of this Agreement each Lender hereby represents and warrants solely to such Fronting Bank that (i) it is duly organized and validly existing in good standing under the laws of the jurisdiction of its formation, and has full corporate power, authority and legal right to execute, deliver and perform its obligations to such Fronting Bank under this Agreement; and (ii) this Agreement constitutes its legal, valid and binding obligation enforceable against it in accordance with the terms hereof, except as such enforceability may be limited by applicable bank organization, moratorium, conservatorship or other laws now or hereafter in effect affecting the enforcement of creditors rights in general and the rights of creditors of banks, and except as such enforceability may be limited by general principles of equity (whether considered in a proceeding at law or in equity).

(p) The Letters of Credit listed in Schedule IV shall be deemed “Letters of Credit” upon fulfillment of the conditions precedent listed in Sections 3.01 and 3.02.

(q) Successor Fronting Bank. Any Fronting Bank may resign at any time by giving written notice thereof to the Lenders, the other Fronting Banks and the Borrowers, as long as such Fronting Bank has no Letters of Credit outstanding under this Agreement. Upon such resignation, the Borrowers may designate one or more Lenders as Fronting Banks to replace the retiring Fronting Bank. If a Fronting Bank has any Letters of Credit outstanding under this Agreement and delivers a written notice of its intent to resign to the Lenders, the other Fronting Banks and the Borrowers, such Fronting Bank shall continue to honor its obligations under this Agreement, but shall have no obligation to issue any new Letter of Credit. Upon receipt of such notice of intent to resign, the Borrowers and such Fronting Bank may agree to replace or terminate the outstanding Letters of Credit issued by such Fronting Bank and to designate one or more Lenders as Fronting Banks to replace such Fronting Bank.

(r) Reallocation of L/C Fronting Bank Commitments. If any Lender becomes a Fronting Bank after the date hereof (a “New Fronting Bank”), the L/C Fronting Bank Commitments of the Lenders that are Fronting Banks on the date hereof (the “Original Fronting Banks”) shall be reduced by an aggregate amount equal to such New Fronting Bank’s L/C Fronting Banks Commitment, with such reduction to be allocated among the Original Fronting Banks ratably in accordance such Original Fronting Banks’ respective L/C Fronting Bank Commitments on the date of such reduction.

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SECTION 2.05. Fees.

(a) FE agrees to pay to the Administrative Agent for the account of each Lender a commitment fee on the amount of such Lender’s Percentage of the unused aggregate Commitments at such time from the date hereof in the case of each Bank and from the effective date specified in the Assignment and Assumption pursuant to which it became a Lender in the case of each other Lender until the Termination Date applicable to such Lender, payable on the last day of each March, June, September and December during such period, and on such Termination Date, at the rate per annum set forth below determined by reference to the Reference Ratings of FE from time to time in effect:

LEVEL 6

LEVEL 2

LEVEL 3

LEVEL 4

LEVEL 5

Reference

Reference

Reference

Reference

Reference

Ratings

LEVEL 1

Ratings lower

Ratings of

Ratings lower

Ratings lower

lower than

Reference

than Level 1

lower than

than Level 3

than Level 4

BB+ by S&P

Ratings at least

but at least

Level 2 but at

but at least

but at least

and Ba1 by

A- by S&P or

BBB+ by

least BBB by

BBB- by S&P

BB+ by S&P

Moody’s, or

BASIS FOR

A3 by

S&P or Baa1

S&P or Baa2

or Baa3 by

or Ba1 by

no Reference

PRICING

Moody’s.

by Moody’s.

by Moody’s.

Moody’s.

Moody’s.

Ratings.

Commitment Fee

0.15

%

0.20

%

0.25

%

0.30

%

0.40

%

0.55

%

For purposes of the foregoing, if (i) there is a difference of one level in Reference Ratings of S&P and Moody’s and the higher of such Reference Ratings falls in Level 1, Level 2, Level 3, Level 4 or Level 5, then the higher Reference Rating will be used to determine the commitment fee, and (ii) there is a difference of more than one level in Reference Ratings of S&P and Moody’s, the Reference Rating that is one level above the lower of such Reference Ratings will be used to determine the commitment fee, unless the lower of such Reference Ratings falls in Level 6, in which case the lower of such Reference Ratings will be used to determine the commitment fee. If there exists only one Reference Rating, such Reference Rating will be used to determine the commitment fee.

(b) FE agrees to pay the fees payable by the Borrowers in such amounts and payable on such terms as set forth in the Fee Letters.

(c) FE agrees to pay to the Administrative Agent, for the account of the Lenders, a fee in an amount equal to the then Applicable Margin for Eurodollar Rate Advances for each Borrower multiplied by the Stated Amount of each Letter of Credit issued for the account of such Borrower, in each case for the number of days that such Letter of Credit is issued and outstanding, payable quarterly in arrears on the last day of each March, June, September and December and on the date such Letter of Credit expires.

(d) FE agrees to pay to each Fronting Bank, for its own account, certain fees payable by each applicable Borrower in such amounts and payable on such terms as set forth in the Fronting Bank Fee Letter to which such Fronting Bank is a party.

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SECTION 2.06. Reduction of the Commitments; Borrower Sublimits.

The Borrowers shall have the right, upon at least three Business Days’ notice to the Administrative Agent, to terminate in whole or, upon same day notice, from time to time to permanently reduce ratably in part the unused portion of the Commitments; provided that each partial reduction shall be in the aggregate amount of $5,000,000 or in an integral multiple of $1,000,000 in excess thereof; provided, further, that the Commitments may not be reduced to an amount that is less than the aggregate Stated Amount of outstanding Letters of Credit. Subject to the foregoing, any reduction of the Commitments to an amount below $700,000,000 shall also result in a reduction of the L/C Commitment Amount to the extent of such deficit. Each such notice of termination or reduction shall be irrevocable; provided, further, that, if, after giving effect to any reduction of the Commitments, the Swing Line Sublimit or any Borrower Sublimit exceeds the amount of the aggregate Commitments, such sublimit shall be automatically reduced by the amount of such excess. Any Commitment reduced or terminated pursuant to this Section may not be reinstated.

SECTION 2.07. Repayment of Advances.

Each Borrower agrees to repay the principal amount of each Advance made by each Lender to such Borrower no later than the earlier of (i) 364 days after the date such Advance is made (or in the case of a Swing Line Advance, 10 days after the date such Swing Line Advance is made) and (ii) the latest Termination Date applicable to such Lender; provided, however, that if any Borrower shall deliver to the Administrative Agent evidence reasonably satisfactory to the Administrative Agent (including, without limitation, certified copies of governmental approvals and legal opinions) that such Borrower is authorized under Applicable Law to incur Indebtedness hereunder maturing more than 364 days after the date of incurrence of such Indebtedness, such Borrower shall repay each Advance made to it by a Lender no later than the latest Termination Date applicable to such Lender.

SECTION 2.08. Interest on Advances.

Each Borrower agrees to pay interest on the unpaid principal amount of each Advance made by each Lender to such Borrower from the date of such Advance until such principal amount shall be paid in full, at the following rates per annum, subject to Section 2.15(f):

(a) Alternate Base Rate Pro-Rata Advances. If such Advance is an Alternate Base Pro-Rata Rate Advance, a rate per annum equal at all times to the Alternate Base Rate in effect from time to time plus the Applicable Margin for such Alternate Base Rate Pro-Rata Advance in effect from time to time, payable quarterly in arrears on the last day of each March, June, September and December, on the Termination Date and on the date such Alternate Base Rate Pro-Rata Advance shall be Converted or be paid in full and as provided in Section 2.12;

(b) Eurodollar Rate Advances. If such Advance is a Eurodollar Rate Advance, a rate per annum equal at all times during the Interest Period for such Advance to the sum of the Eurodollar Rate for such Interest Period plus the Applicable Margin for such Eurodollar Rate Advance in effect from time to time, payable on the last day of each Interest Period for such Eurodollar Rate Advance (and, in the case of any Interest Period of six months, on the last day of the third month of such Interest Period), on the Termination Date and on the date such Eurodollar Rate Advance shall be Converted or be paid in full and as provided in Section 2.12; and

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(c) Swing Line Advances. If such Advance is a Swing Line Advance, a rate per annum equal to the sum of the Alternate Base Rate in effect from time to time plus the Applicable Margin for such Swing Line Advance payable on the date such Swing Line Advance is paid in full and as provided in Section 2.12.

SECTION 2.09. Additional Interest on Advances.

Each Borrower agrees to pay to each Lender, so long as such Lender shall be required under regulations of the Board of Governors of the Federal Reserve System to maintain reserves with respect to liabilities or assets consisting of or including Eurocurrency Liabilities, additional interest on the unpaid principal amount of each Eurodollar Rate Advance made by such Lender to such Borrower, from the date of such Advance until such principal amount is paid in full, at an interest rate per annum equal at all times to the remainder obtained by subtracting (i) the Eurodollar Rate for the Interest Period for such Advance from (ii) the rate obtained by dividing such Eurodollar Rate by a percentage equal to 100% minus the Eurodollar Rate Reserve Percentage of such Lender for such Interest Period, payable on each date on which interest is payable on such Advance; provided, that no Lender shall be entitled to demand additional interest under this Section 2.09 more than 90 days following the last day of the Interest Period in respect of which such demand is made; provided further, however, that the foregoing proviso shall in no way limit the right of any Lender to demand or receive such additional interest to the extent that such additional interest relates to the retroactive application by the Board of Governors of the Federal Reserve System of any regulation described above if such demand is made within 90 days after the implementation of such retroactive regulation. Such additional interest shall be determined by such Lender and notified to the applicable Borrower through the Administrative Agent, and such determination shall be conclusive and binding for all purposes, absent manifest error.

SECTION 2.10. Interest Rate Determination.

(a) The Administrative Agent shall give prompt notice to the applicable Borrower and the Lenders of the applicable interest rate determined by the Administrative Agent for purposes of Section 2.08(a), (b) or (c).

(b) If, with respect to any Eurodollar Rate Advances, the Majority Lenders notify the Administrative Agent that (i) Dollar deposits are not being offered to banks in the London interbank eurodollar market for the applicable amount and Interest Period of such Eurodollar Rate Advances, (ii) adequate and reasonable means do not exist for determining the Eurodollar Rate or (iii) the Eurodollar Rate for any Interest Period for such Advances will not adequately reflect the cost to such Majority Lenders of making or funding their respective Eurodollar Rate Advances for such Interest Period, the Administrative Agent shall forthwith so notify the Borrowers and the Lenders, whereupon

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(i) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period therefor, Convert into an Alternate Base Rate Pro-Rata Advance, and

(ii) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrowers and the Lenders that the circumstances causing such suspension no longer exist.

(c) Upon the occurrence and during the continuance of any Event of Default, (i) each Eurodollar Rate Advance will automatically, on the last day of the then existing Interest Period thereofor, Convert into a Base Rate Advance, and the obligation of the Lenders to make or to Convert Advances into, Eurodollar Rate Advances shall be suspended.

SECTION 2.11. Conversion of Advances.

(a) Voluntary. Any Borrower may on any Business Day, upon notice given to the Administrative Agent not later than 11:00 a.m. (New York time) on the third Business Day prior to the date of any proposed Conversion into Eurodollar Rate Advances, and on the date of any proposed Conversion into Alternate Base Rate Pro-Rata Advances, and subject to the provisions of Sections 2.10 and 2.14, Convert all Pro-Rata Advances of one Type made to such Borrower in connection with the same Borrowing into Pro-Rata Advances of another Type or Types or Pro-Rata Advances of the same Type having the same or a new Interest Period; provided, however, that any Conversion of, or with respect to, any Eurodollar Rate Advances into Pro-Rata Advances of another Type or Pro-Rata Advances of the same Type having the same or new Interest Periods, shall be made on, and only on, the last day of an Interest Period for such Eurodollar Rate Advances, unless the applicable Borrower shall also reimburse the Lenders in respect thereof pursuant to Section 8.05(b) on the date of such Conversion. Each such notice of a Conversion shall, within the restrictions specified above, specify (i) the date of such Conversion, (ii) the Pro-Rata Advances to be Converted, and (iii) if such Conversion is into, or with respect to, Eurodollar Rate Advances, the duration of the Interest Period for each such resulting Pro-Rata Advance.

(b) Mandatory. If any Borrower shall fail to select the Type of any Pro-Rata Advance or the duration of any Interest Period for any Borrowing comprising Eurodollar Rate Advances in accordance with the provisions contained in the definition of “Interest Period” in Section 1.01 and Section 2.11(a), or if any proposed Conversion of a Borrowing that is to comprise Eurodollar Rate Advances upon Conversion shall not occur as a result of the circumstances described in paragraph (c) below, the Administrative Agent will forthwith so notify such Borrower and the Lenders, and such Advances will automatically, on the last day of the then existing Interest Period therefor, Convert into Alternate Base Rate Pro-Rata Advances.

(c) Failure to Convert. Each notice of Conversion given by any Borrower pursuant to subsection (a) above shall be irrevocable and binding on such Borrower. In the case of any Borrowing that is to comprise Eurodollar Rate Advances upon Conversion, the Borrower agrees to indemnify each Lender against any loss, cost or expense incurred by such Lender as a result of any failure of such Conversion to occur pursuant to the provisions of Section 2.10(c), including, without limitation, any loss, cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by such Lender to fund such Eurodollar Rate Advances upon such Conversion, when such Conversion does not occur. Each Borrower’s obligations under this subsection (c) shall survive the repayment of all other amounts owing by such Borrower to the Lenders and the Administrative Agent under this Agreement and any Note and the termination of the Commitments.

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SECTION 2.12. Prepayments.

(a) Optional. Any Borrower may at any time prepay the outstanding principal amounts of the Advances made to such Borrower as part of the same Borrowing in whole or ratably in part, together with accrued interest to the date of such prepayment on the principal amount prepaid, upon notice thereof given to the Administrative Agent by such Borrower not later than 11:00 a.m. (New York time) (i) on the date of any such prepayment in the case of Alternate Base Rate Advances and (ii) on the second Business Day prior to any such prepayment in the case of Eurodollar Rate Advances; provided, however, that (x) each partial prepayment of any Borrowing shall be in an aggregate principal amount not less than $5,000,000 with respect to Pro-Rata Borrowings and $1,000,000 with respect to Swing Line Borrowings and (y) in the case of any such prepayment of a Eurodollar Rate Advance, such Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.05(b) on the date of such prepayment.

(b) Mandatory. (i) If and to the extent that the Outstanding Credits on any date hereunder shall exceed the aggregate amount of the Commitments hereunder on such date, each Borrower agrees to (A) prepay on such date a principal amount of Advances and/or (B) pay to the Administrative Agent an amount in immediately available funds (which funds shall be held as collateral pursuant to arrangements satisfactory to the Administrative Agent) equal to all or a portion of the amount available for drawing under the Letters of Credit outstanding at such time, which prepayment under clause (A) and payment under clause (B) shall, when taken together result in the amount of Outstanding Credits minus the amount paid to the Administrative Agent pursuant to clause (B) being less than or equal to the aggregate amount of the Commitments hereunder on such date.

(ii) If at any time the Outstanding Credits with respect to a Borrower on any date hereunder shall exceed the Borrower Sublimit for such Borrower, such Borrower agrees to (A) prepay on such date Advances in a principal amount equal to such excess and/or (B) pay to the Administrative Agent an amount in immediately available funds (which funds shall be held as collateral pursuant to arrangements satisfactory to the Administrative Agent) equal to all or a portion of the amount available for drawing under the Letters of Credit outstanding to such Borrower at such time, which prepayment under clause (A) and payment under clause (B) shall, when taken together, result in the amount of Outstanding Credits minus the amount paid to the Administrative Agent pursuant to clause (B) being less than or equal to the aggregate amount of the applicable Borrower Sublimit hereunder on such date.

(iii) If at any time the aggregate principal amount of the Swing Line Advances exceeds the Swing Line Sublimit, each Borrower agrees to prepay the Swing Line Advances outstanding to such Borrower in a principal amount equal to such Borrower’s pro-rata amount of such excess, determined on the basis of the percentage of the aggregate principal amount of Swing Line Advances outstanding to such Borrower.

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Any prepayment of Advances shall be accompanied by accrued interest on the amount prepaid to the date of such prepayment and, in the case of any such prepayment of Eurodollar Rate Advances, the applicable Borrower shall be obligated to reimburse the Lenders in respect thereof pursuant to Section 8.05(b).

SECTION 2.13. Increased Costs.

(a) If, due to any Change in Law, there shall be any increase in the cost (other than in respect of Taxes, which are addressed exclusively in Section 2.16) to any Lender of agreeing to make or making, funding or maintaining Eurodollar Rate Advances or any increase in the cost to any Fronting Bank or any Lender of issuing, maintaining or participating in Letters of Credit, other than, in each case, relating to Taxes, then each Borrower shall from time to time, upon demand by such Lender or such Fronting Bank (as the case may be) (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender or such Fronting Bank (as the case may be) additional amounts sufficient to compensate such Lender or such Fronting Bank (as the case may be) for such increased cost. A certificate as to the amount of such increased cost and the basis therefor, submitted to each Borrower and the Administrative Agent by such Lender or such Fronting Bank (as the case may be), shall constitute such demand and shall be conclusive and binding for all purposes, absent manifest error.

(b) If any Lender or any Fronting Bank determines that any Change in Law affects or would affect the amount of capital required or expected to be maintained by such Lender or such Fronting Bank (as the case may be) or any corporation controlling such Lender or such Fronting Bank (as the case may be) and that the amount of such capital is increased by or based upon the existence of (i) such Lender’s commitment to lend or participate in Letters of Credit hereunder and other commitments of this type or (ii) the Advances made by such Lender or (iii) the participations in Letters of Credit acquired by such Lender or (iv) in the case of any Fronting Bank, such Fronting Bank’s commitment to issue, maintain and honor drawings under Letters of Credit hereunder, or (v) the honoring of Letters of Credit by any Fronting Bank hereunder, then, upon demand by such Lender or such Fronting Bank (as the case may be) (with a copy of such demand to the Administrative Agent), each Borrower shall immediately pay to the Administrative Agent for the account of such Lender or such Fronting Bank (as the case may be), from time to time as specified by such Lender or such Fronting Bank (as the case may be), additional amounts sufficient to compensate such Lender, such Fronting Bank or such corporation in the light of such circumstances, to the extent that such Lender or such Fronting Bank (as the case may be) determines such increase in capital to be allocable to (i) in the case of such Lender, the existence of such Lender’s commitment to lend hereunder or the Advances made by such Lender or (ii) the participations in Letters of Credit acquired by such Lender or (iii) in the case of any Fronting Bank, such Fronting Bank’s Commitment to issue, maintain and honor drawings under Letters of Credit hereunder, or (iv) the honoring of Letters of Credit by any Fronting Bank hereunder. A certificate as to such amounts submitted to each Borrower and the Administrative Agent by such Lender or such Fronting Bank (as the case may be) shall constitute such demand and shall be conclusive and binding for all purposes, absent manifest error.

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(c) Each Borrower shall be liable for its pro rata share of each payment to be made by the Borrowers under subsections (a) and (b) of this Section 2.13, determined on the basis of such Borrower’s Fraction; provided, however, that if and to the extent that any such liabilities are reasonably determined by the Borrowers (subject to the approval of the Administrative Agent, which approval shall not be unreasonably withheld) to be directly attributable to Advances made to a specific Borrower, then only such Borrower shall be liable for such payments.

(d) Failure or delay on the part of any Lender or Fronting Bank to demand compensation pursuant to this Section shall not constitute a waiver of such Lender’s or Fronting Bank’s right to demand such compensation, provided that the Borrowers shall not be required to compensate a Lender or Fronting Bank pursuant to this Section for any increased costs or additional amounts incurred more than 180 days prior to the date that such Lender or Fronting Bank notifies the Borrowers of such Lender’s or Fronting Bank’s intention to claim such compensation (except that, if such Change in Law giving rise to such increased costs is retroactive, then the 180-day period referred to above shall be extended to include the period of retroactive effect thereof).

SECTION 2.14. Illegality.

Notwithstanding any other provision of this Agreement, if any Lender shall notify the Administrative Agent that the introduction of or any change in or in the interpretation of any law or regulation makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for any Lender or its Eurodollar Lending Office to perform its obligations hereunder to make Eurodollar Rate Advances or to fund or maintain Eurodollar Rate Advances hereunder, (i) the obligation of the Lenders to make, or to Convert Advances into, Eurodollar Rate Advances shall be suspended until the Administrative Agent shall notify the Borrowers and the Lenders that the circumstances causing such suspension no longer exist and (ii) the Borrowers shall forthwith prepay in full all Eurodollar Rate Advances of all Lenders then outstanding, together with interest accrued thereon, unless (A) the Borrowers, within five Business Days of notice from the Administrative Agent, Converts all Eurodollar Rate Advances of all Lenders then outstanding into Advances of another Type in accordance with Section 2.11 or (B) the Administrative Agent notifies the Borrowers that the circumstances causing such prepayment no longer exist. Any Lender that becomes aware of circumstances that would permit such Lender to notify the Administrative Agent of any illegality under this Section 2.14 shall use its best efforts (consistent with its internal policy and legal and regulatory restrictions) to change the jurisdiction of its Applicable Lending Office if the making of such change would avoid or eliminate such illegality and would not, in the reasonable judgment of such Lender, be otherwise disadvantageous to such Lender.

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SECTION 2.15. Payments and Computations.

(a) Each Borrower shall make each payment hereunder and under any Note not later than 12:00 noon (New York time) on the day when due in Dollars to the Administrative Agent or, with respect to payments made in respect of Reimbursement Obligations, to the applicable Fronting Bank, at its address referred to in Section 8.02 in same day funds, without set-off, counterclaim or defense and any such payment to the Administrative Agent or any Fronting Bank (as the case may be) shall constitute payment by such Borrower hereunder or under any Note, as the case may be, for all purposes, and upon such payment the Lenders shall look solely to the Administrative Agent or such Fronting Bank (as the case may be) for their respective interests in such payment. The Administrative Agent or such Fronting Bank (as the case may be) will promptly after any such payment cause to be distributed like funds relating to the payment of principal or interest or commitment fees or Reimbursement Obligations ratably (other than amounts payable pursuant to Section 2.02(c), 2.05, 2.09, 2.11(c), 2.13, 2.16, 2.21 or 8.05(b)) (according to the Lenders’ respective Commitments) to the Lenders for the account of their respective Applicable Lending Offices, and like funds relating to the payment of any other amount payable to any Lender to such Lender for the account of its Applicable Lending Office, in each case to be applied in accordance with the terms of this Agreement. Upon its acceptance of an Assignment and Assumption and recording of the information contained therein in the Register pursuant to Section 8.08(d), from and after the effective date specified in such Assignment and Assumption, the Administrative Agent and each Fronting Bank shall make all payments hereunder and under any Note in respect of the interest assigned thereby to the Lender assignee thereunder, and the parties to such Assignment and Assumption shall make all appropriate adjustments in such payments for periods prior to such effective date directly between themselves.

(b) Each Borrower hereby authorizes each Lender, each Swing Line Lender and each Fronting Bank, if and to the extent payment owed to such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) is not made by such Borrower to the Administrative Agent, such Swing Line Lender or such Fronting Bank (as the case may be) when due hereunder or under any Note held by such Lender, to charge from time to time against any or all of such Borrower’s accounts (other than any payroll account maintained by such Borrower with such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) if and to the extent that such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) shall have expressly waived its set-off rights in writing in respect of such payroll account) with such Lender, such Swing Line Lender or such Fronting Bank (as the case may be) any amount so due.

(c) All computations of interest based on the Alternate Base Rate (based upon RBS’s “prime rate”) shall be made by the Administrative Agent on the basis of a year of 365 or 366 days, as the case may be, and all computations of commitment fees and of interest based on the Alternate Base Rate (based upon the Federal Funds Rate or upon clause (iii) of the definition of Alternate Base Rate), the Eurodollar Rate or the Federal Funds Rate shall be made by the Administrative Agent, and all computations of interest pursuant to Section 2.09 shall be made by a Lender, on the basis of a year of 360 days, in each case for the actual number of days (including the first day but excluding the last day) occurring in the period for which such commitment fees or interest are payable. Each determination by the Administrative Agent (or, in the case of Section 2.09, by a Lender) of an interest rate hereunder shall be conclusive and binding for all purposes, absent manifest error.

(d) Whenever any payment hereunder or under any Note shall be stated to be due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, and such extension of time shall in such case be included in the computation of payment of interest or commitment fees, as the case may be; provided, however, if such extension would cause payment of interest on or principal of Eurodollar Rate Advances to be made in the next following calendar month, such payment shall be made on the next preceding Business Day.

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(e) Unless the Administrative Agent shall have received notice from any Borrower prior to the date on which any payment is due to the Lenders hereunder that such Borrower will not make such payment in full, the Administrative Agent may assume that each Borrower has made such payment in full to the Administrative Agent on such date and the Administrative Agent may, in reliance upon such assumption, cause to be distributed to each Lender on such due date an amount equal to the amount then due such Lender. If and to the extent that a Borrower shall not have so made such payment in full to the Administrative Agent, each Lender shall repay to the Administrative Agent forthwith on demand such amount distributed to such Lender together with interest thereon, for each day from the date such amount is distributed to such Lender until the date such Lender repays such amount to the Administrative Agent, at the Federal Funds Rate.

(f) The principal amount of any Advance (or any portion thereof) payable by a Borrower hereunder or under any Note that is not paid when due (whether at stated maturity, by acceleration or otherwise) shall (to the fullest extent permitted by law) bear interest from the date when due until paid in full at a rate per annum equal at all times to the rate otherwise applicable to such Advance plus 2% per annum, payable upon demand. Any other amount payable by a Borrower hereunder or under any Note that is not paid when due (whether at stated maturity, by acceleration or otherwise) shall (to the fullest extent permitted by law) bear interest from the date when due until paid in full at a rate per annum equal at all times to the rate of interest applicable to Alternate Base Rate Advances plus 2% per annum, payable upon demand.

(g) To the extent that any payment by or on behalf of a Borrower is made to the Administrative Agent, any Fronting Bank or any Lender, or the Administrative Agent, any Fronting Bank or any Lender exercises its right of setoff, and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by the Administrative Agent, such Fronting Bank or such Lender in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding under any bankruptcy, insolvency or other similar law now or hereafter in effect or otherwise, then (i) to the extent of such recovery, the obligation or part thereof originally intended to be satisfied shall be revived and continued in full force and effect as if such payment had not been made or such setoff had not occurred, and (ii) each Lender and each Fronting Bank severally agrees to pay to the Administrative Agent upon demand its applicable share (without duplication) of any amount so recovered from or repaid by the Administrative Agent, plus interest thereon from the date of such demand to the date such payment is made at a rate per annum equal to the Federal Funds Rate from time to time in effect. The obligations of the Lenders and the Fronting Banks under clause (ii) of the preceding sentence shall survive the payment in full of any amounts hereunder and the termination of this Agreement.

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SECTION 2.16. Taxes.

(a) Any and all payments by each Borrower hereunder and under any Note or any other Loan Document shall be made, in accordance with Section 2.15, free and clear of and without deduction or withholding for any Indemnified Taxes, and all liabilities with respect thereto. If a Borrower shall be required by law to deduct any Taxes from or in respect of any sum payable hereunder or under any Note or any other Loan Document to any Recipient, (i) if such Taxes are Indemnified Taxes, the sum payable shall be increased as necessary so that after making all required deductions (including deductions applicable to additional sums payable under this Section 2.16) such Recipient receives an amount equal to the sum it would have received had no such deductions been made, (ii) such Borrower shall make such deductions and (iii) such Borrower shall timely pay or cause to be timely paid the full amount deducted to the relevant Governmental Authority in accordance with Applicable Law.

(b) In addition, each Borrower agrees to timely pay or cause to be timely paid any Other Taxes in accordance with Applicable Law.

(c) Each Borrower agrees to indemnify each Recipient, within 30 days after written demand therefore, for the full amount of Indemnified Taxes (including, without limitation, any Indemnified Taxes imposed by any jurisdiction on amounts payable under this Section 2.16) paid or payable by such Recipient and any liability (including penalties, interest and expenses) arising therefrom or with respect thereto, whether or not such Indemnified Taxes were correctly or legally asserted. A certificate as to the amount of such payment or liability delivered to FE by or on behalf of the applicable Recipient shall be conclusive, absent manifest error.

(d) As soon as practicable after any payment of Indemnified Taxes by any Borrower to a Governmental Authority, such Borrower shall deliver to the Administrative Agent an original or a certified copy of a receipt issued by such Governmental Authority evidencing such payment or other evidence of such payment reasonably satisfactory to the Administrative Agent.

(e) Tax Forms.

(i) Any Lender that is a U.S. Person shall deliver to each Borrower and the Administrative Agent, on or prior to the date on which such Lender becomes a Lender under this Agreement (and from time to time thereafter upon the reasonable request of such Borrower or the Administrative Agent), duly executed originals of IRS Form W-9 (or copies thereof) certifying, to the extent such Lender is legally entitled to do so, that such Lender is exempt from U.S. federal backup withholding tax.

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(ii) Any Lender that is not a U.S. Person and that is entitled to an exemption from or reduction of withholding tax under the Code or any treaty to which the United States is a party with respect to payments under this Agreement shall deliver to each Borrower and the Administrative Agent, at the time or times prescribed by applicable law, such properly completed and executed documentation prescribed by applicable law or reasonably requested by such Borrower or the Administrative Agent as will permit such payments to be made without withholding or at a reduced rate of withholding, as applicable. Without limiting the generality of the foregoing, each Lender that is not a U.S. Person shall, to the extent it is legally entitled to do so, (w) on or prior to the date such Lender becomes a Lender under this Agreement, (x) on or prior to the date on which any such form or certification expires or becomes obsolete, (y) after the occurrence of any event requiring a change in the most recent form or certification previously delivered by it pursuant to this subsection, and (z) from time to time upon the reasonable request by any Borrower or the Administrative Agent, deliver to such Borrower and the Administrative Agent (in such number of copies as shall be requested by such Borrower or the Administrative Agent), whichever of the following is applicable:

(A) if such Lender is claiming eligibility for benefits of an income tax treaty to which the United States is a party (x) with respect to payments of interest under any Loan Document, duly executed originals of IRS Form W-8BEN, or any successor form thereto, establishing an exemption from, or reduction of, U.S. federal withholding tax pursuant to the “interest” article of such tax treaty, and (y) with respect to any other payments under any Loan Document, duly executed originals of IRS Form W-8BEN, or any successor form thereto, establishing an exemption from, or reduction of, U.S. federal withholding tax pursuant to the “business profits” or “other income” article of such tax treaty;

(B) duly executed originals of IRS Form W-8ECI, or any successor form thereto, certifying that the payments received by such Lender are effectively connected with such Lender’s conduct of a trade or business in the United States;

(C) if such Lender is claiming the benefits of the exemption for “portfolio interest” under Section 871(h) or Section 881(c) of the Code, duly executed originals of IRS Form W-8BEN, or any successor form thereto, together with a certificate (a “U.S. Tax Compliance Certificate”) upon which such Lender certifies that (1) such Lender is not a bank for purposes of Section 881(c)(3)(A) of the Code, or the obligation of the Borrower hereunder is not, with respect to such Lender, a loan agreement entered into in the ordinary course of its trade or business, within the meaning of that Section of the Code, (2) such Lender is not a 10% shareholder of the Borrower within the meaning of Section 871(h)(3) or Section 881(c)(3)(B) of the Code, (3) such Lender is not a controlled foreign corporation that is related to the Borrower within the meaning of Section 881(c)(3)(C) of the Code, and (4) the interest payments in question are not effectively connected with a U.S. trade or business conducted by such Lender; or

(D) if such Lender is not the beneficial owner (for example, a partnership or a Lender granting a participation), duly executed originals of IRS Form W-8IMY, or any successor form thereto, accompanied by IRS Form W-9, IRS Form W-8ECI, IRS Form W-8BEN, a U.S. Tax Compliance Certificate, and/or other certification documents from each beneficial owner, as applicable.

(iii) Each Lender agrees that if any form or certification it previously delivered under this Section 2.16(e) expires or becomes obsolete or inaccurate in any respect and such Lender is not legally entitled to provide an updated form or certification, it shall promptly notify the Borrowers and the Administrative Agent of its inability to update such form or certification.

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(f) If a payment made to a Lender hereunder or under any other Loan Document would be subject to U.S. Federal withholding Tax imposed by FATCA if such Lender were to fail to comply with the applicable reporting requirements of FATCA (including those contained in Section 1471(b) or 1472(b) of the Code, as applicable), such Lender shall deliver to each Borrower and the Administrative Agent, at the time or times prescribed by law and at such time or times reasonably requested by any Borrower or the Administrative Agent, such documentation prescribed by applicable law (including as prescribed by Section 1471(b)(3)(C)(i) of the Code) and such additional documentation reasonably requested by such Borrower or the Administrative Agent as may be necessary for each of the Borrowers and the Administrative Agent to comply with its obligations under FATCA, to determine that such Lender has complied with such Lender’s obligations under FATCA or to determine the amount to deduct and withhold from such payment.

(g) Any Lender claiming any additional amounts payable pursuant to this Section 2.16 shall use its best efforts (consistent with its internal policy and legal and regulatory restrictions) to change the jurisdiction of its Applicable Lending Office if the making of such a change would avoid the need for, or reduce the amount of, any such additional amounts that may thereafter accrue and would not, in the reasonable judgment of such Lender, be otherwise disadvantageous to such Lender.

(h) Without prejudice to the survival of any other agreement of the Borrowers hereunder, the agreements and obligations of the Borrowers contained in this Section 2.16 shall survive the payment in full of principal and interest hereunder and under any Note.

SECTION 2.17. Sharing of Payments, Etc.

(a) If any Lender shall obtain any payment (whether voluntary, involuntary, through the exercise of any right of set-off, or otherwise) on account of the Advances made by it or participations in Letters of Credit acquired by it (other than pursuant to Section 2.02(c), 2.09, 2.11(c), 2.13, 2.16, 2.21 or 8.05(b)) in excess of its ratable share of payments on account of the Advances or Letters of Credit (as the case may be) obtained by all the Lenders, such Lender shall forthwith purchase from the other Lenders such participations in the Advances made by them or participations in Letters of Credit acquired by them (as the case may be) as shall be necessary to cause such purchasing Lender to share the excess payment ratably with each of them; provided, however, that if all or any portion of such excess payment is thereafter recovered from such purchasing Lender, such purchase from each Lender shall be rescinded and such Lender shall repay to the purchasing Lender the purchase price to the extent of such recovery together with an amount equal to such Lender’s ratable share (according to the proportion of (a) the amount of such Lender’s required repayment to (b) the total amount so recovered from the purchasing Lender) of any interest or other amount paid or payable by the purchasing Lender in respect of the total amount so recovered. Each Borrower agrees that any Lender so purchasing a participation from another Lender pursuant to this Section 2.17 may, to the fullest extent permitted by law, exercise all its rights of payment (including the right of set-off) with respect to such participation as fully as if such Lender were the direct creditor of such Borrower in the amount of such participation.

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(b) If any Lender shall fail to make any payment required to be made by it pursuant to Section 2.02(c), 2.03(c), 2.04(j) or 7.05, then the Administrative Agent may, in its discretion and notwithstanding any contrary provision hereof, (i) apply any amounts thereafter received by the Administrative Agent for the account of such Lender for the benefit of the Administrative Agent, any Swing Line Lender or any Fronting Bank to satisfy such Lender’s obligations to it under such Section until all such unsatisfied obligations are fully paid, and/or (ii) hold any such amounts in a segregated account as cash collateral for, and application to, any future funding obligations of such Lender under any such Section, in the case of each of clauses (i) and (ii) above, in any order as determined by the Administrative Agent in its discretion.

SECTION 2.18. Noteless Agreement; Evidence of Indebtedness.

(a) Each Lender shall maintain in accordance with its usual practice an account or accounts evidencing the indebtedness of each Borrower to such Lender resulting from each Advance made by such Lender from time to time, including the amounts of principal and interest payable and paid to such Lender from time to time hereunder.

(b) The Administrative Agent shall also maintain accounts in which it will record (i) the amount of each Advance made hereunder, the Borrower thereof, the Type thereof and the Interest Period (if any) with respect thereto, (ii) the amount of any principal or interest due and payable or to become due and payable from such Borrower to each Lender hereunder, and (iii) the amount of any sum received by the Administrative Agent hereunder from each Borrower and each Lender’s share thereof.

(c) Subject to Section 8.08(c), the entries maintained in the accounts maintained pursuant to subsections (a) and (b) above shall be prima facie evidence of the existence and amounts of the obligations therein recorded; provided, however, that the failure of the Administrative Agent or any Lender to maintain such accounts or any error therein shall not in any manner affect the obligation of each Borrower to repay such obligations in accordance with their terms.

(d) Any Lender may request that its Advances be evidenced by a Note. In such event, each Borrower shall prepare, execute and deliver to such Lender a Note payable to such Lender and its registered assigns. Thereafter, the Advances evidenced by such Note and interest thereon shall at all times (including after any assignment pursuant to Section 8.08) be represented by one or more Notes payable to the payee named therein, or to its registered assigns pursuant to Section 8.08, except to the extent that any such Lender or assignee subsequently returns any such Note for cancellation and requests that such Borrowings once again be evidenced as described in subsections (a) and (b) above.

SECTION 2.19. Extension of Termination Date.

(a) The Borrowers may, by notice to the Administrative Agent (which shall promptly notify the Lenders) not earlier than 45 days prior to any anniversary of the date of this Agreement (the “Anniversary Date”) but no later than 30 days prior to such anniversary of the Closing Date (the date of delivery of any such notice being the “Borrower Extension Notice Date”), request that each Lender extend such Lender’s Termination Date for an additional one year after the Termination Date then in effect for such Lender hereunder (the “Existing Termination Date”). The Borrowers may request no more than two extensions pursuant to this Section.

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(b) Each Lender, acting in its sole and individual discretion, shall, by notice to the Administrative Agent given not earlier than 30 days prior to the applicable Anniversary Date and not later than the date (the “Lender Extension Notice Date”) that is 20 days prior to the Applicable Anniversary Date, advise the Administrative Agent whether or not such Lender agrees to such extension (and each Lender that determines not to so extend its Existing Termination Date (a “Nonconsenting Lender”) shall notify the Administrative Agent of such fact promptly after such determination (but in any event no later than the Lender Extension Notice Date), and any Lender that does not so advise the Administrative Agent on or before the Lender Extension Notice Date shall be deemed to be a Nonconsenting Lender. The election of any Lender to agree to such extension shall not obligate any other Lender to so agree.

(c) The Administrative Agent shall notify the Borrowers of each Lender’s determination under this Section no later than the date 15 days prior to the applicable Anniversary Date, or, if such date is not a Business Day, on the next preceding Business Day (the “Specified Date”).

(d) The Borrowers shall have the right on or before the fifth Business Day after the Specified Date to replace each Nonconsenting Lender (i) with an existing Lender, and/or (ii) by adding as “Lenders” under this Agreement in place thereof, one or more Persons (each Lender in clauses (i) and (ii), an “Additional Commitment Lender”), in each case, with the approval of the Administrative Agent, the Swing Line Lenders and the Fronting Banks (which approvals shall not be unreasonably withheld), each of which Additional Commitment Lenders shall have entered into an agreement in form and substance satisfactory to the Borrowers and the Administrative Agent pursuant to which such Additional Commitment Lender shall, effective as of the Specified Date, undertake a Commitment (and, if any such Additional Commitment Lender is already a Lender, its Commitment shall be in addition to such Lender’s Commitment hereunder on such date); provided that the aggregate amount of the Commitments for all Additional Commitment Lenders shall be no more than the aggregate amount of the Commitments of all Nonconsenting Lenders; provided, further, that the existing Lenders shall have the right to increase their Commitments up to the amount of the Nonconsenting Lenders’ Commitments before the Borrowers shall have the right to substitute any other Person for any Nonconsenting Lender.

(e) If (and only if) the aggregate amount of the Commitments of the Lenders that have agreed to extend their Existing Termination Dates plus the aggregate additional Commitments of the Additional Commitment Lenders shall be more than 50% of the aggregate amount of the Commitments in effect immediately prior to the Specified Date, then, effective as of the Specified Date, the Existing Termination Date of each Lender agreeing to an extension and of each Additional Commitment Lender shall be extended to the date that is one year after the Existing Termination Date, and each Additional Commitment Lender shall thereupon become a “Lender” for all purposes of this Agreement.

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(f) Notwithstanding the foregoing, the extension of a Lender’s Existing Termination Date pursuant to this Section shall be effective with respect to such Lender on the Specified Date but only if (i) the following statements shall be true: (A) no event has occurred and is continuing, or would result from the extension of the Existing Termination Date, that constitutes an Event of Default or an Unmatured Default and (B) the representations and warranties contained in Section 4.01 (other than the first sentence of subsection (g) thereof but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended) are correct in all material respects on and as of the Specified Date, before and after giving effect to such extension, as though made on and as of such date, except for those made specifically as of another date, in which case such representations and warranties shall be true as of such other date, provided that, for purposes of the representations and warranties in Sections 4.01(f) and the last sentence of 4.01(g), the Disclosure Documents shall include all the SEC filings made by FE and the Borrowers prior to the applicable Borrower Extension Notice Date and (ii) on or prior to the Specified Date the Administrative Agent shall have received the following, each dated the Specified Date and in form and substance satisfactory to the Administrative Agent: (x) a certificate of an Authorized Officer of each Borrower to the effect that as of the Specified Date the statements set forth in clauses (A) and (B) above are true, (y) certified copies of the resolutions of the Board of Directors of each Borrower authorizing such extension and the performance of this Agreement on and after the Specified Date, and of all documents evidencing other necessary corporate action and Governmental Action with respect to this Agreement and such extension of the Existing Termination Date and (z) an opinion of counsel to the Borrowers, as to such matters related to the foregoing as the Administrative Agent or the Lenders through the Administrative Agent may reasonably request.

(g) Subject to subsection (d) above, the Commitment of any Nonconsenting Lender shall automatically terminate on its Existing Termination Date (without regard to any extension by any other Lender).

(h) Each Swing Line Lender and Fronting Bank may, in its sole discretion, elect not to serve in such capacity following any extension of the Termination Date; provided that, (i) the Borrowers and the Administrative Agent may appoint a replacement for any such resigning Swing Line Lender or Fronting Bank and (ii) the extension of the Termination Date may become effective without regard to whether such replacement is found.

SECTION 2.20. Several Obligations.

Each Borrower’s obligations hereunder are several and not joint. Any action taken by or on behalf of the Borrowers shall not result in one Borrower being held responsible for the actions, debts or liabilities of the other Borrowers. Nothing contained herein shall be interpreted as requiring the Borrowers to effect Borrowings jointly.

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SECTION 2.21. Defaulting Lenders.

Notwithstanding any provision of this Agreement to the contrary, if any Lender becomes a Defaulting Lender, then the following provisions shall apply for so long as such Lender is a Defaulting Lender:

(a) fees shall cease to accrue on the Percentage of such Defaulting Lender in the unused portion of each Borrower’s Borrower Sublimit pursuant to Section 2.05(a);

(b) the Commitment and Outstanding Credits of such Defaulting Lender shall not be included in determining whether (i) the Majority Lenders have taken or may take any action under this Agreement or (ii) all Lenders affected thereby have taken or may take any action under this Agreement, except to the extent Section 8.01 requires the consent of all Lenders affected thereby (and does not otherwise exclude the Defaulting Lenders from such required consent) to an amendment, waiver or other modification;

(c) if any Swing Line Advance, Letter of Credit or Reimbursement Obligation is outstanding at the time such Lender becomes a Defaulting Lender then:

(i) all or any part of the obligation of such Defaulting Lender to participate in such Swing Line Advance, Letter of Credit or Reimbursement Obligation shall be reallocated among the non-Defaulting Lenders in accordance with their respective Percentages but only to the extent that (x) the sum of all non-Defaulting Lenders’ Outstanding Credits does not exceed the total of all non-Defaulting Lenders’ Commitments and (y) the conditions set forth in Section 3.02 are satisfied at such time;

(ii) if the reallocation described in clause (i) above cannot, or can only partially, be effected, each Borrower shall within one Business Day following notice by the Administrative Agent (x) first, prepay its Swing Line Advances, if any, and (y) second, cash collateralize for the benefit of the applicable Fronting Banks only such Borrower’s obligations, if any, corresponding to such Defaulting Lender’s obligation to participate in Letters of Credit (after giving effect to any partial reallocation pursuant to clause (i) above) in a manner reasonably satisfactory to the Administrative Agent and such Fronting Banks for so long as such LC Exposure is outstanding;

(iii) if and to the extent that any Borrower cash collateralizes any portion of such Defaulting Lender’s obligation to participate in Letters of Credit pursuant to clause (ii) above, such Borrower shall not be required to pay any fees to such Defaulting Lender pursuant to Section 2.05(c) with respect to such Defaulting Lender’s Percentage of the Stated Amount of all Letters of Credit during the period such Defaulting Lender’s obligation is cash collateralized;

(iv) if the obligation of the non-Defaulting Lenders to participate in Letters of Credit is reallocated pursuant to clause (i) above, then the fees payable to the Lenders pursuant to Section 2.05(c) shall be adjusted in accordance with such non-Defaulting Lenders’ Percentages; and

(v) if all or any portion of the obligation of the non-Defaulting Lenders to participate in Letters of Credit is neither reallocated nor cash collateralized pursuant to clause (i) or (ii) above, then, without prejudice to any rights or remedies of any Fronting Bank or any other Lender hereunder, all fees payable under Section 2.05(c) with respect to such Defaulting Lender’s Percentage of the Stated Amount of all Letters of Credit shall be payable to the applicable Fronting Banks until and to the extent that such obligation is reallocated and/or cash collateralized; and

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(d) so long as such Lender is a Defaulting Lender, no Swing Line Lender shall be required to fund any Swing Line Advance, and no Fronting Bank shall be required to make any Extension of Credit in connection with a Letter of Credit, unless it is satisfied that the related exposure and the Defaulting Lender’s then outstanding obligations to participate in such Letter of Credit will be 100% covered by the Commitments of the non-Defaulting Lenders and/or cash collateral will be provided by the applicable Borrower in accordance with subsection (c) above, and participating interests in any newly made Swing Line Advance or any new Extension of Credit relating to a Letter of Credit shall be allocated among non-Defaulting Lenders in a manner consistent with subsection (c)(i) above (and such Defaulting Lender shall not participate therein).

If a Bankruptcy Event with respect to a Parent of any Lender shall occur following the date hereof and for so long as such event shall continue, then no Swing Line Lender shall be required to fund any Swing Line Advance, and no Fronting Bank shall be required to issue, amend or increase any Letter of Credit, unless such Swing Line Lender or Fronting Bank, as the case may be, shall have entered into arrangements with the applicable Borrower or such Lender reasonably satisfactory to such Swing Line Lender or Fronting Bank, as the case may be, to defease any risk to it in respect of such Lender hereunder.

In the event that the Administrative Agent, the applicable Borrower, the Swing Line Lenders and the Fronting Banks all agree that a Defaulting Lender has adequately remedied all matters that caused such Lender to be a Defaulting Lender, then the obligation of such Lender to participate in Swing Line Advances made to such Borrower and Letters of Credit for the account of such Borrower shall be readjusted to reflect the inclusion of such Lender’s Commitment and on such date such Lender shall purchase at par such of the Advances of the other Lenders (other than Swing Line Advances) as the Administrative Agent shall determine may be necessary in order for such Lender to hold such Advances in accordance with its Percentage.

ARTICLE III
CONDITIONS OF LENDING AND ISSUING LETTERS OF CREDIT

SECTION 3.01. Conditions Precedent to Initial Extension of Credit.

The obligation of each Lender and each Swing Line Lender to make its initial Advance to any Borrower, and the obligation of each Fronting Bank to issue its initial Letter of Credit, are subject to the conditions precedent that on or before the date of any such Extension of Credit:

(a) The Administrative Agent shall have received the following, each dated the same date (except for the financial statements referred to in paragraph (iv)), in form and substance satisfactory to the Administrative Agent and (except for any Note) with one copy for each Swing Line Lender, each Fronting Bank and each Lender:

(i) This Agreement, duly executed by each of the parties hereto, and Notes requested by any Lender pursuant to Section 2.18(d), duly completed and executed by each Borrower and payable to the order of such Lender;

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(ii) Certified copies of the resolutions of the Board of Directors of each Borrower (or the equivalent authorization, in the case of Allegheny) approving this Agreement and the other Loan Documents to which it is, or is to be, a party and of all documents evidencing any other necessary corporate action with respect to this Agreement and such Loan Documents;

(iii) A certificate of the Secretary or an Assistant Secretary of each Borrower certifying (A) the names and true signatures of the officers of such Borrower authorized to sign each Loan Document to which such Borrower is, or is to become, a party and the other documents to be delivered hereunder; (B) that attached thereto are true and correct copies of the Organizational Documents of such Borrower, in each case as in effect on such date, and (C) that attached thereto are true and correct copies of all governmental and regulatory authorizations and approvals (including such Borrower’s Approval) required for the due execution, delivery and performance by such Borrower of this Agreement and each other Loan Document to which such Borrower is, or is to become, a party;

(iv) Copies of all the Disclosure Documents (it being agreed that those Disclosure Documents publicly available on the SEC’s EDGAR Database or on FE’s website no later than the Business Day immediately preceding the date of such Extension of Credit will be deemed to have been delivered under this clause (iv));

(v) An opinion of Wendy E. Stark, Associate General Counsel of FE, counsel for the Borrowers, substantially in the form of Exhibit F hereto;

(vi) An opinion of Akin Gump Strauss Hauer & Feld LLP, special counsel for the Borrowers, substantially in the form of Exhibit G hereto;

(vii) A favorable opinion of King & Spalding LLP, special New York counsel for the Administrative Agent, substantially in the form of Exhibit H hereto; and

(viii) Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent, such Fronting Bank, such Swing Line Lender or such other Lender (as the case may be).

(b) FE and each Fronting Bank shall have entered into an agreement, in form and substance satisfactory to such Fronting Bank, concerning fees payable by the Borrowers to such Fronting Bank for its own account (the “Fronting Bank Fee Letters”).

(c) FE shall have paid all of the fees payable in accordance with the Fee Letters, and FE shall have paid all the fees payable in accordance with the Fronting Bank Fee Letters.

(d) All amounts outstanding under the Existing Facilities and the Union Bank Facility, in each case, whether for principal, interest, fees or otherwise, shall have been paid in full, all commitments to lend thereunder shall have been terminated, and the Existing Facilities and the Union Bank Facility shall have been terminated.

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(e) The Administrative Agent shall have received all documentation and information required by regulatory authorities under applicable “know your customer” and anti-money laundering rules and regulations, including without limitation the Patriot Act, to the extent such documentation or information is requested by the Administrative Agent on behalf of the Lenders prior to the date hereof.

SECTION 3.02. Conditions Precedent to Each Extension of Credit.

The obligation of each Lender and each Swing Line Lender to make an Advance to any Borrower as part of any Borrowing (including the initial Borrowing) that would increase the aggregate principal amount of Advances outstanding hereunder, and the obligation of each Fronting Bank to issue, amend, extend or renew a Letter of Credit (including the initial Letter of Credit for the account of such Borrower), in each case, as part of an Extension of Credit, shall be subject to the further conditions precedent that on the date of such Extension of Credit:

(i) The following statements shall be true (and each of the giving of the applicable Notice of Pro-Rata Borrowing, Notice of Swing Line Borrowing or Letter of Credit Request and the acceptance by such Borrower of the proceeds of such Borrowing or the acceptance of a Letter of Credit by the Beneficiary thereof, as the case may be, shall constitute a representation and warranty by such Borrower that on the date of such Extension of Credit such statements are true):

(A) The representations and warranties of such Borrower contained in Section 4.01 (other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of FE and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof with respect to any Extension of Credit following the initial Extension of Credit) hereof are true and correct on and as of the date of such Extension of Credit, before and after giving effect to such Extension of Credit and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of such Extension of Credit, in which case, such representation and warranty shall be true and correct as of such specific date);

(B) No event has occurred and is continuing, or would result from such Extension of Credit or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower; and

(C) Immediately following such Extension of Credit, (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment, (3) the aggregate principal amount of Advances outstanding for such Borrower shall not exceed the amounts authorized under such Borrower’s Approval, (4) the Outstanding Credits for the account of any Borrower shall not exceed the Borrower Sublimit for such Borrower, (5) the aggregate principal amount of the Swing Line Advances outstanding shall not exceed the Swing Line Sublimit, and (6) if such Extension of Credit relates to a Letter of Credit, the Stated Amount thereof, when aggregated with (x) the Stated Amount of each other Letter of Credit that is outstanding or with respect to which a Letter of Credit Request has been received and (y) the outstanding Reimbursement Obligations, shall not exceed the L/C Commitment Amount; and

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(ii) Such Borrower shall have delivered to the Administrative Agent copies of such other approvals and documents as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any other Lender (through the Administrative Agent) may reasonably request.

ARTICLE IV
REPRESENTATIONS AND WARRANTIES

SECTION 4.01. Representations and Warranties of the Borrowers.

Each Borrower represents and warrants as follows:

(a) Existence and Power. It is a corporation or limited liability company, as the case may be, duly formed, validly existing and in good standing under the laws of the jurisdiction of its formation, is duly qualified to do business as a foreign corporation or limited liability company in and is in good standing under the laws of each state in which the ownership of its properties or the conduct of its business makes such qualification necessary, except where the failure to be so qualified would not reasonably be expected to have a Material Adverse Effect with respect to such Borrower, and has all corporate or limited liability company powers and all governmental licenses, authorizations, consents and approvals required to carry on its business as now conducted except where the failure to do so, in each case, would not reasonably be expected to have a Material Adverse Effect.

(b) Due Authorization. The execution, delivery and performance by it of each Loan Document to which it is, or is to become, a party, have been duly authorized by all necessary corporate action on its part and do not, and will not, require the consent or approval of its shareholders or members, as the case may be, other than such consents and approvals as have been duly obtained, given or accomplished.

(c) No Violation, Etc. Neither the execution, delivery or performance by it of this Agreement or any other Loan Document to which it is, or is to become, a party, nor the consummation by it of the transactions contemplated hereby or thereby, nor compliance by it with the provisions hereof or thereof, contravenes or will contravene, or results or will result in a breach of, any of the provisions of its Organizational Documents, any Applicable Law, or any indenture, mortgage, lease or any other agreement or instrument to which it or any of its Subsidiaries is party or by which its property or the property of any of its Subsidiaries is bound, or results or will result in the creation or imposition of any Lien upon any of its property or the property of any of its Subsidiaries except as provided herein, except to the extent such contravention or breach, or the creation or imposition of any such Lien, individually or in the aggregate, has not had and would not reasonably be expected to have a Material Adverse Effect with respect to such Borrower. Each Borrower and each of its Subsidiaries is in compliance with all laws (including, without limitation, ERISA and Environmental Laws), regulations and orders of any Governmental Authority applicable to it or its property and all indentures, agreements and other instruments binding upon it or its property, except where the failure to do so, individually or in the aggregate, has not had and would not reasonably be expected to have a Material Adverse Effect with respect to such Borrower.

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(d) Governmental Actions. No Governmental Action is or will be required in connection with the execution, delivery or performance by it, or the consummation by it of the transactions contemplated by this Agreement or any other Loan Document to which it is, or is to become, a party other than such Borrower’s Approval, as applicable, which has been duly issued and is in full force and effect.

(e) Execution and Delivery. This Agreement and the other Loan Documents to which it is, or is to become, a party have been or will be (as the case may be) duly executed and delivered by it, and this Agreement is, and upon execution and delivery thereof each other Loan Document will be, the legal, valid and binding obligation of it enforceable against it in accordance with its terms, subject, however, to the application by a court of general principles of equity and to the effect of any applicable bankruptcy, insolvency, reorganization, moratorium or similar laws affecting creditors’ rights generally.

(f) Litigation. Except as disclosed in such Borrower’s Disclosure Documents, there is no pending or, to such Borrower’s knowledge, threatened action or proceeding (including, without limitation, any proceeding relating to or arising out of Environmental Laws) affecting such Borrower or any of its Subsidiaries before any court, governmental agency or arbitrator that would reasonably be expected to have a Material Adverse Effect with respect to such Borrower.

(g) Financial Statements; Material Adverse Change. The consolidated balance sheets of such Borrower and its Subsidiaries, as at December 31, 2010, and the related consolidated statements of income, retained earnings and cash flows of such Borrower and its Subsidiaries, certified by PricewaterhouseCoopers LLP or Deloitte & Touche LLP, as applicable, independent public accountants, and the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows of such Borrower and its Subsidiaries, for the three months then ended, copies of which have been furnished to each Lender, each Swing Line Lender and each Fronting Bank, in all cases as amended and restated to the date hereof, present fairly in all material respects the consolidated financial position of such Borrower and its Subsidiaries as at the indicated dates and the consolidated results of the operations of such Borrower and its Subsidiaries for the periods ended on the indicated dates, all in accordance with GAAP consistently applied (in the case of such statements that are unaudited, subject to year-end adjustments and the exclusion of detailed footnotes). Except as disclosed in such Borrower’s Disclosure Documents, there has been no change, event or occurrence since December 31, 2010 that has had a Material Adverse Effect with respect to such Borrower.

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(h) ERISA. Except as would not reasonably be expected to have a Material Adverse Effect:

(i) No Termination Event has occurred or is reasonably expected to occur with respect to any Plan.

(ii) Schedule B (Actuarial Information) to the most recent annual report (Form 5500 Series) with respect to each Plan, copies of which have been filed with the Internal Revenue Service and furnished (or made available) to the Banks, (A) is complete and accurate, (B) fairly presents the funding status of such Plan, and (C) since the date of such Schedule B there has been no change in such funding status.

(iii) Neither it nor any member of the Controlled Group has incurred or reasonably expects to incur any withdrawal liability under ERISA to any Multiemployer Plan.

(i) Margin Stock. After applying the proceeds of each Extension of Credit, not more than 25% of the value of the assets of such Borrower and its Subsidiaries subject to the restrictions of Section 5.03(a) or (b) will consist of or be represented by Margin Stock. Such Borrower is not engaged in the business of extending credit for the purpose of purchasing or carrying Margin Stock, and no proceeds of any Extension of Credit will be used to purchase or carry any Margin Stock or to extend credit to others for the purpose of purchasing or carrying any Margin Stock.

(j) Investment Company. Such Borrower is not an “investment company” or a company “controlled” by an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

(k) No Event of Default. No event has occurred and is continuing that constitutes an Event of Default or an Unmatured Default in each case with respect to such Borrower.

(l) No Material Misstatements. The reports, financial statements and other written information furnished by or on behalf of such Borrower to the Administrative Agent, any Fronting Bank or any Lender pursuant to or in connection with the Loan Documents and the transactions contemplated thereby, when taken together with such Borrower’s Disclosure Documents, do not contain and will not contain, when taken as a whole, any untrue statement of a material fact and do not omit and will not omit, when taken as a whole, to state any fact necessary to make the statements therein, in the light of the circumstances under which they were or will be made, not misleading in any material respect.

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ARTICLE V
COVENANTS OF THE BORROWERS

SECTION 5.01. Affirmative Covenants of the Borrowers.

Unless the Majority Lenders shall otherwise consent in writing, so long as any amount payable by any Borrower hereunder shall remain unpaid, any Letter of Credit shall remain outstanding or any Lender shall have any Commitment hereunder, such Borrower will:

(a) Preservation of Corporate Existence, Etc. (i) Without limiting the right of such Borrower to merge with or into or consolidate with or into any other corporation or entity in accordance with the provisions of Section 5.03(c) hereof, preserve and maintain its corporate or limited liability company (as the case may be) existence, (ii) qualify and remain qualified as a foreign corporation or limited liability company (as the case may be) in each jurisdiction in which such qualification is reasonably necessary in view of its business and operations or the ownership of its properties and (iii) preserve, renew and keep in full force and effect the rights, privileges and franchises necessary or desirable in the normal conduct of its business, except, in the case of clauses (ii) and (iii) above, to the extent that failure to do so would not reasonably be expected to result in a Material Adverse Effect with respect to such Borrower; provided, however, that any Borrower may change its form of organization from a corporation to a limited liability company or from a limited liability company to a corporation if the Administrative Agent is reasonably satisfied that such change shall not affect any obligations of such Borrower under the Loan Documents.

(b) Compliance with Laws, Etc. Comply, and cause each of its Subsidiaries to comply, in all material respects with all applicable laws, rules, regulations, and orders of any Governmental Authority, the noncompliance with which would not reasonably be expected to result in a Material Adverse Effect with respect to such Borrower, such compliance to include, without limitation, compliance with the Patriot Act, regulations promulgated by the U.S. Treasury Department Office of Foreign Assets Control, Environmental Laws and ERISA and paying before the same become delinquent all material taxes, assessments and governmental charges imposed upon it or upon its property, except to the extent compliance with any of the foregoing is then being contested in good faith by appropriate legal proceedings.

(c) Maintenance of Insurance, Etc. Maintain insurance with responsible and reputable insurance companies or associations or through its own program of self-insurance in such amounts and covering such risks as is usually carried by companies engaged in similar businesses and owning similar properties in the same general areas in which such Borrower operates.

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(d) Inspection Rights. At any reasonable time and from time to time as the Administrative Agent, any Swing Line Lender, any Fronting Bank or any Lender may reasonably request (upon five Business Days’ prior notice delivered to the applicable Borrower and no more than once a year, unless an Event of Default has occurred and is continuing), permit the Administrative Agent, such Fronting Bank or such Lender or any agents or representatives thereof to examine and make copies of and abstracts from the records and books of account of, and visit the properties of, such Borrower and any of its Subsidiaries, and to discuss the affairs, finances and accounts of such Borrower and any of its Subsidiaries with any of their respective officers or directors; provided, however, that (x) such Borrower reserves the right to restrict access to any of its Subsidiaries’ facilities in accordance with reasonably adopted procedures relating to safety and security and (y) neither Borrower nor any of its Subsidiaries shall be required to disclose to the Administrative Agent, any Swingline Lender, any Fronting Bank or any Lender or any agents or representatives thereof any information that is the subject of attorney-client privilege or attorney work-product privilege properly asserted by the applicable Person to prevent the loss of such privilege in connection with such information or that is prevented from disclosure pursuant to a confidentiality agreement with third parties (provided that such Borrower agrees to use commercially reasonable efforts to obtain any required third-party consent to such disclosure, subject to customary nondisclosure restrictions applicable to the Administrative Agent, any Swingline Lender, any Fronting Bank or the Lenders, as applicable). The Administrative Agent, each Swing Line Lender, each Fronting Bank and each Lender agree to use reasonable efforts to ensure that any information concerning such Borrower or any of its Subsidiaries obtained by the Administrative Agent, such Fronting Bank or such Lender pursuant to this subsection (d) or subsection (g) that is not contained in a report or other document filed with the SEC, distributed by such Borrower or FE to its security holders or otherwise generally available to the public, will, to the extent permitted by law and except as may be required by valid subpoena or in the normal course of the Administrative Agent’s, such Swing Line Lender’s, such Fronting Bank’s or such Lender’s business operations be treated confidentially by the Administrative Agent, such Swing Line Lender, such Fronting Bank or such Lender, as the case may be, and will not be distributed or otherwise made available by the Administrative Agent, such Swing Line Lender, such Fronting Bank or such Lender, as the case may be, to any Person, other than the Administrative Agent’s, such Swing Line Lender’s, such Fronting Bank’s or such Lender’s employees, authorized agents or representatives (including, without limitation, attorneys and accountants).

(e) Keeping of Books. Keep, and cause each Subsidiary to keep, proper books of record and account in which entries shall be made of all financial transactions and the assets and business of such Borrower and each of its Subsidiaries in accordance with GAAP.

(f) Maintenance of Properties. Maintain and preserve, and cause each of its Subsidiaries to maintain and preserve, all of its properties (except such properties the failure of which to maintain or preserve would not have, individually or in the aggregate, a Material Adverse Effect with respect to such Borrower) that are used or that are useful in the conduct of its business in good working order and condition, ordinary wear and tear excepted, and in accordance with prudent industry practices applicable to the industry of such Borrower, in all material respects, and (subject to (b) above) applicable law it being understood that this covenant relates only to the good working order and condition of such properties and shall not be construed as a covenant of such Borrower or any of its Subsidiaries not to dispose of such properties by sale, lease, transfer or otherwise.

(g) Reporting Requirements. Furnish, or cause to be furnished, to the Administrative Agent, with sufficient copies for each Lender and each Fronting Bank, the following:

(i) promptly after becoming aware of the occurrence of any Event of Default with respect to such Borrower continuing on the date of such statement, the statement of an Authorized Officer of such Borrower setting forth details of such Event of Default and the action that such Borrower has taken or proposes to take with respect thereto;

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(ii) as soon as available and in any event within 60 days after the close of each of the first three quarters in each fiscal year of such Borrower, consolidated balance sheets of such Borrower and its Subsidiaries as at the end of such quarter and consolidated statements of income of such Borrower and its Subsidiaries for the period commencing at the end of the previous fiscal year and ending with the end of such quarter, fairly presenting in all material respects the financial condition of such Borrower and its Subsidiaries as at such date and the results of operations of such Borrower and its Subsidiaries for such period and setting forth in each case in comparative form the corresponding figures for the corresponding period of the preceding fiscal year, all in reasonable detail and duly certified (subject to year-end audit adjustments) by the chief financial officer, treasurer, assistant treasurer or controller of such Borrower as having been prepared in accordance with GAAP consistently applied (in the case of such statements that are unaudited, subject to year-end adjustments and the exclusion of detailed footnotes);

(iii) as soon as available and in any event within 105 days after the end of each fiscal year of such Borrower, a copy of the annual report for such year for such Borrower and its Subsidiaries, containing consolidated and consolidating financial statements of such Borrower and its Subsidiaries for such year certified by PricewaterhouseCoopers LLP, Deloitte & Touche LLP or other independent public accountants of recognized national standing as fairly presenting, in all material respects, the financial position of such Borrower and its Subsidiaries as at the end of such year and the results of their operations and their cash flows for the three-year period (or, if such Borrower is not then required to file reports with the SEC pursuant to Section 13 or 15(d) of the Exchange Act, the two-year period) ending as at the end of such year in conformity with GAAP;

(iv) concurrently with the delivery of the financial statements specified in clauses (ii) and (iii) above a certificate of the chief financial officer, treasurer, assistant treasurer or controller of such Borrower (A) stating whether such Borrower has any knowledge of the occurrence and continuance at the date of such certificate of any Event of Default not theretofore reported pursuant to the provisions of clause (i) of this subsection (g), and, if so, stating the facts with respect thereto, and (B) setting forth in a true and correct manner, the calculation of the ratio contemplated by Section 5.02 hereof, as of the date of the most recent financial statements accompanying such certificate, to show such Borrower’s compliance with or the status of the financial covenant contained in Section 5.02 hereof;

(v) promptly after the sending or filing thereof, copies of any reports that such Borrower sends to any of its securityholders, and copies of all reports on Form 10-K, Form 10-Q or Form 8-K, if any, that such Borrower or any of its Subsidiaries files with the SEC;

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(vi) as soon as possible and in any event within 20 days after such Borrower or any member of the Controlled Group knows or has reason to know that any Termination Event with respect to any Plan has occurred or is reasonably likely to occur, that would reasonably be expected to result in liability exceeding $100,000,000 to such Borrower or such member of the Controlled Group, a statement of the chief financial officer of such Borrower describing such Termination Event and the action, if any, that such Borrower or such member of the Controlled Group, as the case may be, proposes to take with respect thereto;

(vii) promptly upon reasonable request by the Administrative Agent or any Lender, after the filing thereof with the Internal Revenue Service, copies of each Schedule B (Actuarial Information) to the annual report (Form 5500 Series) with respect to each Plan;

(viii) promptly upon request and in any event within five Business Days after receipt thereof by such Borrower or any member of the Controlled Group from a Multiemployer Plan sponsor, a copy of each notice received by such Borrower or such member of the Controlled Group concerning the imposition of withdrawal liability pursuant to Section 4202 of ERISA;

(ix) promptly and in any event within five Business Days after Moody’s or S&P has changed any relevant Reference Rating, notice of such change; and

(x) such other information respecting the condition or operations, financial or otherwise, of such Borrower or any of its Subsidiaries, including, without limitation, copies of all reports and registration statements that such Borrower or any Subsidiary files with the SEC or any national securities exchange, as the Administrative Agent, any Fronting Bank, any Swing Line Lender or any Lender (through the Administrative Agent) may from time to time reasonably request.

The financial statements and reports described in paragraphs (ii), (iii) and (v) above will be deemed to have been delivered hereunder if publicly available on the SEC’s EDGAR Database or on FE’s website no later than the date specified for delivery of same under paragraph (ii), (iii) or (v), as applicable, above. If any financial statements or report described in (ii) and (iii) above is due on a date that is not a Business Day, then such financial statements or report shall be delivered on the next succeeding Business Day.

(h) Borrower Approvals. Maintain such Borrower’s Approval in full force and effect and comply with all terms and conditions thereof until all amounts outstanding under the Loan Documents shall have been repaid or paid (as the case may be) and the Termination Date has occurred.

SECTION 5.02. Debt to Capitalization Ratio.

Unless the Majority Lenders shall otherwise consent in writing, so long as any amount payable by any Borrower hereunder shall remain unpaid, any Letter of Credit for the account of any Borrower shall remain outstanding or any Lender shall have any Commitment to any Borrower hereunder, such Borrower will maintain a Debt to Capitalization Ratio of no more than 0.65 to 1.00 (determined as of the last day of each fiscal quarter).

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SECTION 5.03. Negative Covenants of the Borrowers.

Unless the Majority Lenders shall otherwise consent in writing, so long as any amount payable by any Borrower hereunder shall remain unpaid, any Letter of Credit for the account of any Borrower shall remain outstanding or any Lender shall have any Commitment to any Borrower hereunder, such Borrower will not:

(a) Sales, Etc. (i) Sell, lease, transfer or otherwise dispose of any shares of common stock of any Significant Subsidiary of such Borrower, whether now owned or hereafter acquired by such Borrower, or permit any Significant Subsidiary of such Borrower to do so, or (ii) sell, lease, transfer or otherwise dispose of (whether in one transaction or a series of transactions) or permit any of its Subsidiaries to sell, lease, transfer or dispose of (whether in one transaction or a series of transactions) assets located in The United States of America (other than any assets that are purported to be conveyed in connection with a Permitted Securitization but including assets purported to be conveyed pursuant to any sale leaseback transaction) having an aggregate book value (determined as of the date of such transaction for all such transactions since the date hereof) that is greater than 20% of the book value of all of the consolidated fixed assets of such Borrower, as reported on the most recent consolidated balance sheet of such Borrower prior to the date of such sale, lease transfer or disposition to any entity other than such Borrower or any of its wholly owned direct or indirect Subsidiaries; provided, however, that this provision shall not in any way restrict, and shall not apply to, (A) the disposition of any Borrower’s direct or indirect interests in (1) the approximately 700 megawatt Fremont Energy Center in Fremont, Ohio, (2) Signal Peak Energy, LLC, (3) the 42 megawatt Richland Peaking Facility in Defiance, Ohio, or (4) the 18 megawatt Stryker Peaking Facility in Springfield, Ohio or (B) the sale, lease, transfer or other disposition of a Borrower’s assets to another Borrower, a Subsidiary of another Borrower or a newly-formed Person to which all or substantially all of the assets and liabilities of such Borrowers or their Subsidiaries are being transferred, in each case, pursuant to a transaction permitted under subsection (c) below.

(b) Liens, Etc. Create or suffer to exist, or permit any Significant Subsidiary of such Borrower (other than FES, AESC and their respective Subsidiaries) to create or suffer to exist, any Lien upon or with respect to any of its properties (including, without limitation, any shares of any class of equity security of any Significant Subsidiary of such Borrower (other than FES, AESC and their respective Subsidiaries)), in each case to secure or provide for the payment of Indebtedness, other than (i) liens consisting of (A) pledges or deposits in the ordinary course of business to secure obligations under worker’s compensation laws or similar legislation, (B) deposits in the ordinary course of business to secure, or in lieu of, surety, appeal, or customs bonds to which such Borrower or Significant Subsidiary is a party, (C) pledges or deposits in the ordinary course of business to secure performance in connection with bids, tenders or contracts (other than contracts for the payment of money), or (D) materialmen’s, mechanics’, carriers’, workers’, repairmen’s or other like Liens incurred in the ordinary course of business for sums not yet due or currently being contested in good faith by appropriate proceedings diligently conducted, or deposits to obtain in the release of such Liens; (ii) purchase money liens or purchase money security interests upon or in any property acquired or held by such Borrower or Significant Subsidiary in the ordinary course of business, which secure the purchase price of such property or secure indebtedness incurred solely for the purpose of financing the acquisition of such property; (iii) Liens existing on property acquired by such

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Borrower or Significant Subsidiary or on the property of any Person at the time that such Person becomes a direct or indirect Significant Subsidiary of such Borrower or Significant Subsidiary or is merged into or consolidated with such Borrower or Significant Subsidiary; provided, in each case, that such Liens were not created to secure the acquisition of such Person; (iv) Liens in existence on the date of this Agreement; (v) Liens created by any First Mortgage Indenture, so long as under the terms thereof no “event of default” (howsoever designated) in respect of any bonds issued thereunder will be triggered by reference to an Event of Default or Unmatured Default; (vi) Liens securing Attributable Securitization Obligations on the assets purported to be sold in connection with the applicable Permitted Securitization; (vii) Liens securing Nonrecourse Indebtedness; (viii) Liens on cash or cash equivalents deposited on behalf of or pledged to counterparties with respect to Permitted Obligations of such Borrower or any of its Significant Subsidiaries; (ix) Liens on cash or cash equivalents to defease Indebtedness of such Borrower or any of its Subsidiaries; (x) Liens on cash or cash equivalents constituting proceeds from a disposition of assets otherwise not prohibited under subsection (a) above, which proceeds are deposited in escrow accounts for indemnification, adjustment of purchase price or similar obligations to the purchaser of such assets; (xi) Liens securing obligations in respect of pollution control or industrial revenue bonds or nuclear fuel leases, provided that such Liens extend to only the equipment, project, nuclear fuel or other assets financed with the proceeds of such financing; (xii) Liens arising in connection with leases that shall have been or should be, in accordance with GAAP, recorded as capital leases in respect of which such Borrower or Significant Subsidiary is liable as lessee; provided, that no such Lien shall extend to or cover any assets of such Borrower or Significant Subsidiary other than the assets of such Borrower or Significant Subsidiary subject to such lease and proceeds thereof; and (xiii) Liens created for the sole purpose of refinancing, extending, renewing or replacing in whole or in part Indebtedness secured by any Lien referred to in the foregoing clauses (i) through (xii); provided, however, that the principal amount of Indebtedness (or, if greater, the aggregate lending commitment) secured thereby shall not exceed the principal amount of Indebtedness (or, if greater, the aggregate lending commitment) so secured at the time of such refinancing, extension, renewal or replacement, and that such refinancing, extension, renewal or replacement, as the case may be, shall be limited to all or a part of the property or Indebtedness that secured the Lien so extended, renewed or replaced (and any improvements on such property).

(c) Mergers, Etc. Merge with or into or consolidate with or into any other Person, or permit any of its Subsidiaries to do so unless (i) immediately after giving effect thereto, no event shall occur and be continuing that constitutes an Event of Default, (ii) the consolidation or merger shall not materially and adversely affect the ability of such Borrower (or its successor by merger or consolidation as contemplated by clause (i) of this subsection (c)) to perform its obligations hereunder or under any other Loan Document, and (iii) in the case of any merger or consolidation to which such Borrower is a party, the Person formed by such consolidation or into which such Borrower shall be merged shall assume such Borrower’s obligations under this Agreement and the other Loan Documents to which it is a party in a writing reasonably satisfactory in form and substance to the Administrative Agent. Without limiting the foregoing, (A) any Borrower may merge with or into or consolidate with or into (x) another Borrower or into a newly-formed Person into which one or more Borrowers are being merged or consolidated (which Person will become a Borrower hereunder and a wholly-owned Subsidiary of FE) or (y) a wholly-owned Subsidiary of another Borrower (in which case only such

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other Borrower will continue as a Borrower hereunder), and (B) any Borrower may transfer all or substantially all of its assets and liabilities to another Borrower, to a wholly-owned Subsidiary of another Borrower (in which case only such other Borrower will continue as a Borrower hereunder) or to a newly-formed Person to which all or substantially all of the assets and liabilities of one or more Borrowers are being transferred (which Person will become a Borrower hereunder and a wholly-owned Subsidiary of FE), in each case of clauses (A) and (B), if (1) the surviving Person, transferee or Person otherwise specified above to become a Borrower hereunder, as applicable, assumes such Borrower’s or Borrowers’, as applicable, obligations under this Agreement and the other Loan Documents pursuant to an instrument in form and substance reasonably satisfactory to the Administrative Agent, (2) the Reference Ratings of the surviving or resulting Borrower are not, after giving effect to such transactions, any lower than the Reference Ratings of each Borrower that was a party to such transactions immediately prior to the consummation of such transactions, unless the Reference Ratings of such surviving or resulting Borrower are at least BBB- and Baa3, and (3) the parties to such transaction deliver to the Administrative Agent certified copies of all corporate or limited liability, equity holder and Governmental Authority approvals required in connection with such transactions and legal opinions of counsel to such parties relating to such transactions and the assumption agreement described in clause (1) above. For the avoidance of doubt, nothing in this Section 5.03(c) shall restrict any (i) merger or consolidation of FES, AESC or any of their respective Subsidiaries with or into any Person or (ii) transfer of all or substantially all of the assets and liabilities of FES, AESC or any of their respective Subsidiaries to any Person, in each case, to the extent such merger, consolidation or transfer is permitted under the FES/AESC Credit Agreement.

(d) Compliance with ERISA. (i) Enter into any nonexempt “prohibited transaction” (within the meaning of Section 4975 of the Code or Section 406 of ERISA) involving any Plan that may result in any liability of such Borrower to any Person that (in the opinion of the Majority Lenders and the Fronting Banks) would reasonably be expected to have a Material Adverse Effect with respect to any Borrower or (ii) allow or suffer to exist any other event or condition known to such Borrower that results in any liability of such Borrower to the PBGC that would reasonably be expected to have a Material Adverse Effect with respect to any Borrower. For purposes of this subsection (d), “liability” shall not include termination insurance premiums payable under Section 4007 of ERISA.

(e) Use of Proceeds. Use the proceeds of any Extension of Credit for any purpose other than (ii) refinancing the Existing Facilities to which such Borrower is a party and (ii) working capital and other general corporate purposes of such Borrower and its Subsidiaries; provided, however, that such Borrower may not use such proceeds in connection with any Hostile Acquisition.

(f) Limitation on Cross-Default Provisions. Incur or permit any Significant Subsidiary (other than FES, AESC and their respective Subsidiaries) to incur (which for purposes of this subsection (f), shall not include the drawdown of any revolving credit facility or any letter of credit facility in existence on the date hereof or any other incurrence of Indebtedness or other obligation under agreements in existence on the date hereof pursuant to the terms thereof as in effect on the date hereof) after the date hereof any Indebtedness, Commodity Trading Obligations or Hedging Obligations that shall or may become subject to acceleration, redemption or mandatory purchase prior to the stated maturity date of such Indebtedness or the stated or otherwise applicable date for performance

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of such Commodity Trading Obligations or Hedging Obligations, as the case may be, upon the occurrence of one or more events of default or credit event or similar events (howsoever designated) under any document or instrument evidencing any other such Indebtedness, Commodity Trading Obligations or Hedging Obligations (any such provision to the effect of the foregoing being a “Cross-Default Provision”) of FES, AESC or any of their respective Subsidiaries; provided however, that, during the six-month period following the date hereof, each Borrower and its Subsidiaries may incur Commodity Trading Obligations and Hedging Obligations pursuant to any ISDA Master Agreement and related schedule that contains such a Cross-Default Provision if and to the extent that such ISDA Master Agreement and related schedule contained such Cross-Default Provision on the date hereof.

ARTICLE VI
EVENTS OF DEFAULT

SECTION 6.01. Events of Default.

If any of the following events shall occur and be continuing with respect to any Borrower (as to such Borrower, an “Event of Default”):

(a) (i) Any principal of any Advance or any Reimbursement Obligation shall not be paid by such Borrower when the same becomes due and payable, or (ii) any interest on any Advance or any fees or other amounts payable hereunder shall not be paid by such Borrower within three Business Days after the same becomes due and payable; or

(b) Any representation or warranty made by such Borrower (or any of its officers) in any Loan Document or in connection with any Loan Document shall prove to have been incorrect or misleading in any material respect when made; or

(c) (i) Such Borrower shall fail to perform or observe any covenant set forth in Section 5.02 or Section 5.03 on its part to be performed or observed, or (ii) such Borrower shall fail to perform or observe any other term, covenant or agreement (other than those covenants otherwise covered in clause (a) or (c)(i) of this Section 6.01) contained in this Agreement or any other Loan Document on its part to be performed or observed and such failure shall remain unremedied for 30 days after written notice thereof shall have been given to such Borrower by the Administrative Agent or any Lender; or

(d) Any material provision of this Agreement or any other Loan Document shall at any time and for any reason cease to be valid and binding upon such Borrower, except pursuant to the terms thereof, or shall be declared to be null and void, or the validity or enforceability thereof shall be contested in any manner by such Borrower or any Governmental Authority, or such Borrower shall deny in any manner that it has any or further liability or obligation under this Agreement or any other Loan Document; or

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(e) Such Borrower or any Significant Subsidiary of such Borrower (other than FES, AESC and their respective Subsidiaries) shall fail to pay any principal of or premium or interest on any Indebtedness (other than Indebtedness of such Borrower under this Agreement, but including, with respect to FE, Indebtedness of its Significant Subsidiaries under this Agreement) that is outstanding in a principal amount in excess of $100,000,000 in the aggregate when the same becomes due and payable (whether by scheduled maturity, required prepayment, acceleration, demand or otherwise), and such failure shall continue after the applicable grace period, if any, specified in the agreement or instrument relating to such Indebtedness; or any other event shall occur or condition shall exist under any agreement or instrument relating to any such Indebtedness and shall continue after the applicable grace period, if any, specified in such agreement or instrument, if the effect of such event or condition is to accelerate, or to permit the acceleration of, the maturity of such Indebtedness; or any such Indebtedness shall be declared to be due and payable, or required to be prepaid (other than by a regularly scheduled required prepayment), prior to the stated maturity thereof; or

(f) Such Borrower or any Significant Subsidiary of such Borrower (other than FES, AESC and their respective Subsidiaries) shall generally not pay its debts as such debts become due, or shall admit in writing its inability to pay its debts generally, or shall make a general assignment for the benefit of creditors; or any proceeding shall be instituted by or against any Borrower or any Significant Subsidiary of such Borrower (other than FES, AESC and their respective Subsidiaries) seeking to adjudicate it a bankrupt or insolvent, or seeking liquidation, winding up, reorganization, arrangement, adjustment, protection, relief, or composition or arrangement with creditors, a readjustment of its debts, in each case under any law relating to bankruptcy, insolvency or reorganization or relief of debtors, or seeking the entry of an order for relief or the appointment of a receiver, trustee, custodian or other similar official for it or for any substantial part of its property and, in the case of any such proceeding instituted against it (but not instituted or acquiesced in by it), either such proceeding shall remain undismissed or unstayed for a period of 60 consecutive days, or any of the actions sought in such proceeding (including, without limitation, the entry of an order for relief against, or the appointment of a receiver, trustee, custodian or other similar official for, it or for any substantial part of its property) shall occur; or any Borrower or any Significant Subsidiary of such Borrower (other than FES, AESC and their respective Subsidiaries) shall take any corporate action to authorize or to consent to any of the actions set forth above in this subsection (f); or

(g) Any judgment or order for the payment of money exceeding any applicable insurance coverage by more than $100,000,000 shall be rendered by a court of final adjudication against such Borrower or any Significant Subsidiary of such Borrower and either (i) valid enforcement proceedings shall have been commenced by any creditor upon such judgment or order or (ii) there shall be any period of 30 consecutive days during which a stay of enforcement of such judgment or order, by reason of a pending appeal or otherwise, shall not be in effect; or

(h) Any Termination Event with respect to a Plan or a Multiemployer Plan shall have occurred, and, 30 days after notice thereof shall have been given to such Borrower by the Administrative Agent or any Lender, such Termination Event (if correctable) shall not have been corrected, and either (1) the actual liability in respect of such Termination Event to such Borrower would reasonably be expected to exceed $100,000,000, or (2) such Borrower or any member of the Controlled Group as employer under a Multiemployer Plan shall have made a complete or partial withdrawal from such Multiemployer Plan and, as a result thereof, such Borrower would reasonably be expected to incur withdrawal liability in an amount exceeding $100,000,000; or

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(i) (i) FE shall fail to own directly or indirectly 100% of the issued and outstanding shares of common stock of each Significant Subsidiary (with any such failure constituting an Event of Default with respect to FE and any such Significant Subsidiary that is also a Borrower), (ii) any Person or two or more Persons acting in concert shall have acquired beneficial ownership (within the meaning of Rule 13d-3 of the Securities and Exchange Commission under the Securities Exchange Act of 1934, as amended), directly or indirectly, of securities of FE (or other securities convertible into such securities) representing 30% or more of the combined voting power of all securities of FE entitled to vote in the election of directors; or (iii) commencing after the date of this Agreement, individuals who as of the date of this Agreement were directors shall have ceased for any reason to constitute a majority of the Board of Directors of FE unless the Persons replacing such individuals were nominated by the stockholders or the Board of Directors of FE in accordance with FE’s Organizational Documents (each a “Change of Control”);

then, and in any such event, the Administrative Agent shall at the request, or may with the consent, of the Majority Lenders, (i) by notice to the defaulting Borrower, declare the obligation of each Lender to make Advances to such Borrower, the obligation of the Fronting Banks to issue Letters of Credit for the account of such Borrower and the obligation of the Swing Line Lenders to make Swing Line Advances to such Borrower, to be terminated, whereupon the same shall forthwith terminate, and (ii) by notice to such Borrower, declare the Advances made to such Borrower, an amount equal to the aggregate Stated Amount of all issued but undrawn Letters of Credit issued for the account of such Borrower, (such amount being the “Letter of Credit Cash Cover”) and all other amounts payable under this Agreement and the other Loan Documents by such Borrower to be forthwith due and payable, whereupon such Advances and all such amounts shall become and be forthwith due and payable, without presentment, demand, protest or further notice of any kind, all of which are hereby expressly waived by such Borrower; provided, however, that in the event of an actual or deemed entry of an order for relief with respect to any Borrower or any Significant Subsidiary of such Borrower under the Bankruptcy Code, (A) the obligation of each Lender to make Advances to such Borrower, the obligation of the Fronting Banks to issue Letters of Credit for the account of such Borrower, and the obligation of the Swing Line Lenders to make Swing Line Advances to such Borrower shall automatically be terminated and (B) all Advances made to such Borrower, the Letter of Credit Cash Cover with respect to such Borrower and all other amounts payable under this Agreement by such Borrower shall automatically become and be due and payable, without presentment, demand, protest or any notice of any kind, all of which are hereby expressly waived by such Borrower. In the event that any Borrower is required to pay the Letter of Credit Cash Cover pursuant to this Section, such payment shall be made in immediately available funds to the Administrative Agent, which shall hold such funds as collateral pursuant to arrangements reasonably satisfactory to the Administrative Agent and the Fronting Banks to secure Reimbursement Obligations in respect of Letters of Credit then outstanding, for the benefit of the Lenders and the Fronting Banks.

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ARTICLE VII
THE ADMINISTRATIVE AGENT

SECTION 7.01. Authorization and Action.

Each Lender, each Fronting Bank and each Swing Line Lender hereby appoints and authorizes the Administrative Agent to take such action as agent on its behalf and to exercise such powers under this Agreement as are delegated to the Administrative Agent by the terms hereof, together with such powers as are reasonably incidental thereto. As to any matters not expressly provided for by this Agreement the Administrative Agent shall not be required to exercise any discretion or take any action, but shall be required to act or to refrain from acting (and shall be fully protected in so acting or refraining from acting) upon the instructions of the Majority Lenders, and such instructions shall be binding upon all Lenders and all Fronting Banks; provided, however, that the Administrative Agent shall not be required to take any action that exposes the Administrative Agent to personal liability or that is contrary to this Agreement or applicable law. The Administrative Agent agrees to give to each Lender and each Fronting Bank prompt notice of each notice given to it by the Borrowers pursuant to the terms of this Agreement and to promptly forward to each Lender, each Fronting Bank and each Swing Line Lender the financial statements and any other certificates or statements delivered to the Administrative Agent pursuant to Section 5.01(g).

SECTION 7.02. Administrative Agent’s Reliance, Etc.

Neither the Administrative Agent nor any of its directors, officers, agents or employees shall be liable to any Lender, any Fronting Bank, any Swing Line Lender or the Borrowers for any action taken or omitted to be taken by it or them under or in connection with this Agreement, except for its or their own gross negligence or willful misconduct. Without limitation of the generality of the foregoing, the Administrative Agent: (i) may treat each Lender listed in the Register as a “Lender” with a Commitment in the amount recorded in the Register until the Administrative Agent receives and accepts an Assignment and Assumption entered into by a Lender listed in the Register, as assignor, and the applicable assignee, as provided in Section 8.08, at which time the Administrative Agent will make such recordations in the Register as are appropriate to reflect the assignment effected by such Assignment and Assumption; (ii) may consult with legal counsel (including counsel for the Borrowers), independent public accountants and other experts selected by it and shall not be liable for any action taken or omitted to be taken in good faith by it in accordance with the advice of such counsel, accountants or experts; (iii) makes no warranty or representation to any Lender, any Fronting Bank or any Swing Line Lender and shall not be responsible to any Lender, any Fronting Bank or any Swing Line Lender for any statements, warranties or representations (whether written or oral) made in or in connection with the Loan Documents; (iv) shall not have any duty to ascertain or to inquire as to the performance or observance of any of the terms, covenants or conditions of the Loan Documents on the part of the Borrowers or to inspect the property (including the books and records) of the Borrowers, and, without limiting the foregoing, shall be deemed not to have knowledge of any Default or Event of Default unless and until written notice is given by a Lender or a Borrower to the Administrative Agent in accordance with the terms of this Agreement; (v) shall not be responsible to any Lender, any Fronting Bank or any Swing Line Lender for the due execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any other instrument or document furnished pursuant thereto; and (vi) shall incur no liability under or in respect of this Agreement by acting upon any notice, consent, certificate or other instrument or writing (which may be by telecopier, telegram or cable) believed by it in good faith to be genuine and signed or sent by the proper party or parties.

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SECTION 7.03. RBS and the Fronting Banks and Swing Line Lenders.

With respect to its Commitment, the Advances made by it and any Note issued to it, each of RBS and each Lender that is also a Fronting Bank or a Swing Line Lender shall have the same rights and powers under this Agreement as any other Lender and may exercise the same as though it were not the Administrative Agent, a Fronting Bank or a Swing Line Lender (as the case may be); and the term “Lender” or “Lenders” shall, unless otherwise expressly indicated, include each of RBS and each Lender that is also a Fronting Bank as a Swing Line Lender in its individual capacity. Each of RBS and each Lender that is also a Fronting Bank as a Swing Line Lender and its Affiliates may accept deposits from, lend money to, act as trustee under indentures of, and generally engage in any kind of business with, each Borrower, any of its respective Subsidiaries and any Person who may do business with or own securities of such Borrower or any such Subsidiary, all as if RBS or such Lender were not the Administrative Agent, a Fronting Bank or a Swing Line Lender (as the case may be) and without any duty to account therefor to the Lenders or any other Fronting Bank or Swing Line Lender.

SECTION 7.04. Lender Credit Decision; No Other Duties.

Each Lender acknowledges that it has, independently and without reliance upon the Administrative Agent, the Fronting Banks, the Swing Line Lenders or any other Lender (or any such Person or any Affiliate thereof acting in the capacity of “Joint Lead Arranger”, “Syndication Agent” or “Documentation Agent”) and based on the financial statements referred to in Section 4.01(g) and such other documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Agreement. Each Lender also acknowledges that it will, independently and without reliance upon the Administrative Agent, the Fronting Banks, the Swing Line Lenders or any other Lender (or any such Person or any Affiliate thereof acting in the capacity of “Joint Lead Arranger”, “Syndication Agent” or “Documentation Agent”) and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under this Agreement.

Anything herein to the contrary notwithstanding, none of the Persons listed on the cover page hereof as a “Joint Lead Arranger”, “Documentation Agent” or “Syndication Agent” shall have any powers, duties or responsibilities under this Agreement or any of the other Loan Documents, except in its capacity, as applicable, as the Administrative Agent, a Fronting Bank, a Swing Line Lender, or a Lender hereunder.

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SECTION 7.05. Indemnification.

The Lenders agree to indemnify the Administrative Agent (to the extent not reimbursed by the Borrowers), ratably according to the amounts of their respective Commitments, from and against any and all liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements of any kind or nature whatsoever that may be imposed on, incurred by, or asserted against the Administrative Agent in any way relating to or arising out of this Agreement or any action taken or omitted by the Administrative Agent (in its capacity as such) under this Agreement; provided that no Lender shall be liable for any portion of such liabilities, obligations, losses, damages, penalties, actions, judgments, suits, costs, expenses or disbursements resulting from the Administrative Agent’s gross negligence or willful misconduct. Without limitation of the foregoing, each Lender agrees to reimburse the Administrative Agent promptly upon demand for its ratable share of any out-of-pocket expenses (including reasonable counsel fees) incurred by the Administrative Agent in connection with the preparation, execution, delivery, administration, modification, amendment or enforcement (whether through negotiations, legal proceedings or otherwise) of, or legal advice in respect of rights or responsibilities under, this Agreement, to the extent that such expenses are reimbursable by the Borrowers but for which the Administrative Agent is not reimbursed by the Borrowers.

SECTION 7.06. Successor Administrative Agent.

The Administrative Agent may resign at any time by giving written notice thereof to the Lenders, the Fronting Banks, the Borrowers and the Swing Line Lenders and may be removed at any time with or without cause by the Majority Lenders, the Fronting Banks and the Swing Line Lenders. Upon any such resignation or removal, the Majority Lenders, the Fronting Banks and the Swing Line Lenders shall have the right, with the prior written consent of the Borrowers (unless an Event of Default has occurred and is continuing), which consent shall not be unreasonably withheld or delayed, to appoint a successor Administrative Agent. If no successor Administrative Agent shall have been so appointed by the Majority Lenders, the Fronting Banks and the Swing Line Lenders, and shall have accepted such appointment, within 30 days after the retiring Administrative Agent’s giving of notice of resignation or the Majority Lenders’, the Fronting Banks’ and the Swing Line Lenders’ removal of the retiring Administrative Agent, then the retiring Administrative Agent may, on behalf of the Lenders, the Fronting Banks and the Swing Line Lenders, appoint a successor Administrative Agent, which shall be a Lender or an Affiliate of a Lender and (i) a commercial bank organized under the laws of the United States, or any State thereof or (ii) a commercial bank organized under the laws of any other country that is a member of the OECD or has concluded special lending arrangements with the International Monetary Fund associated with its “General Arrangements to Borrow”, or a political subdivision of any such country, provided that such bank is acting through a branch or agency located in the United States and shall have a combined capital and surplus of at least $250,000,000. Upon the acceptance of any appointment as Administrative Agent hereunder by a successor Administrative Agent, such successor Administrative Agent shall thereupon succeed to and become vested with all the rights, powers, privileges and duties of the retiring Administrative Agent, and the retiring Administrative Agent shall be discharged from its duties and obligations under this Agreement. After any retiring Administrative Agent’s resignation or removal hereunder as Administrative Agent, the provisions of this Article VII shall inure to its benefit as to any actions taken or omitted to be taken by it while it was Administrative Agent under this Agreement. Notwithstanding the foregoing, if no Event of Default or Unmatured Default shall have occurred and be continuing, then no successor Administrative Agent shall be appointed under this Section 7.06 without the prior written consent of the Borrowers, which consent shall not be unreasonably withheld or delayed.

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SECTION 7.07. Delegation of Duties.

The Administrative Agent may perform any and all of its duties and exercise its rights and powers hereunder by or through any one or more sub-agents appointed by the Administrative Agent; provided that, the appointment of a sub-agent that is not an Affiliate of the Administrative Agent shall be subject to the prior consent of the Borrowers (unless an Event of Default has occurred and is continuing), which consent shall not be unreasonably withheld or delayed. The Administrative Agent and any such sub-agent may perform any and all of its duties and exercise its rights and powers by or through their respective Related Parties. Each such sub-agent and the Related Parties of the Administrative Agent shall be entitled to the benefits of all provisions of this Article VII and Section 8.05, as though such sub-agents were the “Administrative Agent”, as if set forth in full herein with respect thereto.

ARTICLE VIII
MISCELLANEOUS

SECTION 8.01. Amendments, Etc.

No amendment or waiver of any provision of this Agreement or any Note, nor consent to any departure by any Borrower therefrom, shall in any event be effective unless the same shall be in writing and signed by the Majority Lenders, and then such waiver or consent shall be effective only in the specific instance and for the specific purpose for which given; provided, however, that no amendment, waiver or consent shall, unless in writing and signed by all the Lenders affected thereby (other than, in the case of clause (a), (e) or (f) below, any Defaulting Lender), do any of the following: (a) waive any of the conditions specified in Section 3.01 or 3.02 increase the Commitments of the Lenders or subject the Lenders to any additional obligations, (b) change any provision hereof in a manner that would alter the pro rata sharing of payments or the pro rata reduction of Commitments among the Lenders, (c) reduce the principal of, or interest (or rate of interest) on, the Advances or any fees or other amounts payable hereunder, (d) postpone any date fixed for any payment of principal of, or interest on, the Advances or any fees or other amounts payable hereunder, (e) change the percentage of the Commitments or of the aggregate unpaid principal amount of the Advances, the aggregate undrawn amount of outstanding Letters of Credit or the number of Lenders, that shall be required for the Lenders or any of them to take any action hereunder or (f) amend this Section 8.01 or the definition of “Majority Lenders”; and provided, further, that (i) no amendment, waiver or consent shall, unless in writing and signed by the Administrative Agent in addition to the Lenders required above to take such action, affect the rights or duties of the Administrative Agent under this Agreement or Section 2.21; (ii) that no amendment, waiver or consent that would adversely affect the rights of, or increase the obligations of, any Fronting Bank, or that would alter any provision hereof relating to or affecting Letters of Credit issued by such Fronting Bank or modify or waive Section 2.21, shall be effective unless agreed to in writing by such Fronting Bank or modify or waive Section 2.21; (iii) no amendment, waiver or consent that would adversely affect the rights of, or increase the obligations of, any Swing Line Lender, or that would alter provisions hereof relating to or affecting Swing Line Advances made by such Swing Line Lender or modify or waive Section 2.21, shall be effective unless agreed to in writing by such Swing Line Lender; and (iv) this Agreement may be amended and restated without the consent of any Lender, any Fronting Bank, any Swing Line Lender or the Administrative Agent if, upon giving effect to such amendment and restatement, such Lender, such Fronting Bank, such Swing Line Lender or the Administrative Agent, as the case may be, shall no longer be a party to this Agreement (as so amended and restated) or have any Commitment or other obligation hereunder (including, without limitation, any obligation to make payment on account of a Drawing) and shall have been paid in full all amounts payable hereunder to such Lender, such Fronting Bank, such Swing Line Lender or the Administrative Agent, as the case may be.

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SECTION 8.02. Notices, Etc.

Unless specifically provided otherwise in this Agreement, all notices and other communications provided for hereunder shall be in writing (including telecopier) and delivered by hand or overnight courier service, mailed or sent by telecopy, if to any Borrower, to it in care of FE at its address at 76 South Main Street, Akron, Ohio 44308, Attention: Treasurer, Telecopy: (330) 384-3772; if to any Bank (including any Swing Line Lender), at its Domestic Lending Office specified opposite its name on Schedule I hereto; if to any other Lender (including any Swing Line Lender), at its Domestic Lending Office specified in the Assignment and Assumption pursuant to which it became a Lender; if to the Administrative Agent, at its address at, The Royal Bank of Scotland plc, 600 Washington Boulevard, Stamford, Connecticut 06901, Attention: John Ferrante / Juan Zuniga, Telecopy: (203) 873-5300 / (212) 401-1494; if to any Fronting Bank identified on Schedule II hereto, at the address specified opposite its name on Schedule II hereto; if to any other Fronting Bank, at such address as shall be designated by such Fronting Bank in a written notice to the other parties; or, as to each party, at such other address as shall be designated by such party in a written notice to the other parties. Subject to the other notice requirements of this Agreement, all notices and communications given to any party hereto in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt if delivered by hand or overnight courier service, mailed or sent by telecopy to such party and received during the normal business hours of such party as provided in this Section or in accordance with the latest unrevoked direction from such party given in accordance with this Section. If such notices and communications are received after the normal business hours of such party, receipt shall be deemed to have been given upon the opening of the recipient’s next Business Day.

SECTION 8.03. Electronic Communications.

(a) Each Borrower hereby agrees that it will provide to the Administrative Agent all information, documents and other materials that it is obligated to furnish to the Administrative Agent pursuant to the Loan Documents, including, without limitation, all notices, requests, financial statements, financial and other reports, certificates and other information materials, but excluding any such communication that (i) relates to a request for a new, or a conversion of an existing, Borrowing or other Extension of Credit (including any election of an interest rate or Interest Period relating thereto), (ii) relates to the payment of any principal or other amount due under the Credit Agreement prior to the scheduled date therefor, (iii) provides notice of any Unmatured Default or Event of Default under the Credit Agreement or (iv) is required to be delivered to satisfy any condition precedent to the effectiveness of the Credit Agreement and/or any Borrowing or other Extension of Credit thereunder (all such non-excluded communications being referred to herein collectively as “Communications”), by transmitting the Communications in an electronic/soft medium in a format acceptable to the Administrative Agent to gbmnaagency@rbs.com or faxing the Communications to (203) 873-5300 / (212) 401-1494. In addition, each Borrower agrees to continue to provide the Communications to the Administrative Agent in the manner otherwise specified in this Agreement, but only to the extent requested by the Administrative Agent.

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(b) Each Borrower further agrees that the Administrative Agent may make the Communications available to the Lenders by posting the Communications on Intralinks or a substantially similar electronic transmission systems (the “Platform”). Each Borrower acknowledges that the distribution of material through an electronic medium is not necessarily secure and that there are confidentiality and other risks associated with such distribution.

(c) THE PLATFORM IS PROVIDED “AS IS” AND “AS AVAILABLE”. THE AGENT PARTIES (AS DEFINED BELOW) DO NOT WARRANT THE ACCURACY OR COMPLETENESS OF THE COMMUNICATIONS, OR THE ADEQUACY OF THE PLATFORM AND EXPRESSLY DISCLAIM LIABILITY FOR ERRORS OR OMISSIONS IN THE COMMUNICATIONS. NO WARRANTY OF ANY KIND, EXPRESS, IMPLIED OR STATUTORY, INCLUDING, WITHOUT LIMITATION, ANY WARRANTY OF MERCHANTABILITY, FITNESS FOR A PARTICULAR PURPOSE, NON-INFRINGEMENT OF THIRD PARTY RIGHTS OR FREEDOM FROM VIRUSES OR OTHER CODE DEFECTS, IS MADE BY THE AGENT PARTIES IN CONNECTION WITH THE COMMUNICATIONS OR THE PLATFORM. IN NO EVENT SHALL THE ADMINISTRATIVE AGENT OR ANY OF ITS AFFILIATES OR ANY OF THEIR RESPECTIVE OFFICERS, DIRECTORS, EMPLOYEES, AGENTS, ADVISORS OR REPRESENTATIVES (COLLECTIVELY, “AGENT PARTIES”) HAVE ANY LIABILITY TO ANY BORROWER, ANY LENDER OR ANY OTHER PERSON OR ENTITY FOR DAMAGES OF ANY KIND, INCLUDING, WITHOUT LIMITATION, DIRECT OR INDIRECT, SPECIAL, INCIDENTAL OR CONSEQUENTIAL DAMAGES, LOSSES OR EXPENSES (WHETHER IN TORT, CONTRACT OR OTHERWISE) ARISING OUT OF ANY BORROWER’S OR THE ADMINISTRATIVE AGENT’S TRANSMISSION OF THE COMMUNICATIONS THROUGH THE PLATFORM, EXCEPT TO THE EXTENT THE LIABILITY OF ANY AGENT PARTY IS FOUND IN A FINAL NON-APPEALABLE JUDGMENT BY A COURT OF COMPETENT JURISDICTION TO HAVE RESULTED PRIMARILY FROM SUCH AGENT PARTY’S GROSS NEGLIGENCE OR WILLFUL MISCONDUCT.

(d) The Administrative Agent agrees that the receipt of the Communications by the Administrative Agent at its e-mail address set forth above shall constitute effective delivery of the Communications to the Administrative Agent for purposes of the Loan Documents. Each Lender agrees that notice to it (as provided in the next sentence) specifying that the Communications have been posted to the Platform shall constitute effective delivery of the Communications to such Lender for purposes of the Loan Documents. Each Lender agrees to notify the Administrative Agent in writing (including by electronic communication) from time to time of such Lender’s e-mail address to which the foregoing notice may be sent by electronic transmission and that the foregoing notice may be sent to such e-mail address. Subject to the other notice requirements of this Agreement, all such notices and Communications given to the Administrative Agent or such Lender in accordance with the provisions of this Agreement shall be deemed to have been given on the date of receipt if delivered by electronic/soft medium to such party and received during the normal business hours of such party as provided in this Section or in accordance with the latest unrevoked direction from such party given in accordance with this Section. If such notices and communications are received after the normal business hours of such party, receipt shall be deemed to have been given upon the opening of the recipient’s next Business Day.

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(e) Nothing herein shall prejudice the right of the Administrative Agent or any Lender to give any notice or other communication pursuant to any Loan Document in any other manner specified in such Loan Document.

SECTION 8.04. No Waiver; Remedies.

No failure on the part of any Lender, any Fronting Bank, any Swing Line Lender or the Administrative Agent to exercise, and no delay in exercising, any right hereunder or under any Note shall operate as a waiver thereof; nor shall any single or partial exercise of any such right preclude any other or further exercise thereof or the exercise of any other right. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

SECTION 8.05. Costs and Expenses; Indemnification.

(a) Each Borrower agrees to pay on demand all reasonable out-of-pocket costs and expenses incurred by the Administrative Agent, each Fronting Bank and each Swing Line Lender in connection with the preparation, execution, delivery, syndication administration, modification and amendment of this Agreement, any Note, any Letter of Credit and the other documents to be delivered hereunder, including, without limitation, the reasonable fees and out-of-pocket expenses of counsel for the Administrative Agent, the Fronting Banks and the Swing Line Lenders with respect thereto and with respect to advising the Administrative Agent, the Fronting Banks and each Swing Line Lender as to their rights and responsibilities under this Agreement. Each Borrower further agrees to pay on demand all reasonable out-of-pocket costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses of counsel), incurred by the Administrative Agent, the Fronting Banks, the Swing Line Lenders and the Lenders in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Agreement, any Note and the other documents to be delivered hereunder, including, without limitation, counsel fees and expenses in connection with the enforcement of rights under this Section 8.05(a).

(b) Except as otherwise expressly provided to the contrary herein, if any payment of principal of, or Conversion of, any Eurodollar Rate Advance is made other than on the last day of the Interest Period for such Advance, as a result of a payment or Conversion pursuant to Section 2.11 or 2.14 or a prepayment pursuant to Section 2.12 or acceleration of the maturity of any amounts owing hereunder pursuant to Section 6.01 or upon an assignment made upon demand of a Borrower pursuant to Section 8.08(h) or for any other reason, the applicable Borrower shall, upon demand by any Lender (with a copy of such demand to the Administrative Agent), pay to the Administrative Agent for the account of such Lender any amounts required to compensate such Lender for any additional losses, costs or expenses that it may reasonably incur as a result of such payment or Conversion, including, without limitation, any loss, cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by any Lender to fund or maintain such Advance. Each Borrower’s obligations under this subsection (b) shall survive the repayment of all other amounts owing to the Lenders and the Administrative Agent under this Agreement and any Note and the termination of the Commitments.

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(c) Each Borrower hereby agrees to indemnify and hold each Lender, each Fronting Bank, the Administrative Agent and their respective Affiliates and their respective officers, directors, employees and professional advisors (each, an “Indemnified Person”) harmless from and against any and all claims, damages, liabilities, costs or expenses (including reasonable attorney’s fees and expenses, whether or not such Indemnified Person is named as a party to any proceeding or is otherwise subjected to judicial or legal process arising from any such proceeding) that any of them may incur or that may be claimed against any of them by any Person (including any Borrower) by reason of or in connection with or arising out of any investigation, litigation or proceeding related to the Commitments or the commitment of each Fronting Bank hereunder and any use or proposed use by any Borrower of the proceeds of any Extension of Credit or the existence or use of any Letter of Credit or the amounts drawn thereunder, except to the extent such claim, damage, liability, cost or expense is found in a final, non-appealable judgment by a court of competent jurisdiction to have resulted from such Indemnified Person’s gross negligence or willful misconduct. Each Borrower’s obligations under this Section 8.05(c) shall survive (x) the repayment of all amounts owing to the Lenders, the Fronting Banks and the Administrative Agent under this Agreement and any Note, (y) the termination of the Commitments, the commitment of the Fronting Banks hereunder and any Letters of Credit and (z) the termination of this Agreement. If and to the extent that the obligations of the Borrowers under this Section 8.05(c) are unenforceable for any reason, each Borrower agrees to make the maximum payment in satisfaction of such obligations that are not unenforceable that is permissible under Applicable Law or, if less, such amount that may be ordered by a court of competent jurisdiction.

(d) To the extent permitted by law, each Borrower also agrees not to assert any claim against any Indemnified Person on any theory of liability, for special, indirect, consequential or punitive damages (as opposed to actual or direct damages) in connection with, arising out of, or otherwise relating to this Agreement, any of the transactions contemplated herein or the actual or proposed use of the proceeds of the Advances.

(e) Each Borrower shall be liable for its pro rata share of any payment to be made by the Borrowers under this Section 8.05, such pro rata share to be determined on the basis of such Borrower’s Fraction; provided, however, that if and to the extent that any such liabilities are reasonably determined by the Borrowers (subject to the approval of the Administrative Agent which approval shall not be unreasonably withheld) to be directly attributable to a specific Borrower, only such Borrower shall be liable for such payments.

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SECTION 8.06. Right of Set-off.

Upon the occurrence and during the continuance of any Event of Default each Lender, each Fronting Bank and each Swing Line Lender is hereby authorized at any time and from time to time, to the fullest extent permitted by law, to set off and apply any and all deposits (general or special, time or demand, provisional or final, excluding, however, any payroll accounts maintained by the Borrowers with such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) if and to the extent that such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) shall have expressly waived its set-off rights in writing in respect of such payroll account) at any time held and other indebtedness at any time owing by such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) to or for the credit or the account of the Borrowers against any and all of the obligations of the Borrowers now or hereafter existing under this Agreement and any Note held by such Lender, whether or not such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) shall have made any demand under this Agreement or such Note and although such obligations may be unmatured. Each Lender, each Fronting Bank and each Swing Line Lender agrees promptly to notify the Borrowers after any such set-off and application made by such Lender, such Fronting Bank or such Swing Line Lender (as the case may be), provided that the failure to give such notice shall not affect the validity of such set-off and application. The rights of each Lender and each Fronting Bank and each Swing Line Lender under this Section 8.06 are in addition to other rights and remedies (including, without limitation, other rights of set-off) that such Lender, such Fronting Bank or such Swing Line Lender (as the case may be) may have.

SECTION 8.07. Binding Effect.

This Agreement shall become effective when it shall have been executed by the Borrowers and the Administrative Agent and when the Administrative Agent shall have been notified by each Bank, each Swing Line Lender and each Fronting Bank that such Bank, such Swing Line Lender or such Fronting Bank (as the case may be) has executed it and thereafter shall be binding upon and inure to the benefit of the Borrowers, the Administrative Agent, each Swing Line Lender, each Fronting Bank and each Lender and their respective successors and permitted assigns, except that the Borrowers shall not have the right to assign their rights or obligations hereunder or any interest herein (x) without the prior written consent of the Lenders and the Fronting Banks or (y) pursuant to Section 5.03(c).

SECTION 8.08. Assignments and Participations.

(a) Successors and Assigns Generally. No Lender may assign or otherwise transfer any of its rights or obligations hereunder except (i) to an assignee in accordance with the provisions of subsection (b) of this Section 8.08, (ii) by way of participation in accordance with the provisions of subsection (d) of this Section 8.08, or (iii) by way of pledge or assignment of a security interest subject to the restrictions of subsection (f) of this Section 8.08 (and any other attempted assignment or transfer by any party hereto shall be null and void). Nothing in this Agreement, expressed or implied, shall be construed to confer upon any Person (other than the parties hereto, their respective successors and assigns permitted hereby, Participants to the extent provided in subsection (d) of this Section 8.08 and, to the extent expressly contemplated hereby, the Related Parties of each of the Administrative Agent and the Lenders) any legal or equitable right, remedy or claim under or by reason of this Agreement.

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(b) Assignments by Lenders. Any Lender may at any time assign to one or more assignees all or a portion of its rights and obligations under this Agreement (including all or a portion of its Commitment and the Advances at the time owing to it); provided that any such assignment shall be subject to the following conditions:

(i) Minimum Amounts.

(A) in the case of an assignment of the entire remaining amount of the assigning Lender’s Commitment and/or the Advances at the time owing to it or contemporaneous assignments to related Approved Funds that equal at least the amount specified in subsection (b)(i)(B) of this Section 8.08 in the aggregate or in the case of an assignment to a Lender, an Affiliate of a Lender or an Approved Fund, no minimum amount need be assigned; and

(B) in any case not described in subsection (b)(i)(A) of this Section 8.08, the aggregate amount of the Commitment (which for this purpose includes Advances outstanding thereunder) or, if the applicable Commitment is not then in effect, the principal outstanding balance of the Advances of the assigning Lender subject to each such assignment (determined as of the date the Assignment and Assumption with respect to such assignment is delivered to the Administrative Agent or, if “Trade Date” is specified in the Assignment and Assumption, as of the Trade Date) shall not be less than $5,000,000, unless each of the Administrative Agent and, so long as no Event of Default has occurred and is continuing, the Borrowers otherwise consent (each such consent not to be unreasonably withheld or delayed); provided that the Borrowers shall be deemed to have consented to any such assignment unless they shall object thereto by giving written notice to the Administrative Agent within five Business Days after having received notice thereof.

(ii) Proportionate Amounts. Each partial assignment shall be made as an assignment of a proportionate part of all the assigning Lender’s rights and obligations under this Agreement with respect to the Advance or the Commitment assigned.

(iii) Required Consents. No consent shall be required for any assignment except to the extent required by subsection (b)(i)(B) of this Section 8.08 and, in addition:

(A) the consent of the Borrowers (such consent not to be unreasonably withheld or delayed) shall be required unless (x) an Event of Default has occurred and is continuing at the time of such assignment, or (y) such assignment is to a Lender, an Affiliate of a Lender or an Approved Fund; provided that the Borrowers shall be deemed to have consented to any such assignment unless they shall object thereto by giving written notice to the Administrative Agent within five Business Days after having received notice thereof and provided, further, that the Borrowers’ consent shall not be required during the primary syndication hereof;

(B) the consent of the Administrative Agent (such consent not to be unreasonably withheld or delayed) shall be required for assignments if such assignment is to a Person that is not a Lender, an Affiliate of such Lender or an Approved Fund with respect to such Lender; and

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(C) the consent of each Fronting Bank and Swing Line Lender shall be required for all assignments, other than pursuant to subsection (f) below.

(iv) Assignment and Assumption. The parties to each assignment shall execute and deliver to the Administrative Agent an Assignment and Assumption, together with a processing and recordation fee of $3,500 provided that the Administrative Agent may, in its sole discretion, elect to waive such processing and recordation fee in the case of any assignment. The assignee, if it is not a Lender, shall deliver to the Administrative Agent an Administrative Questionnaire.

(v) No Assignment to Certain Persons. No such assignment shall be made to (A) the Borrowers or any of the Borrowers’ Affiliates or Subsidiaries or (B) to any Defaulting Lender or any of its Subsidiaries, or any Person who, upon becoming a Lender hereunder, would constitute any of the foregoing Persons described in this clause (B).

(vi) No Assignment to Natural Persons. No such assignment shall be made to a natural Person.

(vii) Certain Additional Payments. In connection with any assignment of rights and obligations of any Defaulting Lender hereunder, no such assignment shall be effective unless and until, in addition to the other conditions thereto set forth herein, the parties to the assignment shall make such additional payments to the Administrative Agent in an aggregate amount sufficient, upon distribution thereof as appropriate (which may be outright payment, purchases by the assignee of participations or subparticipations, or other compensating actions, including funding, with the consent of the Borrowers and the Administrative Agent, the applicable pro rata share of Advances previously requested but not funded by the Defaulting Lender, to each of which the applicable assignee and assignor hereby irrevocably consent), to (x) pay and satisfy in full all payment liabilities then owed by such Defaulting Lender to the Administrative Agent, each Fronting Bank, each Swing Line Lender and each other Lender hereunder (and interest accrued thereon), and (y) acquire (and fund as appropriate) its full pro rata share of all Advances and participations in Letters of Credit and Swing Line Advances in accordance with its Percentage. Notwithstanding the foregoing, in the event that any assignment of rights and obligations of any Defaulting Lender hereunder shall become effective under applicable law without compliance with the provisions of this paragraph, then the assignee of such interest shall be deemed to be a Defaulting Lender for all purposes of this Agreement until such compliance occurs.

Subject to acceptance and recording thereof by the Administrative Agent pursuant to paragraph (c) of this Section 8.08, from and after the effective date specified in each Assignment and Assumption, the assignee thereunder shall be a party to this Agreement and, to the extent of the interest assigned by such Assignment and Assumption, have the rights and obligations of a Lender under this Agreement, and the assigning Lender thereunder shall, to the extent of the interest assigned by such Assignment and Assumption, be released from its obligations under this Agreement (and, in the case of an Assignment and Assumption covering all of the assigning Lender’s rights and obligations under this Agreement, such Lender shall cease to be a party hereto) but shall continue to be entitled to the benefits of Sections 2.13, 2.16 and 8.05 with respect to facts and circumstances occurring prior to the effective date of such assignment; provided, that except to the extent otherwise expressly agreed by the affected parties, no assignment by a Defaulting Lender will constitute a waiver or release of any claim of any party hereunder arising from that Lender’s having been a Defaulting Lender. Any assignment or transfer by a Lender of rights or obligations under this Agreement that does not comply with this paragraph shall be treated for purposes of this Agreement as a sale by such Lender of a participation in such rights and obligations in accordance with paragraph (d) of this Section 8.08.

78

(c) Register. The Administrative Agent, acting solely for this purpose as an agent of the Borrowers, shall maintain at its offices at 600 Washington Boulevard, Stamford, Connecticut 06901 a copy of each Assignment and Assumption delivered to it and a register for the recordation of the names and addresses of the Lenders, and the Commitments of, and principal amounts of the Advances owing to, each Lender pursuant to the terms hereof from time to time (the “Register”). The entries in the Register shall be conclusive absent manifest error, and the Borrowers, the Administrative Agent and the Lenders shall treat each Person whose name is recorded in the Register pursuant to the terms hereof as a Lender hereunder for all purposes of this Agreement. The Register shall be available for inspection by the Borrowers and any Lender, at any reasonable time and from time to time upon reasonable prior notice.

(d) Participations. Any Lender may at any time, without the consent of, or notice to, the Borrowers or the Administrative Agent, sell participations to any Person (other than a natural Person or the Borrowers or any of the Borrowers’ Affiliates or Subsidiaries) (each, a “Participant”) in all or a portion of such Lender’s rights and/or obligations under this Agreement (including all or a portion of its Commitment and/or the Advances owing to it); provided that (i) such Lender’s obligations under this Agreement shall remain unchanged, (ii) such Lender shall remain solely responsible to the other parties hereto for the performance of such obligations, and (iii) the Borrowers, the Administrative Agent, the Fronting Banks and Lenders shall continue to deal solely and directly with such Lender in connection with such Lender’s rights and obligations under this Agreement. For the avoidance of doubt, each Lender shall be responsible for the indemnity under Section 7.05 with respect to any payments made by such Lender to its Participant(s). Each Lender that sells a participation shall, acting solely for this purpose as an agent of the Borrower, maintain a register on which it enters the name and address of each Participant and the principal amounts (and stated interest) of each Participant’s interest in the Loans or other obligations under this Agreement (the “Participant Register”); provided that no Lender shall have any obligation to disclose all or any portion of the Participant Register to any Person (including the identity of any Participant or any information relating to a Participant’s interest in any Commitments, Advances, Letters of Credit or its obligations under any Loan Document) except to the Internal Revenue Service and only to the extent that such disclosure is necessary to establish that such Commitment, Advance, Letter of Credit or other obligation is in registered form under Section 5f.103-1(c) of the United States Treasury Regulations. The entries in the Participant Register shall be conclusive absent manifest error, and such Lender shall treat each Person whose name is recorded in the Participant Register as the owner of such participation for all purposes of this Agreement notwithstanding any notice to the contrary.

79

Any agreement or instrument pursuant to which a Lender sells such a participation shall provide that such Lender shall retain the sole right to enforce this Agreement and to approve any amendment, modification or waiver of any provision of this Agreement; provided that such agreement or instrument may provide that such Lender will not, without the consent of the Participant, agree to any amendment, modification or waiver described in clauses (a) through (f) of Section 8.01 that affects such Participant. The Borrowers agree that each Participant shall be entitled to the benefits of Sections 2.13 and 2.16 to the same extent as if it were a Lender and had acquired its interest by assignment pursuant to subsection (b) of this Section 8.08; provided that such Participant agrees to be subject to the provisions of Sections 2.16(f) and 8.08(h) as if it were an assignee under subsection (b) of this Section 8.08. To the extent permitted by law, each Participant also shall be entitled to the benefits of Section 8.06 as though it were a Lender; provided that such Participant agrees to be subject to Section 2.17 as though it were a Lender.

(e) Limitations upon Participant Rights. A Participant shall not be entitled to receive any greater payment under Sections 2.13 and 2.16 than the applicable Lender would have been entitled to receive with respect to the participation sold to such Participant, unless the sale of the participation to such Participant is made with the Borrowers’ prior written consent. A Participant that would be a Foreign Lender if it were a Lender shall not be entitled to the benefits of Section 2.16 unless the Borrowers are notified of the participation sold to such Participant and such Participant agrees, for the benefit of the Borrowers, to comply with Section 2.16(e) as though it were a Lender.

(f) Certain Pledges. Any Lender may at any time pledge or assign a security interest in all or any portion of its rights under this Agreement to secure obligations of such Lender, including any pledge or assignment to secure obligations to a Federal Reserve Bank or other central banking authority; provided that no such pledge or assignment shall release such Lender from any of its obligations hereunder or substitute any such pledgee or assignee for such Lender as a party hereto.

(g) Disclosure of Certain Information. Any Lender may, in connection with any assignment or participation or proposed assignment or participation pursuant to this Section 8.08, disclose to the assignee or participant or proposed assignee or participant, any information relating to the Borrowers furnished to such Lender by or on behalf of the Borrowers; provided, that prior to any such disclosure, the assignee or participant or proposed assignee or participant shall agree to preserve the confidentiality of any confidential information relating to the Borrowers received by it from such Lender.

(h) Replacement of Lenders. If any Lender shall make demand for payment under Section 2.13(a), 2.13(b) or 2.16, or shall deliver any notice to the Administrative Agent pursuant to Section 2.14 resulting in the suspension of certain obligations of the Lenders with respect to Eurodollar Rate Advances, or shall be a Defaulting Lender, then, within 30 days of such demand (if, and only if, such payment demanded under Section 2.13(a), 2.13(b) or 2.16, as the case may be, shall have been made by a Borrower) or such notice (if such suspension is still in effect) or such Lenders’ becoming a Defaulting Lender, as the case may be, such Borrower may demand that such Lender assign in accordance with this Section 8.08 to one or more assignees designated by such Borrower and approved by the required Persons under subsection (b)(iii) above all (but not less than all) of such Lender’s Commitment and the Advances owing to it within the next 15 days. If any such assignee designated by such Borrower shall fail to consummate such assignment on terms acceptable to such Lender, or if such Borrower shall fail to designate any such assignee for all of such Lender’s

80

Commitment or Advances, then such Lender may assign such Commitment and Advances to any other assignee in accordance with this Section 8.08 during such 15-day period; it being understood for purposes of this Section 8.08(h) that such assignment shall be conclusively deemed to be on terms acceptable to such Lender, and such Lender shall be compelled to consummate such assignment to an assignee designated by such Borrower, if such assignee shall agree to such assignment in substantially the form of Exhibit A hereto and shall offer compensation to such Lender in an amount equal to the sum of the principal amount of all Advances outstanding to such Lender plus all interest accrued thereon to the date of such payment plus all other amounts payable by such Borrower to such Lender hereunder (whether or not then due) as of the date of such payment accrued in favor of such Lender hereunder. Notwithstanding the foregoing, no Lender shall make any assignment at any time pursuant to this subsection (g) if, at such time, (i) an Event of Default or Unmatured Default has occurred and is continuing, (ii) any Borrower has not satisfied all of its obligations hereunder with respect to such Lender or (iii) such replacement of such Lender is not acceptable to the Administrative Agent, the Fronting Banks and the Swing Line Lenders, as applicable, pursuant to subsection (b)(iii) above.

SECTION 8.09. Governing Law.

THIS AGREEMENT AND EACH OTHER LOAN DOCUMENT SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

SECTION 8.10. Consent to Jurisdiction; Waiver of Jury Trial.

(a) To the fullest extent permitted by law, each Borrower hereby irrevocably (i) submits to the exclusive jurisdiction of any New York State or Federal court sitting in New York City and any appellate court from any thereof in any action or proceeding arising out of or relating to this Agreement, any other Loan Document or any Letter of Credit, and (ii) agrees that all claims in respect of such action or proceeding may be heard and determined in such New York State court or in such Federal court. Each Borrower hereby irrevocably waives, to the fullest extent permitted by law, the defense of an inconvenient forum to the maintenance of such action or proceeding. Each Borrower also irrevocably consents, to the fullest extent permitted by law, to the service of any and all process in any such action or proceeding by the mailing by certified mail of copies of such process to such Borrower at its address specified in Section 8.02. Each Borrower agrees, to the fullest extent permitted by law, that a final judgment in any such action or proceeding shall be conclusive and may be enforced in other jurisdictions by suit on the judgment or in any other manner provided by law.

(b) EACH BORROWER, THE ADMINISTRATIVE AGENT, EACH FRONTING BANK, EACH SWING LINE LENDER AND THE LENDERS HEREBY WAIVE ALL RIGHT TO TRIAL BY JURY IN ANY ACTION, PROCEEDING OR COUNTERCLAIM ARISING OUT OF OR RELATING TO THIS AGREEMENT, ANY OTHER LOAN DOCUMENT OR ANY LETTER OF CREDIT, OR ANY OTHER INSTRUMENT OR DOCUMENT DELIVERED HEREUNDER OR THEREUNDER.

81

SECTION 8.11. Severability.

Any provision of this Agreement that is prohibited, unenforceable or not authorized in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition, unenforceability or non-authorization without invalidating the remaining provisions hereof or affecting the validity, enforceability or legality of such provision in any other jurisdiction.

SECTION 8.12. Entire Agreement.

This Agreement and the Notes issued hereunder constitute the entire contract among the parties relative to the subject matter hereof. Any previous agreement among the parties with respect to the subject matter hereof is superseded by this Agreement, except (i) as expressly agreed in any such previous agreement and (ii) for the Fee Letters and the Fronting Bank Fee Letters. Except as is expressly provided for herein, nothing in this Agreement, expressed or implied, is intended to confer upon any party other than the parties hereto any rights, remedies, obligations or liabilities under or by reason of this Agreement.

SECTION 8.13. Execution in Counterparts.

This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

SECTION 8.14. USA PATRIOT Act Notice.

Each Lender that is subject to the Patriot Act, each Fronting Bank and the Administrative Agent (for itself and not on behalf of any Lender) hereby notifies the Borrowers pursuant to the requirements of the Patriot Act that it is required to obtain, verify and record information that identifies the Borrowers, which information includes the name and address of the Borrower and other information that will allow such Lender, such Fronting Bank or the Administrative Agent, as applicable, to identify the Borrowers in accordance with the Patriot Act.

82

SECTION 8.15. No Fiduciary Duty.

The Administrative Agent, each Fronting Bank, each Swing Line Lender, each Lender and their respective Affiliates (collectively, the “Credit Parties”), may have economic interests that conflict with those of the Borrowers, their stockholders and/or their affiliates. Each Borrower agrees that nothing in the Loan Documents or otherwise will be deemed to create an advisory, fiduciary or agency relationship or fiduciary or other implied duty between any Credit Party, on the one hand, and such Borrower, its stockholders or its affiliates, on the other. The Borrowers acknowledge and agree that (i) the transactions contemplated by the Loan Documents (including the exercise of rights and remedies hereunder and thereunder) are arm’s-length commercial transactions between the Credit Parties, on the one hand, and the Borrowers, on the other, and (ii) in connection therewith and with the process leading thereto, (x) no Credit Party has assumed an advisory or fiduciary responsibility in favor of any Borrower, its stockholders or its affiliates with respect to the transactions contemplated hereby (or the exercise of rights or remedies with respect thereto) or the process leading thereto (irrespective of whether any Credit Party has advised, is currently advising or will advise any Borrower, its stockholders or its Affiliates on other matters) or any other obligation to any Borrower except the obligations expressly set forth in the Loan Documents and (y) each Credit Party is acting solely as principal and not as the agent or fiduciary of any Borrower, its management, stockholders, creditors or any other Person. Each Borrower acknowledges and agrees that it has consulted its own legal and financial advisors to the extent it deemed appropriate and that it is responsible for making its own independent judgment with respect to such transactions and the process leading thereto. Each Borrower agrees that it will not claim that any Credit Party has rendered advisory services of any nature or respect, or owes a fiduciary or similar duty to such Borrower, in connection with such transaction or the process leading thereto.

[Signatures to Follow]

83

IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be executed by their respective officers thereunto duly authorized, as of the date first above written.

FIRSTENERGY CORP. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY METROPOLITAN EDISON COMPANY OHIO EDISON COMPANY PENNSYLVANIA POWER COMPANY THE TOLEDO EDISON COMPANY AMERICAN TRANSMISSION SYSTEMS, INCORPORATED MONONGAHELA POWER COMPANY PENNSYLVANIA ELECTRIC COMPANY THE POTOMAC EDISON COMPANY WEST PENN POWER COMPANY
By:	/s/ James F. Pearson
	James F. Pearson
	Vice President & Treasurer
JERSEY CENTRAL POWER & LIGHT COMPANY
By:	/s/ Randy Scilla
	Randy Scilla
	Treasurer

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-1

THE ROYAL BANK OF SCOTLAND PLC, as Administrative Agent, as a Bank, as a Swing Line Lender and as a Fronting Bank
By:	/s/ Andrew N. Taylor
	Name:	Andrew N. Taylor
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-2

BANK OF AMERICA, N.A., as a Bank
By:	/s/ Mike Mason
	Name:	Mike Mason
	Title:	Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-3

BARCLAYS BANK PLC, as a Bank, as a Fronting Bank and as a Swing Line Lender
By:	/s/ Ann E. Sutton
	Name:	Ann E. Sutton
	Title:	Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-4

JPMORGAN CHASE BANK, N.A., as a Bank and as a Fronting Bank
By:	/s/ Peter Christensen
	Name:	Peter Christensen
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-5

CITIBANK, N.A., as a Bank
By:	/s/ Maureen Maroney
	Name:	Maureen Maroney
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-6

KEYBANK NATIONAL ASSOCIATION, as a Bank
By:	/s/ Sherrie I. Manson
	Name:	Sherrie I. Manson
	Title:	Senior Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-7

THE BANK OF NOVA SCOTIA, as a Bank
By:	/s/ Thane Rattew
	Name:	Thane Rattew
	Title:	Managing Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-8

THE BANK OF TOKYO-MITSUBISHI UFJ, LTD., as a Bank
By:	/s/ Bradford Joyce
	Name:	Bradford Joyce
	Title:	Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-9

UNION BANK, N.A., as a Bank
By:	/s/ Eric Otieno
	Name:	Eric Otieno
	Title:	Assistant Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-10

WELLS FARGO BANK, NATIONAL ASSOCIATION, as a Bank
By:	/s/ Frederick W. Price
	Name:	Frederick W. Price
	Title:	Managing Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-11

MORGAN STANLEY BANK, N.A., as a Bank
By:	/s/ Sherrese Clarke
	Name:	Sherrese Clarke
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-12

BNP Paribas, as a Bank
By:	/s/ Denis O’Meara
	Name:	Denis O’Meara
	Title:	Managing Director
By:	/s/ Pasquale Perraglia
	Name:	Pasquale Perraglia
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-13

CREDIT SUISSE AG, Cayman Islands Branch, as a Bank
By:	/s/ Shaheen Malik
	Name:	Shaheen Malik
	Title:	Vice President
By:	/s/ Rahul Parmar
	Name:	Rahul Parmar
	Title:	Associate

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-14

Goldman Sachs Bank USA, as a Bank
By:	/s/ Mark Walton
	Name:	Mark Walton
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-15

ROYAL BANK OF CANADA, as a Bank
By:	/s/ Thomas Casey
	Name:	Thomas Casey
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-16

UBS AG, Stamford Branch, as a Bank
By:	/s/ Irja R. Otsa
	Name:	Irja R. Otsa
	Title:	Associate Director
By:	/s/ Mary E. Evans
	Name:	Mary E. Evans
	Title:	Associate Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-17

MIZUHO CORPORATE BANK, LTD, as a Bank
By:	/s/ Leon Mo
	Name:	Leon Mo
	Title:	Authorized Signatory

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-18

PNC BANK, NATIONAL ASSOCIATION, as a Bank
By:	/s/ Christian S. Brown
	Name:	Christian S. Brown
	Title:	Senior Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-19

SUMITOMO MITSUI BANKING CORPORATION, as a Bank
By:	/s/ Hiroshi Higuma
	Name:	Hiroshi Higuma
	Title:	Joint General Manager

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-20

U.S. Bank National Association, as a Bank
By:	/s/ Eric J. Cosgrove
	Name:	Eric J. Cosgrove
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-21

The Bank of New York Mellon, as a Bank
By:	/s/ Richard K. Fronapfel, Jr.
	Name:	Richard K. Fronapfel, Jr.
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-22

CoBank, ACB, as a Bank
By:	/s/ Josh Batchelder
	Name:	Josh Batchelder
	Title:	Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-23

Banco Bilbao Vizcaya Argentaria, SA- New York Branch as a Bank
By:	/s/ Michael Oka
	Name:	Michael Oka
	Title:	Executive Director
By:	/s/ Michael D’Anna
	Name:	Michael D’Anna
	Title:	Executive Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-24

CIBC Inc., as a Bank
By:	/s/ Robert W. Casey, Jr.
	Name:	Robert Casey
	Title:	Authorized Signatory
By:	/s/ Josh Hogarth
	Name:	Josh Hogarth
	Title:	Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-25

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Bank
By:	/s/ Tom Byargeon
	Name:	Tom Byargeon
	Title:	Managing Director
By:	/s/ Sharada Manne
	Name:	Sharada Manne
	Title:	Director

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-26

Sovereign Bank, as a Bank
By:	/s/ Robert D. Lanigan
	Name:	Robert D. Lanigan
	Title:	SVP

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-27

THE HUNTINGTON NATIONAL BANK, as a Bank
By:	/s/ Brian H. Gallagher
	Name:	Brian H. Gallagher
	Title:	Senior Vice President

[Signature Page to FirstEnergy Corp. Credit Agreement]

S-28

SCHEDULE I

List of Commitments and Lending Offices

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
The Royal Bank of Scotland plc	$	88,888,888.89	600 Washington Boulevard, Stamford, Connecticut 06901	Same as Domestic Lending Office
			Contact: John Ferrante Phone: (203) 897-7623 Fax: (203) 873-5300 Email: john.ferrante@rbs.com Group Email: gbmnaagency@rbs.com
Bank of America, N.A.	$	88,888,888.89	104 N Tryon Street, Floor 17 Charlotte, NC 28155-0001 Contact: Mike Mason Phone: (980) 683-1839 Fax: (980) 233-7196 Email: Michael.mason@baml.com	Same as Domestic Lending Office
Barclays Bank PLC	$	88,888,888.89	745 Seventh Avenue New York, NY 10019 Primary Contact: Shawn Powers Phone: (201) 499-4580 Fax: (917) 522-0555 Email: shawn.powers@barcap.com Group Email: xrausloanops3@barclayscapital.com	Same as Domestic Lending Office
JPMorgan Chase Bank, N.A.	$	88,888,888.89	1111 Fannin, 10th Floor Houston, TX 77002-6925 Account Manager: Leslie Hill Phone: (713) 750-2318 Fax: (713) 427-6307 Email: leslie.d.hill@chase.com	Same as Domestic Lending Office
Citibank, N.A.	$	88,888,888.89	399 Park Ave, 16th Floor 5 New York, NY 10043 Contact: Loan Administration Phone: (302) 894-6052 Fax: (212) 994-0847 Email: GLOriginationOps@citi.com	Same as Domestic Lending Office

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
KeyBank National Association	$	88,888,888.89	124 Public Square Cleaveland, OH 44114 Contact: Yvette Dyson-Owens Phone: (216) 689-4815 Fax: (216) 370-6119 Email: Yvette_M_Dyson-Owens@Keybank.com	Same as Domestic Lending Office
The Bank of Nova Scotia	$	88,888,888.89	1 Liberty Plaza New York, NY 10006 Contact: Melissa McMillan Phone: (212) 225-5705 Fax: (212) 225-5709 Email: mellissa_mcmillan@scotiacapital.com	Same as Domestic Lending Office
The Bank of Tokyo-Mitsubishi UFJ, Ltd.	$	44,444,444.44	1251 Avenue of the Americas New York, NY 10020-1104 Contact: Mr. Jamie Velez Phone: (201) 413-8586 Fax: (201) 521-2304	Same as Domestic Lending Office
Union Bank, N.A.	$	44,444,444.44	445 S. Figueroa Street, 15th Floor Los Angeles, CA 90071 Contact: Commercial Loan Operations Fax: (800) 446-9951 Email: synd@unionbank.com	Same as Domestic Lending Office
Wells Fargo Bank, National Association	$	88,888,888.89	301 S. College St., 15th Floor MAC: D1053-150 Charlotte, NC 28202 Contact: Michelle P Field Phone: (303) 863-5411 Fax: (303) 863-2729 Email: Michelle.p.field@wellsfargo.com	Same as Domestic Lending Office
Morgan Stanley Bank, N.A.	$	86,666,666.67	1000 Lancaster Street Baltimore, MD 21202 Phone: (443) 627-4355 Fax: (718) 233-2140 Email: msloanservicing@morganstanley.com	Same as Domestic Lending Office

2

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
BNP Paribas	$	86,666,666.67	787 Seventh Avenue New York, NY 10019 Contact: Denis O’Meara Phone: (212) 471-8108 Fax: (212) 841-2745 Email: denis.omeara@us.bnpparibas.com	Same as Domestic Lending Office
Credit Suisse AG	$	86,666,666.67	Eleven Madison Avenue New York, NY 10010 Contact: Vijaykumar Kalji Phone + 91 20 6673 4371 Fax: (866) 469-3871 Email: vijaykumar.kalji@credit-suisse.com	Same as Domestic Lending Office
Goldman Sachs Bank USA	$	86,666,666.67	200 West Street New York, NY 10282 Contact: Operations Phone: (212) 902-1099 Fax: (212) 977-3966 Email: gs-sbd-admin-contacts@ny.email.gs.com	Same as Domestic Lending Office
Royal Bank of Canada	$	86,666,666.67	Three World Financial Center 5th Floor New York, NY 10281 Contact: Manager, Loans Administration Phone: (212) 428-6322 Fax: (212) 428-2372	Same as Domestic Lending Office
UBS AG, Stamford Branch	$	86,666,666.67	677 Washington Blvd. Stamford, CT 06901 Contact: Samantha Mason Phone: (203) 719-4839 Fax: (203) 719-3390 Email: Samantha.mason@ubs.com	Same as Domestic Lending Office
Mizuho Corporate Bank, LTD.	$	74,222,222.22	1251 Avenue of the Americas New York, NY 10020	Same as Domestic Lending Office

3

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
PNC Bank, National Association	$	74,222,222.22	249 First Avenue Pittsburgh, PA 15222 Contact: Maja Kuljic Phone: (440) 546-7364 Fax: (877) 728-2851 Email: Participationla8brv@pnc.com	Same as Domestic Lending Office
Sumitomo Mitsui Banking Corporation	$	74,222,222.22	277 Park Avenue 6th Floor New York, NY 10172 Contact: Delma Mitchell Phone: (212) 224-4387 Fax: (212) 224-4391 Email: Delma_c_mitchell@smbcgroup.com	Same as Domestic Lending Office
U.S. Bank National Association	$	74,222,222.22	National Corporate Banking CN-OH-W8 425 Walnut Street, 8th Floor Cincinnati, OH 45202 Contact: Eric Cosgrove Phone: (513) 632-3033 Fax: (513) 632-2068 Email: eric.cosgrove@usbank.com	Same as Domestic Lending Office
The Bank of New York Mellon	$	74,222,222.22	1 Wall Street, 19th Floor New York, NY 10286 Contact: Amber Mierek Phone: (315) 765-4300 Fax: (315) 765-4782 Email: amber.mierek@bnymellon.com	Same as Domestic Lending Office
CoBank, ACB	$	55,555,555.56	5500 South Quebec St. Greenwood Village, CO 80111 Contact: Graham Kaiser Phone: (303) 740-4386 Fax: (303) 740-4021 Email: agencybank@cobank.com	Same as Domestic Lending Office

4

				Eurodollar Lending
Lender	Allocation		Domestic Lending Office	Office
Banco Bilbao Vizcaya Argentaria, S.A.	$	53,333,333.33	1345 Avenue of the Americas 45th Floor New York, NY 10105 Contact: C&I Banking Phone: (212) 728-2382 Fax: (212) 333-2926 Email: cibny@grupobbva.com	Same as Domestic Lending Office
CIBC	$	53,333,333.33	425 Lexington Avenue, 4th Floor New York, NY 10017 Contact: Angela Tom Phone: (416) 542-4446 Fax: (905) 948-1934 Email: Angela.Tom@cibc.ca	Same as Domestic Lending Office
Credit Agricole Corporate and Investment Bank	$	53,333,333.33	1301 Avenue of the Americas New York, NY 10019 Contact: Dixon Schultz Phone: (713) 890-8607 Fax: (713) 890-8668 Email: dixon.schultz@ca-cib.com	Same as Domestic Lending Office
Sovereign Bank	$	53,333,333.33	75 State Street Boston, MA 02109 Contact: Roxaine Ovid Phone: (610) 988-1261 Fax: (484) 338-2831 Email: participations@sovereignbank.com	Same as Domestic Lending Office
The Huntington National Bank	$	40,000,000.00	41 South High Street Columbus, OH 43215 Contact: Shefali Patel Phone: (614) 480-5677 Fax: (614) 480-2249 Email: Shefali.patel@huntington.com	Same as Domestic Lending Office
TOTAL	$	2,000,000,000

5

SCHEDULE II

List of L/C Fronting Bank Commitments

		L/C Fronting Bank
Fronting Bank	Fronting Bank Address	Commitment
The Royal Bank of Scotland plc	600 Washington Boulevard, Stamford, Connecticut 06901 Primary Contact: Richard Emmich Phone: (203) 897-7619 Fax: (212) 401-1494 Email: richard.emmich@rbs.com Secondary Contact: Marchette Major Phone: (203) 897-7638 Fax: (212) 401-1494 Email: marchette.major@rbs.com	$	250,000,000
Barclays Bank PLC	Letter of Credit Department 200 Park Avenue New York, NY 10166 Attn: Dawn Townsend Phone: (201) 499-2081 Fax: (212) 412-5011 Email: dawn.townsend@barcap.com	$	350,000,000
	Group Email: XraLetterofCredit@barclayscapital.com
JPMorgan Chase Bank, N.A.	Global Trade Services, 10420 Highland Manor Drive Floor 4, Tampa, FL 33610-9128 Attention: Letter of Credit Department Fax: (813) 432-5162 Email: James.Alonzo@jpmchase.com	$	100,000,000

SCHEDULE III

List of Swing Line Commitments

Swing Line Lender	Swing Line Commitment
The Royal Bank of Scotland plc	$	125,000,000
Barclays Bank PLC	$	125,000,000

SCHEDULE IV

Letters of Credit

Please see attached.

SCHEDULE V

Existing Facilities

1.	$2,750,000,000 Credit Agreement, dated as of August 24, 2006, as amended as of November 2, 2007, among certain of the Borrowers, the lenders and fronting banks parties thereto and Citibank, N.A., as administrative agent.
2.	$110,000,000 Credit Agreement, dated as of December 18, 2009, among Monongahela Power Company, certain banks, financial institutions and other institutional lenders, The Bank of Nova Scotia, as joint lead arranger and administrative agent, and Union Bank, N.A., as joint lead arranger and as syndication agent.
3.	$150,000,000 Credit Agreement, dated as of April 30, 2010, among The Potomac Edison Company, certain banks, financial institutions and other institutional lenders, The Bank of Nova Scotia as the global coordinator, Commerzbank AG, New York and Grand Cayman Branches, as joint lead arranger and administrative agent, and BNP Paribas Securities Corp., as joint lead arranger and as syndication agent.
4.	$200,000,000 Credit Agreement, dated as of April 30, 2010, among West Penn Power Company, certain banks, financial institutions and other institutional lenders, The Bank of Nova Scotia as the global coordinator, joint lead arranger and as syndication agent, PNC Bank, National Association, as administrative agent, and PNC Capital Markets LLC, as joint lead arranger.

SCHEDULE VI

Disclosure Documents

1.	Update to matters addressed in each of FE’s, Met-Ed’s and Penelec’sFirst Quarter Form 10-Q, Note 10 — Regulatory Matters, (E) Pennsylvania, concerning Met-Ed and Penelec and the collection of marginal transmission losses:
	On June 14, 2011, the Commonwealth Court affirmed the Pennsylvania Public Utility Commission’s (PPUC) decision that the marginal transmission losses are not recoverable as transmission costs. Met-Ed and Penelec are considering an appeal of the Commonwealth Court’s decision to the Pennsylvania Supreme Court. If management ultimately determines that the probability of success is not high enough to support continued recognition of the regulatory assets that had been established for the recoverable marginal transmission losses, Met-Ed and Penelec would write off the regulatory assets.
2.	Update to matters addressed in (i) FE’s First Quarter Form 10-Q, Note 10 — Regulatory Matters, (H) FERC Matters, RTO Realignment; and (ii) ATSI 2010 Annual Financial Statements, Note 10 — Commitments and Contingencies, Regulatory Matters, RTO Realignment:
	On February 1, 2011, ATSI — in conjunction with PJM — submitted its proposal for moving its transmission rate into PJM’s tariffs to FERC. On May 31, 2011, FERC issued an order that made the following rulings: (i) ATSI’s formula rate was moved into PJM’s tariffs without change; (ii) ATSI’s request to recover exit fees, entry costs, and MTEP costs was found to lack evidentiary basis and FERC directed that these costs (that would have been incremental to ATSI’s formula rate) be removed from the rate until such time as ATSI presents evidence that demonstrates that the benefits to transmission customers of moving to PJM exceed these costs; (iii) consistent with existing practices under the PJM tariff, ATSI had proposed to adopt a formal process for communicating information about the annual update to ATSI’s formula rate to customers — FERC noted that some transmission customers objected to parts of the proposed process and set this narrow set of issues for hearing.
	On April 1, 2011, the Midwest ISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. This filing is important because the Midwest ISO Transmission Owners agreed that transmission customers, and not ATSI (or other utilities) are responsible for MTEP costs. On May 31, 2011, FERC issued an order rejecting elements of this filing. The basis for FERC’s rejection was FERC’s finding, in the ATSI T-Rates case order, that ATSI had not yet established that the MTEP costs should be recovered from customers. FERC directed ATSI and the RTOs (PJM and MISO) to submit compliance filings by June 30, 2011 to adjust the tariffs as necessary to implement the May 31, 2011 orders. ATSI will submit the compliance filings as directed. Moreover, ATSI likely will ask for rehearing of FERC’s directives with regard to exit fees, entry costs, and MTEP costs.
	FERC has ruled that ATSI cannot yet recover the MISO exit fee in its transmission rates, from the ATSI Utilities and its other transmission customers.

3.	Update to matters addressed in (i) FE’s First Quarter Form 10-Q, Note 10 — Regulatory Matters, (H) FERC Matters, MISO Multi-Value Project Rule Proposal; and (ii) ATSI 2010 Annual Financial Statements, Note 10 — Commitments and Contingencies, Regulatory Matters, MISO Multi-Value Project Rule Proposal:
	On May 31, 2011, FERC issued an order that made the following rulings: (i) ATSI’s formula rate was moved into PJM’s tariffs without change; (ii) ATSI’s request to recover exit fees, entry costs, and MTEP costs was found to lack evidentiary basis and FERC directed that these costs (that would have been incremental to ATSI’s formula rate) be removed from the rate until such time as ATSI presents evidence that demonstrates that the benefits to transmission customers of moving to PJM exceed these costs; (iii) consistent with existing practices under the PJM tariff ATSI had proposed to adopt a formal process for communicating information about the annual update to ATSI’s formula rate to customers — FERC noted that some transmission customers objected to parts of the proposed process and set this narrow set of issues for hearing. FERC also announced that it would host a settlement conference on June 23, 2011, to determine if settlement can be reached on the narrow question of the procedures and protocols for communicating data to customers about the annual update to the formula rate. FirstEnergy will attend this settlement conference.
	FERC directed ATSI and the RTOs (PJM and MISO) to submit compliance filings by June 30, 2011 to adjust the tariffs as necessary to implement the May 31, 2011 orders. ATSI will submit the compliance filings as directed. Moreover, ATSI likely will ask for rehearing of FERC’s directives with regard to exit fees, entry costs, and MTEP costs. The rehearing filing will be submitted on June 30, 2011.

EXHIBIT A
Form of Assignment and Assumption

ASSIGNMENT AND ASSUMPTION

This Assignment and Assumption (the “Assignment and Assumption”) is dated as of the Effective Date set forth below and is entered into by and between [the][each]¹ Assignor identified in item 1 below ([the][each, an] “Assignor”) and [the][each]² Assignee identified in item 2 below ([the][each, an] “Assignee”). [It is understood and agreed that the rights and obligations of [the Assignors][the Assignees]³ hereunder are several and not joint.]⁴ Capitalized terms used but not defined herein shall have the meanings given to them in the Credit Agreement identified below (as amended, the “Credit Agreement”), receipt of a copy of which is hereby acknowledged by [the][each] Assignee. The Standard Terms and Conditions set forth in Annex 1 attached hereto are hereby agreed to and incorporated herein by reference and made a part of this Assignment and Assumption as if set forth herein in full.

For an agreed consideration, [the][each] Assignor hereby irrevocably sells and assigns to [the Assignee][the respective Assignees], and [the][each] Assignee hereby irrevocably purchases and assumes from [the Assignor][the respective Assignors], subject to and in accordance with the Standard Terms and Conditions and the Credit Agreement, as of the Effective Date inserted by the Administrative Agent as contemplated below (i) all of [the Assignor’s][the respective Assignors’] rights and obligations in [its capacity as a Lender][their respective capacities as Lenders] under the Credit Agreement and any other documents or instruments delivered pursuant thereto to the extent related to the amount and percentage interest identified below of all of such outstanding rights and obligations of [the Assignor][the respective Assignors] under the respective facilities identified below (including without limitation any letters of credit, guarantees, and swing line loans included in such facilities), and (ii) to the extent permitted to be assigned under applicable law, all claims, suits, causes of action and any other right of [the Assignor (in its capacity as a Lender)][the respective Assignors (in their respective capacities as Lenders)] against any Person, whether known or unknown, arising under or in connection with the Credit Agreement, any other documents or instruments delivered pursuant thereto or the loan transactions governed thereby or in any way based on or related to any of the foregoing, including, but not limited to, contract claims, tort claims, malpractice claims, statutory claims and all other claims at law or in equity related to the rights and obligations sold and assigned pursuant to clause (i) above (the rights and obligations sold and assigned by [the][any] Assignor to [the][any] Assignee pursuant to clauses (i) and (ii) above being referred to herein collectively as [the][an] “Assigned Interest”). Each such sale and assignment is without recourse to [the][any] Assignor and, except as expressly provided in this Assignment and Assumption, without representation or warranty by [the][any] Assignor.

1. Assignor[s]:

1	For bracketed language here and elsewhere in this form relating to the Assignor(s), if the assignment is from a single Assignor, choose the first bracketed language. If the assignment is from multiple Assignors, choose the second bracketed language.
2	For bracketed language here and elsewhere in this form relating to the Assignee(s), if the assignment is to a single Assignee, choose the first bracketed language. If the assignment is to multiple Assignees, choose the second bracketed language.
3	Select as appropriate.
4	Include bracketed language if there are either multiple Assignors or multiple Assignees.

	[Assignor [is] [is not] a Defaulting Lender]
2.	Assignee[s]:
	[for each Assignee, indicate [Affiliate][Approved Fund] of [identify Lender]
3.	Borrowers:	FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company
4.	Administrative Agent:	The Royal Bank of Scotland plc as the administrative agent under the Credit Agreement
5.	Credit Agreement:	The $2,000,000,000 Credit Agreement dated as of June 17, 2011 among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as Borrowers, the Lenders parties thereto, The Royal Bank of Scotland plc, as Administrative Agent, and the fronting banks and swing line lenders party thereto
6.	Assigned Interest[s]:

			Amount of	Percentage
		Aggregate Amount of	Commitment/	Assigned of
		Commitment/Advances	Advances	Commitment/		CUSIP
Assignor[s]5	Assignee[s]6	for all Lenders7	Assigned8	Advances8		Number
		$	$		%
		$	$		%
		$	$		%

[7. Trade Date:                                         ]⁹

5	List each Assignor, as appropriate.
6	List each Assignee, as appropriate.
7	Amount to be adjusted by the counterparties to take into account any payments or prepayments made between the Trade Date and the Effective Date.
8	Set forth, to at least 9 decimals, as a percentage of the Commitment/Advances of all Lenders thereunder.
9	To be completed if the Assignor(s) and the Assignee(s) intend that the minimum assignment amount is to be determined as of the Trade Date.

A-2

Effective Date:                           , 201    [TO BE INSERTED BY ADMINISTRATIVE AGENT AND WHICH SHALL BE THE EFFECTIVE DATE OF RECORDATION OF TRANSFER IN THE REGISTER THEREFOR.]

The terms set forth in this Assignment and Assumption are hereby agreed to:

ASSIGNOR[S]10 [NAME OF ASSIGNOR]
By:
	Name:
	Title:
[NAME OF ASSIGNOR]
By:
	Name:
	Title:
ASSIGNEE[S]11 [NAME OF ASSIGNEE]
By:
	Name:
	Title:
[NAME OF ASSIGNEE]
By:
	Name:
	Title:

10	Add additional signature blocks as needed. Include both Fund/Pension Plan and manager making the trade (if applicable).
11	Add additional signature blocks as needed. Include both Fund/Pension Plan and manager making the trade (if applicable).

A-3

[Consented to and]12 Accepted:
THE ROYAL BANK OF SCOTLAND PLC, as Administrative Agent
By:
	Name:
	Title:
Consented to:
[LIST ALL FRONTING BANKS]., as a Fronting Bank
By:
	Name:
	Title:
[LIST ALL SWING LINE LENDERS], as a Swing Line Lender
By:
	Name:
	Title:
[FIRSTENERGY CORP. THE CLEVELAND ELECTRIC ILLUMINATING COMPANY METROPOLITAN EDISON COMPANY OHIO EDISON COMPANY PENNSYLVANIA POWER COMPANY THE TOLEDO EDISON COMPANY AMERICAN TRANSMISSION SYSTEMS, INCORPORATED MONONGAHELA POWER COMPANY PENNSYLVANIA ELECTRIC COMPANY THE POTOMAC EDISON COMPANY WEST PENN POWER COMPANY
By:
	Name:
	Title:
JERSEY CENTRAL POWER & LIGHT COMPANY
By:
	Name:
	Title:]13

12	To be added only if the consent of the Administrative Agent is required by the terms of the Credit Agreement.
13	To be added only if the consent of the Borrowers are required by the terms of the Credit Agreement.

A-4

ANNEX 1

$2,000,000,000 Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as Borrowers, the Lenders parties thereto, The Royal Bank of Scotland plc, as Administrative Agent, and the fronting banks and swing line lenders party thereto

STANDARD TERMS AND CONDITIONS FOR
ASSIGNMENT AND ASSUMPTION

1. Representations and Warranties.

1.1 Assignor[s]. [The][Each] Assignor (a) represents and warrants that (i) it is the legal and beneficial owner of [the][the relevant] Assigned Interest, (ii) [the][such] Assigned Interest is free and clear of any lien, encumbrance or other adverse claim, (iii) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and (iv) it is [not] a Defaulting Lender; and (b) assumes no responsibility with respect to (i) any statements, warranties or representations made in or in connection with the Credit Agreement or any other Loan Document, (ii) the execution, legality, validity, enforceability, genuineness, sufficiency or value of the Loan Documents or any collateral thereunder, (iii) the financial condition of the Borrowers, any of its Subsidiaries or Affiliates or any other Person obligated in respect of any Loan Document, or (iv) the performance or observance by the Borrowers, any of its Subsidiaries or Affiliates or any other Person of any of their respective obligations under any Loan Document.

1.2. Assignee[s]. [The][Each] Assignee (a) represents and warrants that (i) it has full power and authority, and has taken all action necessary, to execute and deliver this Assignment and Assumption and to consummate the transactions contemplated hereby and to become a Lender under the Credit Agreement, (ii) it meets all the requirements to be an assignee under Section 8.08(b)(iii), (v) and (vi) of the Credit Agreement (subject to such consents, if any, as may be required under Section 8.08(b)(iii) of the Credit Agreement), (iii) from and after the Effective Date, it shall be bound by the provisions of the Credit Agreement as a Lender thereunder and, to the extent of [the][the relevant] Assigned Interest, shall have the obligations of a Lender thereunder, (iv) it is sophisticated with respect to decisions to acquire assets of the type represented by the Assigned Interest and either it, or the Person exercising discretion in making its decision to acquire the Assigned Interest, is experienced in acquiring assets of such type, (v) it has received a copy of the Credit Agreement, and has received or has been accorded the opportunity to receive copies of the most recent financial statements delivered pursuant to Section 5.01(g) thereof, as applicable, and such other documents and information as it deems appropriate to make its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, (vi) it has, independently and without reliance upon the Administrative Agent or any other Lender and based on such documents and information as it has deemed appropriate, made its own credit analysis and decision to enter into this Assignment and Assumption and to purchase [the][such] Assigned Interest, and (vii) if it is not a U.S. Person, attached to the Assignment and Assumption is any documentation required to be delivered by it pursuant to the terms of the Credit Agreement (including pursuant to Section 2.16(e)(ii) of the Credit Agreement), duly completed and executed by [the][such] Assignee; and (b) agrees that (i) it will, independently and without reliance on the Administrative Agent, [the][any] Assignor or any other Lender, and based on such documents and information as it shall deem appropriate at the time, continue to make its own credit decisions in taking or not taking action under the Loan Documents, and (ii) it will perform in accordance with their terms all of the obligations which by the terms of the Loan Documents are required to be performed by it as a Lender.

2. Payments. From and after the Effective Date, the Administrative Agent shall make all payments in respect of [the][each] Assigned Interest (including payments of principal, interest, fees and other amounts) to [the][the relevant] Assignor for amounts which have accrued to but excluding the Effective Date and to [the][the relevant] Assignee for amounts which have accrued from and after the Effective Date. Notwithstanding the foregoing, the Administrative Agent shall make all payments of interest, fees or other amounts paid or payable in kind from and after the Effective Date to [the][the relevant] Assignee.

3. General Provisions. This Assignment and Assumption shall be binding upon, and inure to the benefit of, the parties hereto and their respective successors and assigns. This Assignment and Assumption may be executed in any number of counterparts, which together shall constitute one instrument. Delivery of an executed counterpart of a signature page of this Assignment and Assumption by telecopy shall be effective as delivery of a manually executed counterpart of this Assignment and Assumption. This Assignment and Assumption shall be governed by, and construed in accordance with, the law of the State of New York.

EXHIBIT B
Form of Note

PROMISSORY NOTE

U.S.$[                    ]                           , 20     

FOR VALUE RECEIVED, the undersigned, [FIRSTENERGY CORP.] [THE CLEVELAND ELECTRIC ILLUMINATING COMPANY] [METROPOLITAN EDISON COMPANY] [OHIO EDISON COMPANY] [PENNSYLVANIA POWER COMPANY] [THE TOLEDO EDISON COMPANY] [AMERICAN TRANSMISSION SYSTEMS, INCORPORATED] [JERSEY CENTRAL POWER & LIGHT COMPANY] [MONONGAHELA POWER COMPANY] [PENNSYLVANIA ELECTRIC COMPANY] [THE POTOMAC EDISON COMPANY] [WEST PENN POWER COMPANY], a[n] [                    ] corporation (the “Borrower”), HEREBY PROMISES TO PAY to [                    ] (the “Lender”) for the account of its Applicable Lending Office (such term and other capitalized terms herein being used as defined in the Credit Agreement referred to below), or its registered assigns, the principal sum of U.S.$[                    ] or, if less, the aggregate principal amount of the Advances made by the Lender to the Borrower pursuant to the Credit Agreement outstanding on the Termination Date, payable on the Termination Date.

The Borrower promises to pay interest on the unpaid principal amount of each Advance from the date of such Advance until such principal amount is paid in full, at such interest rates, and payable at such times, as are specified in the Credit Agreement.

Both principal and interest are payable in lawful money of the United States of America to The Royal Bank of Scotland plc, as Administrative Agent, at [INSERT PAYMENT ADDRESS], in same day funds. Each Advance made by the Lender to the Borrower pursuant to the Credit Agreement, and all payments made on account of principal thereof, shall be recorded by the Lender and, prior to any transfer hereof, endorsed on the grid attached hereto which is part of this Promissory Note.

This Promissory Note is one of the Notes referred to in, and is entitled to the benefits of, the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Borrower, [FirstEnergy Corp.,] [The Cleveland Electric Illuminating Company,] [Metropolitan Edison Company,] [Ohio Edison Company,] [Pennsylvania Power Company,] [The Toledo Edison Company,] [American Transmission Systems, Incorporated,] [Jersey Central Power & Light Company,] [Monongahela Power Company,] [Pennsylvania Electric Company,] [The Potomac Edison Company,] [West Penn Power Company,] the banks party thereto, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time. The Credit Agreement, among other things, (i) provides for the making of Advances by the Lender to the Borrower from time to time in an aggregate amount not to exceed at any time outstanding the Dollar amount first above mentioned, the indebtedness of the Borrower resulting from each such Advance being evidenced by this Promissory Note, and (ii) contains provisions for acceleration of the maturity hereof upon the happening of certain stated events and also for prepayments on account of principal hereof prior to the maturity hereof upon the terms and conditions therein specified.

The Borrower hereby waives presentment, demand, protest and notice of any kind. No failure to exercise, and no delay in exercising, any rights hereunder on the part of the holder hereof shall operate as a waiver of such rights.

THIS PROMISSORY NOTE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

[FIRSTENERGY CORP.] [THE CLEVELAND ELECTRIC ILLUMINATING COMPANY] [METROPOLITAN EDISON COMPANY] [OHIO EDISON COMPANY] [PENNSYLVANIA POWER COMPANY] [THE TOLEDO EDISON COMPANY] [AMERICAN TRANSMISSION SYSTEMS, INCORPORATED] [JERSEY CENTRAL POWER & LIGHT COMPANY] [MONONGAHELA POWER COMPANY] [PENNSYLVANIA ELECTRIC COMPANY] [THE POTOMAC EDISON COMPANY] [WEST PENN POWER COMPANY]
By:
	Name:
	Title:

B-2

EXHIBIT C
Form of Notice of Pro-Rata Borrowing

The Royal Bank of Scotland plc, as Administrative Agent
for the Lenders party to the Credit Agreement
referred to below

                , 200     

Ladies and Gentlemen:

The undersigned refers to the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, [FirstEnergy Corp.,] [The Cleveland Electric Illuminating Company,] [Metropolitan Edison Company,] [Ohio Edison Company,] [Pennsylvania Power Company,] [The Toledo Edison Company,] [American Transmission Systems, Incorporated,] [Jersey Central Power & Light Company,] [Monongahela Power Company,] [Pennsylvania Electric Company,] [The Potomac Edison Company,] [West Penn Power Company,] the banks party thereto, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time, and hereby gives you notice, irrevocably, pursuant to Section 2.02 of the Credit Agreement that the undersigned hereby requests [a] Pro-Rata Borrowing[s] under the Credit Agreement, and in that connection sets forth below the information relating to such Pro-Rata Borrowing[s] (the “Proposed Borrowing[s]”) as required by Section 2.02(a) of the Credit Agreement:

(i) The Business Day of the Proposed Borrowing[s] is                     ,      .

(ii) The Type of Pro-Rata Advance to be made in connection with the [First] Proposed Borrowing is [an Alternate Base Rate Pro-Rata Advance] [a Eurodollar Rate Advance]. The aggregate amount of such Proposed Borrowing is $                    . [The Interest Period for each Eurodollar Rate Advance made as part of such Proposed Borrowing is            [week][month[s]].]

[(iii) The Type of Pro-Rata Advance to be made in connection with the [Second] Proposed Borrowing is [an Alternate Base Rate Pro-Rata Advance] [a Eurodollar Rate Advance]. The aggregate amount of such Proposed Borrowing is $                    . [The Interest Period for each Eurodollar Rate Advance made as part of such Proposed Borrowing is            [week][month[s]].]

[(iii)][(iv)] The Borrower requesting the Proposed Borrowing[s] is                     .

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing[s]:

(A) the representations and warranties of such Borrower contained in Section 4.01 [(other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof)]* of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing[s] and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of the Proposed Borrowing[s], in which case, such representation and warranty is true and correct as of such specific date);

(B) no event has occurred and is continuing, or would result from such Proposed Borrowing[s] or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower; and

(C) immediately following such Proposed Borrowing[s], (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment and (3) the Outstanding Credits for the account of any Borrower shall not exceed the Borrower Sublimit for such Borrower.

Please transfer or credit the funds to the following account:

Bank:                     

Address:                     

ABA #:                     

Account #:                     

Beneficiary:                     

[remainder of page intentionally left blank]

* Delete for initial Extension of Credit.

C-2

Very truly yours,** [FIRSTENERGY CORP.] [THE CLEVELAND ELECTRIC ILLUMINATING COMPANY] [METROPOLITAN EDISON COMPANY] [OHIO EDISON COMPANY] [PENNSYLVANIA POWER COMPANY] [THE TOLEDO EDISON COMPANY] [AMERICAN TRANSMISSION SYSTEMS, INCORPORATED] [JERSEY CENTRAL POWER & LIGHT COMPANY] [MONONGAHELA POWER COMPANY] [PENNSYLVANIA ELECTRIC COMPANY] [THE POTOMAC EDISON COMPANY] [WEST PENN POWER COMPANY]
By:
	Name:
	Title:

** Please use a separate Notice of Pro-Rata Borrowing for each Borrower.

C-3

EXHIBIT D
Form of Notice of Swing Line Borrowing

The Royal Bank of Scotland plc, as Administrative Agent
for the Lenders party to the Credit Agreement
referred to below

                , 200     

Ladies and Gentlemen:

The undersigned refers to the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”, the terms defined therein being used herein as therein defined), among the undersigned, [FirstEnergy Corp.,] [The Cleveland Electric Illuminating Company,] [Metropolitan Edison Company,] [Ohio Edison Company,] [Pennsylvania Power Company,] [The Toledo Edison Company,] [American Transmission Systems, Incorporated,] [Jersey Central Power & Light Company,] [Monongahela Power Company,] [Pennsylvania Electric Company,] [The Potomac Edison Company,] [West Penn Power Company,] the banks party thereto, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time, and hereby gives you notice, irrevocably, pursuant to Section 2.03 of the Credit Agreement that the undersigned hereby requests a Swing Line Borrowing under the Credit Agreement, and in that connection sets forth below the information relating to such Swing Line Borrowing (the “Proposed Borrowing”) as required by Section 2.03(b) of the Credit Agreement:

(i) The Business Day of the Proposed Borrowing is                     ,      .

(ii) The aggregate amount of the Proposed Borrowing is $                    .

(iii) The Borrower requesting the Proposed Borrowing is                     .

The undersigned hereby certifies that the following statements are true on the date hereof, and will be true on the date of the Proposed Borrowing:

(A) the representations and warranties of such Borrower contained in Section 4.01 [(other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof)]* of the Credit Agreement are correct, before and after giving effect to the Proposed Borrowing and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of the Proposed Borrowing, in which case, such representation and warranty is true and correct as of such specified date);

(B) no event has occurred and is continuing, or would result from such Proposed Borrowing or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower ; and

(C) immediately following such Proposed Borrowing, (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment, (3) the Outstanding Credits for the account of any Borrower shall not exceed the Borrower Sublimit for such Borrower, and (4) the aggregate principal amount of the Swing Line Advances outstanding shall not exceed the Swing Line Sublimit.

Please transfer or credit the funds to the following account:

Bank:                     

Address:                     

ABA #:                     

Account #:  _____ 

Beneficiary:                     

[remainder of page intentionally left blank]

* Delete for initial Extension of Credit.

D-2

Very truly yours, [FIRSTENERGY CORP.] [THE CLEVELAND ELECTRIC ILLUMINATING COMPANY] [METROPOLITAN EDISON COMPANY] [OHIO EDISON COMPANY] [PENNSYLVANIA POWER COMPANY] [THE TOLEDO EDISON COMPANY] [AMERICAN TRANSMISSION SYSTEMS, INCORPORATED] [JERSEY CENTRAL POWER & LIGHT COMPANY] [MONONGAHELA POWER COMPANY] [PENNSYLVANIA ELECTRIC COMPANY] [THE POTOMAC EDISON COMPANY] [WEST PENN POWER COMPANY]
By:
	Name:
	Title:

D-3

EXHIBIT E
Form of Letter of Credit Request

                , 200     

The Royal Bank of Scotland plc, as
Administrative Agent
[INSERT ADMINISTRATIVE AGENT’S ADDRESS]
Attn:                                         

[                                        , as Fronting Bank
[ADDRESS]]

Ladies and Gentlemen:

The undersigned, [FIRSTENERGY CORP.] [THE CLEVELAND ELECTRIC ILLUMINATING COMPANY] [METROPOLITAN EDISON COMPANY] [OHIO EDISON COMPANY] [PENNSYLVANIA POWER COMPANY] [THE TOLEDO EDISON COMPANY] [AMERICAN TRANSMISSION SYSTEMS, INCORPORATED] [JERSEY CENTRAL POWER & LIGHT COMPANY] [MONONGAHELA POWER COMPANY] [PENNSYLVANIA ELECTRIC COMPANY] [THE POTOMAC EDISON COMPANY] [WEST PENN POWER COMPANY], a[n] [                    ] corporation (the “Borrower”), refer to that certain Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Borrower, [FirstEnergy Corp.,] [The Cleveland Electric Illuminating Company,] [Metropolitan Edison Company,] [Ohio Edison Company,] [Pennsylvania Power Company,] [The Toledo Edison Company,] [American Transmission Systems, Incorporated,] [Jersey Central Power & Light Company,] [Monongahela Power Company,] [Pennsylvania Electric Company,] [The Potomac Edison Company,] [West Penn Power Company,] the banks party thereto, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto from time to time and the swing line lenders party thereto from time to time. Capitalized terms used herein, and not otherwise defined herein, shall have their respective defined meanings as set forth in the Credit Agreement.

Pursuant to Section 2.04(d) of the Credit Agreement, the Borrower irrevocably requests that the Fronting Bank to which this Letter of Credit Request is addressed issue a Letter of Credit on the following terms:

1. Date of Issuance:

2. Expiration Date:

3. Stated Amount:

4. Beneficiary:

5. Account Party:

and the terms set forth in the attached application for said Letter of Credit.

The Borrower hereby further certifies that (i) as of the date hereof, (ii) as of the Date of Issuance and (iii) after the issuance of the Letter of Credit requested hereby:

(A) the representations and warranties of such Borrower contained in Section 4.01 [(other than (1) subsection (f) thereof, (2) the first sentence of subsection (g) thereof (but solely with respect to the unaudited consolidated balance sheet of such Borrower and its Subsidiaries, as at March 31, 2011, and the related consolidated statements of income, retained earnings and cash flows for the three months then ended), and (3) the last sentence of subsection (g) thereof)]* of the Credit Agreement are true and correct on and as of the date hereof, before and after giving effect to the issuance of such Letter of Credit and to the application of the proceeds therefrom, as though made on and as of such date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the date of the issuance of such Letter of Credit, in which case, such representation and warranty is true and correct as of such specified date);

(B) no event has occurred and is continuing, or would result from the issuance of the Letter of Credit requested hereby or from the application of the proceeds therefrom, that constitutes an Event of Default or an Unmatured Default with respect to such Borrower; and

(C) immediately following the issuance of such Letter of Credit, (1) the aggregate amount of Outstanding Credits shall not exceed the aggregate amount of the Commitments then in effect, (2) the Outstanding Credits of any Lender shall not exceed the amount of such Lender’s Commitment [and] [,] (3) the Stated Amount thereof, when aggregated with (x) the Stated Amount of each other Letter of Credit that is outstanding or with respect to which a Letter of Credit Request has been received and (y) the outstanding Reimbursement Obligations, shall not exceed the L/C Commitment Amount [and (2) the aggregate Stated Amount of all outstanding Letters of Credit issued by the Fronting Bank will not exceed $]**.

If notice of the request for the above referenced Letter of Credit has been given by the Borrower previously by telephone, then this notice shall be considered a written confirmation of such telephone notice as required by Section 2.04(d) of the Credit Agreement.

[remainder of page intentionally left blank]

*	Delete for initial Extension of Credit.
**	Insert applicable Fronting Bank L/C Fronting Bank Commitment.

E-2

Very truly yours, [FIRSTENERGY CORP.] [THE CLEVELAND ELECTRIC ILLUMINATING COMPANY] [METROPOLITAN EDISON COMPANY] [OHIO EDISON COMPANY] [PENNSYLVANIA POWER COMPANY] [THE TOLEDO EDISON COMPANY] [AMERICAN TRANSMISSION SYSTEMS, INCORPORATED] [JERSEY CENTRAL POWER & LIGHT COMPANY] [MONONGAHELA POWER COMPANY] [PENNSYLVANIA ELECTRIC COMPANY] [THE POTOMAC EDISON COMPANY] [WEST PENN POWER COMPANY]
By:
	Name:
	Title:

E-3

EXHIBIT F
Form of Opinion of Wendy E. Stark, Associate General Counsel of FE

[LETTERHEAD OF FIRSTENERGY CORP.]

June 17, 2011

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto

Re: Credit Agreement, dated as of June 17, 2011

Ladies and Gentlemen:

I am Associate General Counsel of FirstEnergy Corp., an Ohio corporation (“FE”) and have acted as counsel to FE, and its subsidiaries, The Cleveland Electric Illuminating Company, an Ohio corporation (“CEI”), Metropolitan Edison Company, a Pennsylvania corporation (“Met-Ed”), Ohio Edison Company, an Ohio corporation (“OE”), Pennsylvania Power Company, a Pennsylvania corporation (“Penn”), The Toledo Edison Company, an Ohio corporation (“TE”), American Transmission Systems, Incorporated, an Ohio corporation (“ATSI”), Monongahela Power Company, an Ohio corporation (“MP”), Pennsylvania Electric Company, a Pennsylvania corporation (“Penelec”) and West Penn Power Company, a Pennsylvania corporation (“West-Penn”, and together with FE, CEI, Met-Ed, OE, Penn, TE, ATSI, MP and Penelec, the “Specified Borrowers” and each a “Specified Borrower”), in connection with the transactions contemplated by the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Specified Borrowers, Jersey Central Power & Light Company, The Potomac Edison Company, the banks party thereto, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto and the swing line lenders party thereto. Capitalized terms used herein but not otherwise defined herein shall have the respective meanings assigned to them in the Credit Agreement. This opinion is being furnished to you pursuant to Section 3.01(a)(v) of the Credit Agreement. The Credit Agreement and the Notes are sometimes referred to in this opinion collectively as the “Loan Documents” and each individually as a “Loan Document”.

For purposes of this opinion, I or persons under my supervision and control have reviewed executed originals or copies of executed originals of the Credit Agreement and each Note delivered on the date hereof. I or persons under my supervision and control have also reviewed originals or copies of the Approvals and such corporate records and other documents and matters and have made such investigation of fact and law as I have considered relevant or necessary as a basis for this opinion. In such review, I have assumed the accuracy and completeness of all agreements, documents, records, certificates and other materials submitted to us, the conformity with the originals of all such materials submitted to us as copies (whether or not certified and including facsimiles), the authenticity of the originals of such materials and all materials submitted to us as originals, the genuineness of all signatures (other than those on behalf of the Specified Borrowers) and the legal capacity of all natural persons.

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 2

I have also assumed (a) the due organization, valid existence and good standing under the laws of its jurisdiction of incorporation of each party (other than the Specified Borrowers) to each Loan Document, (b) the corporate or other power and due authorization of each Person (other than the Specified Borrowers) not a natural person to execute, deliver and perform its obligations under each Loan Document to which it is a party, (c) the due execution and delivery of each Loan Document by each party thereto (other than the Specified Borrowers), and (d) that each Loan Document constitutes the valid and binding obligation of each party thereto, enforceable against such party in accordance with its terms. As to various questions of fact relevant to this opinion, I have relied, without independent investigation, upon certificates of public officials, certificates of officers of the Specified Borrowers and representations and warranties of the Specified Borrowers contained in the Credit Agreement.

I am a member of the Bars of the State of Ohio and the Commonwealth of Pennsylvania, and, for purposes of this opinion, I do not hold myself out as an expert on the laws of any jurisdiction other than the laws of the State of Ohio and the Commonwealth of Pennsylvania. I express no opinion herein as to the application or effect of the laws of any jurisdiction other than the laws of the State of Ohio or the Commonwealth of Pennsylvania.

Based on the foregoing and such legal considerations as I have deemed necessary or advisable to express this opinion, I am of the opinion that:

1. Each Specified Borrower is a corporation duly incorporated, validly existing and in good standing under the laws of the jurisdiction of its incorporation, is duly qualified to do business as a foreign corporation in and is in good standing under the laws of each other state in which the ownership of its properties or the conduct of its business makes such qualification necessary, except where the failure to be so qualified would not have a Material Adverse Effect, and has all corporate powers to carry on its business as now conducted and to maintain and operate its property and business.

2. No Governmental Action is or will be required under laws of the State of Ohio or the Commonwealth of Pennsylvania for (a) the due execution or delivery by any Specified Borrower of any Loan Document or the performance by any Specified Borrower of its obligations thereunder or (b) the consummation by any Specified Borrower of any transaction contemplated by the Loan Documents, other than (1) the CEI PUCO Order, the OE PUCO Order, the TE PUCO Order and the ATSI PUCO Order, which are in full force and effect as of the date hereof, (2) such Governmental Action as may be required as a condition to the exercise by any Specified Borrower of its rights under Section 2.07 of the Credit Agreement and (3) such Governmental Action as may be required after the date hereof in connection with the performance by the Specified Borrowers of the general covenants set forth in Sections 5.01(a) and (b) of the Credit Agreement.

F-2

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 3

3. The execution and delivery by each Specified Borrower of the Loan Documents to which it is a party, the performance by such Specified Borrower of its obligations under such Loan Documents, the consummation by such Specified Borrower of the transactions contemplated by any such Loan Document, and compliance by such Specified Borrower with the provisions thereof, will not result in (a) a breach or contravention of any of the provisions of the Organizational Documents of such Specified Borrower, (b) a breach or contravention of any Applicable Law of the State of Ohio or the Commonwealth of Pennsylvania, (c) a breach or contravention of any of the provisions of any indenture, mortgage, lease or any other agreement or instrument to which any Specified Borrower is a party or by which any of its property is bound, or (d) the creation or imposition of any Lien upon any property of such Specified Borrower, except in the case of (c) and (d) to the extent such breach or contravention, or the creation or imposition of any such Lien, would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect with respect to such Specified Borrower.

4. The execution, delivery and performance by each Specified Borrower of each of the Loan Documents to which it is a party are within its corporate powers, have been duly authorized by all necessary corporate action on the part of such Specified Borrower and do not, and will not, require the consent or approval of such Specified Borrower’s shareholders, other than such consents and approvals as have been duly obtained, given or accomplished.

5. The Credit Agreement and each Note delivered on the date hereof by any Specified Borrower has been duly executed and delivered by each Specified Borrower.

Except as disclosed in any Specified Borrower’s Disclosure Documents, there is no pending or, to the best of my knowledge, threatened action or proceeding (including, without limitation, any proceeding relating to or arising out of Environmental Laws) affecting directly such Specified Borrower or any of its Subsidiaries before any court, governmental agency or arbitrator that would reasonably be expected to have a material adverse effect on such Specified Borrower’s ability to perform its obligations under the Loan Documents to which it is a party.

The opinions set forth herein are qualified in their entirety and subject to the following:

A. No examination has been made of, and no opinion is expressed as to the effect of, any zoning ordinance or permit pertaining to the authority of the Specified Borrowers to operate their properties or conduct their businesses.

B. I also express no opinion with respect to (i) the solvency of any Specified Borrower; or (ii) the compliance of the Credit Agreement or any other Loan Document or the transactions contemplated thereby with, or the effect of any of the foregoing with respect to, Federal and state securities Laws, rules and regulations.

F-3

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 4

C. This opinion and the matters addressed herein are as of the date hereof or such earlier date as is specified herein, and I undertake no, and hereby disclaim any, obligation to advise you of any change in any matter set forth herein, whether based on a change in the law, a change in any fact relating to the Specified Borrowers or any other Person, or any other circumstance occurring after the date hereof.

D. I have assumed that no fraud, dishonesty, forgery, coercion, duress or breach of fiduciary duty exists with respect to any of the matters relevant to this opinion.

E. This opinion is limited to the matters expressly set forth herein and no opinion is to be implied or may be inferred beyond the matters expressly stated herein.

F. This opinion is solely for the benefit of the addressees hereof in connection with the transactions contemplated by the Credit Agreement and may not be relied on by the addressees hereof for any other purpose or furnished or quoted to or relied on by any other Person (other than the permitted successors and assigns of such addressees under the Credit Agreement) for any purpose without my prior written consent.

Respectfully submitted,

Wendy E. Stark, Esq.
Associate General Counsel

F-4

EXHIBIT G
Form of Opinion of Akin Gump Strauss Hauer & Feld LLP

June 17, 2011

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto

Re: Credit Agreement, dated as of June 17, 2011

Ladies and Gentlemen:

We have acted as special New York counsel to FirstEnergy Corp., an Ohio corporation (“FE”), and its subsidiaries, The Cleveland Electric Illuminating Company, an Ohio corporation (“CEI”), Metropolitan Edison Company, a Pennsylvania corporation (“Met-Ed”), Ohio Edison Company, an Ohio corporation (“OE”), Pennsylvania Power Company, a Pennsylvania corporation (“Penn”), The Toledo Edison Company, an Ohio corporation (“TE”), American Transmission Systems, Incorporated, an Ohio corporation (“ATSI”), Jersey Central Power & Light Company, a New Jersey corporation (“JCP&L”), Monongahela Power Company, an Ohio corporation (“MP”), Pennsylvania Electric Company, a Pennsylvania corporation (“Penelec”), The Potomac Edison Company, a Maryland and Virginia corporation (“PE”) and West Penn Power Company, a Pennsylvania corporation (together with FE, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec and PE, the “Borrowers” and each a “Borrower”), in connection with the execution and delivery of the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among the Borrowers, the banks party thereto, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto and the swing line lenders party thereto. Capitalized terms used herein but not otherwise defined herein shall have the respective meanings assigned to them in the Credit Agreement. This opinion is being furnished to you at the request of the Borrowers pursuant to Section 3.01(a)(vi) of the Credit Agreement. The Credit Agreement and the Notes are sometimes referred to in this opinion collectively as the “Loan Documents” and each individually as a “Loan Document”.

In connection with this opinion, we have reviewed executed originals or copies of executed originals of the Credit Agreement and the form of the Notes attached thereto. We have also reviewed copies of the Approvals and originals or certified copies of such corporate records of each Borrower and other certificates and documents of officials of each Borrower and certain of their affiliates, public officials and others as we have deemed appropriate for purposes of this opinion, and relied upon them to the extent we deem appropriate. As to various questions of fact relevant to this opinion, we have relied, without independent investigation, upon certificates of public officials, certificates of officers of each Borrower, and representations and warranties of each Borrower contained in the Credit Agreement. In addition, we have made no inquiry of any Borrower or any other Person (including Governmental Authorities) regarding any judgments, orders, decrees, franchises, licenses, certificates, registrations, permits or other public records or agreements to which any Borrower is a party other than those described herein, and our knowledge of any such matters is accordingly limited.

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 2

We have assumed the genuineness of all signatures, the authenticity of all documents submitted to us as originals, and the conformity to authentic original documents of all copies submitted to us as conformed, certified or reproduced copies. We have also assumed (i) the due organization, valid existence and good standing under the laws of its jurisdiction of incorporation of each party to each Loan Document, (ii) the legal capacity of natural persons, (iii) the corporate or other power and due authorization of each Person not a natural person to execute, deliver and perform its obligations under each Loan Document to which it is a party, (iv) the due execution and delivery of each Loan Document by all parties thereto, (v) that each Loan Document constitutes the valid and binding obligation of each party thereto (other than the Borrowers), enforceable against such party in accordance with its terms, (vi) that the execution, delivery and performance by each party to the Loan Documents do not, and will not, require the consent or approval of its shareholders and will not result in (a) a breach or violation of, or conflict with, any of the provisions of its Organizational Documents or (b) a breach or contravention of, or conflict with, any of the provisions of any indenture, mortgage, lease or other agreement or instrument to which it is a party or (c) a breach or violation of, or conflict with, any law (other than, in the case of any Borrower, any Included Law (as defined herein)) or any order, rule, regulation or determination of any Governmental Authority applicable to it (other than, in the case of any Borrower, its Regulatory Order), (vii) that all required Governmental Action (other than, in the case of any Borrower, under any Included Law) for the execution and delivery by each party to any Loan Document, the performance by it of its obligations thereunder or the consummation by it of any transaction contemplated thereby have been obtained or taken and (viii) that the Approvals (other than the Met-Ed FERC Order, the Penn FERC Order, the JCP&L FERC Order, the MP FERC Order, the Penelec FERC Order, the PE FERC Order and the West-Penn FERC Order (collectively, the “Regulatory Orders”)) are in full force and effect. We also note that, under their applicable Regulatory Orders as currently in effect, certain Borrowers may not borrow up to their respective full Borrower Sublimits. Accordingly, we have assumed that Borrowings by any Borrower shall not at any time exceed amounts authorized by its Regulatory Order as then in effect.

Based upon the foregoing and subject to the assumptions, exceptions, qualifications and limitations set forth herein, we are of the opinion that:

1. No Governmental Action is or will be required under any Included Law for the due execution and delivery by each Borrower of each Loan Document to which it is a party or the performance by it of its obligations thereunder, other than (i) the Regulatory Orders, each of which is in full force and effect as of the date hereof, and (ii) such Governmental Action as may be required after the date hereof in connection with the performance by such Borrower of the general covenants set forth in Sections 5.01(a) and (b) of the Credit Agreement.

G-2

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 3

2.	The execution and delivery by each Borrower of each Loan Document to which it is a party do not, and the performance by such Borrower of its obligations under each such Loan Document will not, result in a breach or violation of any Included Law or any of the Regulatory Orders.
3.	The Credit Agreement constitutes a valid and binding obligation of each Borrower, enforceable against each Borrower in accordance with its terms.
4.	Each Note, when properly completed and executed by the applicable Borrower and delivered in exchange for value, will constitute a valid and binding obligation of such Borrower, enforceable against such Borrower in accordance with its terms.

The opinions set forth herein are qualified in their entirety and subject to the following:

A. We express no opinion as to the Laws (as defined below) of any jurisdiction other than the Included Laws. We have made no special investigation or review of any published constitutions, treaties, laws, rules or regulations or judicial or administrative decisions (“Laws”), other than a review of (i) the Laws of the State of New York, and (ii) the Federal Laws of the United States of America. For purposes of this opinion, the term “Included Laws” means the items described in clauses (i) and (ii) of the preceding sentence that are, in our experience, normally applicable to transactions of the type contemplated by the Loan Documents. The term Included Laws specifically excludes (i) Laws of any counties, cities, towns, municipalities and special political subdivisions and any agencies thereof; (ii) zoning, land use, building and construction Laws; (iii) Federal Reserve Board margin regulations; and (iv) any environmental, labor, tax, pension, employee benefit, antiterrorism, money laundering, insurance, antitrust, securities or intellectual property Laws.

B. When used in this opinion, the phrases “known to us”, “to our knowledge” and similar phrases (i) mean the conscious awareness of facts or other information by (a) the lawyer in our firm who signed this letter, (b) any lawyer in our firm actively involved in negotiating and preparing the Loan Documents and (c) solely as to information relevant to a particular opinion, issue or confirmation regarding a particular factual matter, any lawyer in our firm who is primarily responsible for providing the response concerning that particular opinion, issue or confirmation and (ii) do not require or imply (a) any examination of this firm’s, such lawyer’s or any other Person’s files, (b) that any inquiry be made of the client, any lawyer (other than the lawyers described above), or any other Person or (c) any review or examination of any agreements, documents, certificates, instruments or other papers (including, but not limited to, the exhibits and schedules to the Loan Documents and the various papers referred to in or contemplated by the Loan Documents and the respective exhibits and schedules thereto) other than the Loan Documents.

G-3

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 4

C. The matters expressed in this opinion are subject to and qualified and limited by (i) applicable bankruptcy, insolvency, fraudulent transfer and conveyance, reorganization, moratorium and similar laws affecting creditors’ rights and remedies generally from time to time in effect; (ii) general principles of equity (regardless of whether enforcement is sought in a proceeding at law or in equity); (iii) principles of commercial reasonableness and unconscionability and an implied covenant of good faith and fair dealing; (iv) the power of the courts to award damages in lieu of equitable remedies; and (v) securities Laws and public policy underlying such Laws with respect to rights to indemnification and contribution. Although it appears that the requirements of Section 5-1401 of the New York General Obligations Law have been met, we express no opinion on whether the choice of law provision in Section 8.09 of the Credit Agreement or in each Note would raise any issues under the United States constitution or in equity that would affect whether courts in New York would enforce the choice of New York law to govern the Credit Agreement or such Note. We have also assumed that the choice of law of the State of New York as the governing law of the Credit Agreement and each Note would not result in a violation of an important public policy of another state having greater contacts with the transactions contemplated by the Loan Documents than the State of New York.

D. The opinions expressed herein are as of the date hereof or such earlier date as is specified herein, and we undertake no, and hereby disclaim any, obligation to advise you of any change in any matter set forth herein, whether based on a change in the law, a change in any fact relating to any Borrower or any other Person, or any other circumstance occurring after the date hereof. This opinion is limited to the matters expressly stated herein and no opinions are to be inferred or may be implied beyond the opinions expressly set forth herein.

E. We have assumed that no fraud, dishonesty, forgery, coercion, duress or breach of fiduciary duty exists with respect to any of the matters relevant to the opinions expressed in this letter.

F. We express no opinion as to (i) the compliance of the transactions contemplated by the Loan Documents with any Laws applicable to any Person other than the Borrowers; (ii) the financial condition or solvency of any Borrower; (iii) the ability (financial or otherwise) of any Borrower or any other Person to meet its obligations under the Loan Documents; (iv) the compliance of the Loan Documents or the transactions contemplated thereby with, or the effect on any of the opinions expressed herein of, the antifraud provisions of Federal and state securities Laws; (v) the conformity of the Loan Document to any term sheet or commitment letter; or (vi) any provision of any Loan Document which would, to the extent not permitted by applicable Law, restrict, waive access to or vary legal or equitable remedies or defenses (including, but not limited to, a right to notice of and hearing on matters relating to prejudgment remedies, service of process, proper jurisdiction and venue, forum non conveniens and the right to trial by jury) or the right to collect damages (including, but not limited to, actual, consequential, special, indirect, incidental, exemplary and punitive damages).

G-4

To the Banks party to the within-mentioned Credit Agreement,
The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder,
the fronting banks party thereto and the swing line lenders party thereto
June 17, 2011
Page 5

G. For purposes of this letter, the phrase “transactions of the type contemplated by the Loan Documents” and similar phrases mean (i) the making of Advances and the issuance of Letters of Credit by the banks party to the Credit Agreement and (ii) the performance by the Borrowers of their respective obligations under the Loan Documents.

H. This letter is solely for your benefit, and no other Person (other than your permitted successors and assigns under the Credit Agreement) shall be entitled to rely upon this opinion. Without our prior written consent, this opinion may not be quoted in whole or in part or otherwise referred to in any document and may not be furnished or otherwise disclosed to or used by any other Person, except for (i) delivery of copies hereof to counsel for the addressees hereof and (ii) inclusion of copies hereof in a closing file relating to the Credit Agreement.

Very truly yours,

AKIN, GUMP, STRAUSS, HAUER & FELD, L.L.P.

G-5

EXHIBIT H
Form of Opinion of
Special New York Counsel to the Administrative Agent

June 17, 2011

The Royal Bank of Scotland plc, as
administrative agent, the fronting banks, the
swing line lenders and the lenders party to
the Credit Agreement defined below

Re: FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company

Ladies and Gentlemen:

We have acted as special New York counsel to The Royal Bank of Scotland plc, individually and as administrative agent (the “Administrative Agent”), in connection with the preparation, execution and delivery of the Credit Agreement, dated as of June 17, 2011 (the “Credit Agreement”), among FirstEnergy Corp., an Ohio corporation (“FE”), The Cleveland Electric Illuminating Company, an Ohio corporation (“CEI”), Metropolitan Edison Company, a Pennsylvania corporation (“Met-Ed”), Ohio Edison Company, an Ohio corporation (“OE”), Pennsylvania Power Company, a Pennsylvania corporation (“Penn”), The Toledo Edison Company, an Ohio corporation (“TE”), American Transmission Systems, Incorporated, a an Ohio corporation (“ATSI”), Jersey Central Power & Light Company, a New Jersey corporation (“JCP&L”), Monongahela Power Company, an Ohio corporation (“MP”), Pennsylvania Electric Company, a Pennsylvania corporation (“Penelec”), The Potomac Edison Company, a Maryland and Virginia corporation (“PE”) and West Penn Power Company, a Pennsylvania corporation (“West-Penn”, and together with FE, CEI, Met-Ed, OE, Penn, TE, ATSI, JCP&L, MP, Penelec and PE, the “Borrowers” and each a “Borrower”), The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto, the swing line lenders party thereto and the Banks party thereto. Unless otherwise defined herein, terms defined in the Credit Agreement are used herein as therein defined. This opinion is being delivered pursuant to Section 3.01(a)(vii) of the Credit Agreement.

In that connection, we have examined (i) counterparts of the Credit Agreement, executed by the Borrowers, the Banks, the Swing Line Lenders, the Administrative Agent and the Fronting Banks, (ii) a form of the Notes and (iii) the other documents furnished to the Administrative Agent pursuant to Section 3.01(a) of the Credit Agreement, including (without limitation) the opinions of (i) Wendy E. Stark, Associate General Counsel of FE, counsel to the Borrowers, (ii) DLA Piper LLP (US), special counsel to PE, (iii) Hunton & Williams LLP, special counsel to PE, (iv) Morgan, Lewis & Bockius LLP, special counsel to JCP&L, and (v) Akin Gump Strauss Hauer & Feld LLP, special counsel to the Borrowers (such opinions referred to hereinafter, collectively, as the “Borrowers’ Counsel Opinions”).

In our examination of the documents referred to above, we have assumed the authenticity of all such documents submitted to us as originals, the genuineness of all signatures, the due authority of the parties executing such documents and the conformity to the originals of all such documents submitted to us as copies. We have also assumed that each of the Banks, the Swing Line Lenders, the Fronting Banks and the Administrative Agent have duly executed and delivered, with all necessary power and authority (corporate and otherwise), the Credit Agreement. We have further assumed that you have evaluated, and are satisfied with, the creditworthiness of the Borrowers and the business and financial terms evidenced by the Loan Documents.

To the extent that our opinions expressed below involve conclusions as to matters governed by law other than the law of the State of New York and the Federal law of the United States, we have relied upon the Borrowers’ Counsel Opinions and have assumed without independent investigation the correctness of the matters set forth therein, our opinions expressed below being subject to the assumptions, qualifications and limitations set forth in the Borrowers’ Counsel Opinions. As to matters of fact, we have relied solely upon the documents we have examined. We note that we do not represent the Borrowers, and accordingly, are not privy to the nature or character of their business. Accordingly, we have assumed that the Borrowers are subject only to statutes, rules, regulations, judgments, orders and other requirements of law generally applicable to corporations doing business in the State of New York.

Based upon the foregoing, and subject to the qualifications set forth below, we are of the opinion that:

(i)

The Credit Agreement is, and each of the Notes when executed and delivered for value received will be, the legal, valid and binding obligation of each Borrower that is a party thereto enforceable against such Borrower in accordance with their respective terms.

(ii)

While we have not independently considered the matters covered by the Borrowers’ Counsel Opinions to the extent necessary to enable us to express the conclusions stated therein, each of the Borrowers’ Counsel Opinions and the other documents furnished to the Administrative Agent pursuant to Section 3.01(a) of the Credit Agreement are substantially responsive to the corresponding requirements set forth in Section 3.01(a) of the Credit Agreement pursuant to which the same have been delivered.

Our opinions are subject to the following qualifications:

(a)	Our opinion in paragraph (i) above is subject to the effect of any applicable bankruptcy, insolvency, reorganization, fraudulent conveyance, moratorium or similar law affecting creditors’ rights generally.
(b)	Our opinion in paragraph (i) above is subject to the effect of general principles of equity, including (without limitation) concepts of materiality, reasonableness, good faith and fair dealing (regardless of whether considered in a proceeding in equity or at law).

H-2

(c)	We note further that, in addition to the application of equitable principles described above, courts have imposed an obligation on contracting parties to act reasonably and in good faith in the exercise of their contractual rights and remedies, and may also apply public policy considerations in limiting the right of parties seeking to obtain indemnification under circumstances where the conduct of such parties in the circumstances in question is determined to have constituted negligence.
(d)	We express no opinion herein as to (i) Section 8.06 of the Credit Agreement, (ii) the enforceability of provisions purporting to grant to a party conclusive rights of determination, (iii) the availability of specific performance or other equitable remedies, (iv) the enforceability of rights to indemnity under Federal or state securities laws and (v) the enforceability of waivers by parties of their respective rights and remedies under law.
(e)	Our opinion in paragraph (i) is limited to the law of the State of New York and the Federal law of the United States, and we do not express any opinion herein concerning any other law. Without limiting the generality of the foregoing, we express no opinion as to the effect of the law of any jurisdiction other than the State of New York wherein any Lender may be located or wherein enforcement of the Credit Agreement or the Notes may be sought that limits the rates of interest legally chargeable or collectible.
(f)	In connection with any provision of the Credit Agreement or the Notes whereby any Borrower submits to the jurisdiction of any court of competent jurisdiction, we note the limitations of 28 U.S.C. §§1331 and 1332 on Federal court of jurisdiction.

The foregoing opinion is solely for your benefit and may not be relied upon by any other Person other than any Person that may become a Lender under the Credit Agreement after the date hereof.

Very truly yours,

MEO:kty:mg

H-3

EX-12

EXHIBIT 12

FIRSTENERGY CORP.

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	216	$	405
Interest and other charges, before reduction for amounts capitalized and deferred		496		421
Provision for income taxes		179		245
Interest element of rentals charged to income (a)		74		77
Earnings as defined	$	965	$	1,148
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	496	$	421
Interest element of rentals charged to income (a)		74		77
Fixed charges as defined	$	570	$	498
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		1.69		2.31

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

EXHIBIT 12

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	56	$	214
Interest and other charges, before reduction for amounts capitalized and deferred		108		106
Provision for income taxes		24		113
Interest element of rentals charged to income (a)		44		46
Earnings as defined	$	232	$	479
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	108	$	106
Interest element of rentals charged to income (a)		44		46
Fixed charges as defined	$	152	$	152
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		1.53		3.15

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EXHIBIT 12

OHIO EDISON COMPANY

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	68,765	$	73,484
Interest and other charges, before reduction for amounts capitalized and deferred		44,156		44,465
Provision for income taxes		34,029		31,465
Interest element of rentals charged to income (a)		29,048		32,386
Earnings as defined	$	175,998	$	181,800
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	44,156	$	44,465
Interest element of rentals charged to income (a)		29,048		32,386
Fixed charges as defined	$	73,204	$	76,851
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		2.40		2.37

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EXHIBIT 12

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	35,050	$	35,918
Interest and other charges, before reduction for amounts capitalized and deferred		65,213		66,883
Provision for income taxes		10,645		19,628
Interest element of rentals charged to income (a)		889		896
Earnings as defined	$	111,797	$	123,325
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	65,213	$	66,883
Interest element of rentals charged to income (a)		889		896
Fixed charges as defined	$	66,102	$	67,779
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		1.69		1.82

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EXHIBIT 12

THE TOLEDO EDISON COMPANY

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	17,408	$	14,725
Interest and other charges, before reduction for amounts capitalized and deferred		20,858		20,942
Provision for income taxes		3,164		6,330
Interest element of rentals charged to income (a)		14,586		16,139
Earnings as defined	$	56,016	$	58,136
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	20,858	$	20,942
Interest element of rentals charged to income (a)		14,586		16,139
Fixed charges as defined	$	35,444	$	37,081
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		1.58		1.57

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EXHIBIT 12

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	61,314	$	79,119
Interest and other charges, before reduction for amounts capitalized and deferred		61,839		60,213
Provision for income taxes		48,461		57,051
Interest element of rentals charged to income (a)		2,967		3,283
Earnings as defined	$	174,581	$	199,666
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	61,839	$	60,213
Interest element of rentals charged to income (a)		2,967		3,283
Fixed charges as defined	$	64,806	$	63,496
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		2.69		3.14

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EXHIBIT 12

METROPOLITAN EDISON COMPANY

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	39,365	$	29,424
Interest and other charges, before reduction for amounts capitalized and deferred		26,187		26,775
Provision for income taxes		19,232		20,884
Interest element of rentals charged to income (a)		719		1,078
Earnings as defined	$	85,503	$	78,161
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	26,187	$	26,775
Interest element of rentals charged to income (a)		719		1,078
Fixed charges as defined	$	26,906	$	27,853
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		3.18		2.81

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EXHIBIT 12

PENNSYLVANIA ELECTRIC COMPANY

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Six Months Ended
	June 30
	2011		2010
	(Dollars in thousands)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	32,024	$	30,273
Interest and other charges, before reduction for amounts capitalized and deferred		34,595		34,920
Provision for income taxes		25,356		22,969
Interest element of rentals charged to income (a)		1,702		1,668
Earnings as defined	$	93,677	$	89,830
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	34,595	$	34,920
Interest element of rentals charged to income (a)		1,702		1,668
Fixed charges as defined	$	36,297	$	36,588
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES		2.58		2.46

(a) Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined

EX-31.1

Exhibit 31.1

Certification

I, Anthony J. Alexander, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Anthony J. Alexander

Chief Executive Officer

Exhibit 31.1

Certification

I, Donald R. Schneider, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Solutions Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Donald R. Schneider

Chief Executive Officer

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-Q of Ohio Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Charles E. Jones

Chief Executive Officer

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-Q of The Cleveland Electric Illuminating Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Charles E. Jones

Chief Executive Officer

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-Q of The Toledo Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Charles E. Jones

Chief Executive Officer

Exhibit 31.1

Certification

I, Donald M. Lynch, certify that:

1.	I have reviewed this report on Form 10-Q of Jersey Central Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Donald M. Lynch

Chief Executive Officer

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-Q of Metropolitan Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Charles E. Jones

Chief Executive Officer

Exhibit 31.1

Certification

I, Charles E. Jones, certify that:

1.	I have reviewed this report on Form 10-Q of Pennsylvania Electric Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Charles E. Jones

Chief Executive Officer

EX-31.2

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of FirstEnergy Solutions Corp.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of Ohio Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of The Cleveland Electric Illuminating Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of The Toledo Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

Exhibit 31.2

Certification

I, K. Jon Taylor, certify that:

1.	I have reviewed this report on Form 10-Q of Jersey Central Power & Light Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

K. Jon Taylor

Chief Financial Officer

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of Metropolitan Edison Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

Exhibit 31.2

Certification

I, Mark T. Clark, certify that:

1.	I have reviewed this report on Form 10-Q of Pennsylvania Electric Company;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 2, 2011

Mark T. Clark

Chief Financial Officer

EX-32

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Corp. (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Anthony J. Alexander

Chief Executive Officer

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Solutions Corp. (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Donald R. Schneider

President

(Chief Executive Officer)

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of Ohio Edison Company (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Charles E. Jones

President

(Chief Executive Officer)

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of The Cleveland Electric Illuminating Company (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Charles E. Jones

President

(Chief Executive Officer)

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of The Toledo Edison Company (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Charles E. Jones

President

(Chief Executive Officer)

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of Jersey Central Power & Light Company (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his or her knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Donald M. Lynch

President

(Chief Executive Officer)

K. Jon Taylor

Controller

(Chief Financial Officer)

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of Metropolitan Edison Company (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Charles E. Jones

President

(Chief Executive Officer)

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

Exhibit 32

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350

In connection with the Report of Pennsylvania Electric Company (“Company”) on Form 10-Q for the period ending June 30, 2011 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Charles E. Jones

President

(Chief Executive Officer)

Mark T. Clark

Chief Financial Officer

Date: August 2, 2011

XML



Derivative Instruments (Details) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Fair value of commodity derivatives
Economic Hedges Derivative assets	$ 404	$ 268
Economic Hedges Derivative liabilities	896	714
Power Contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	88	38
Power Contracts | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	102	40
Power Contracts | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	210	96
Power Contracts | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	274	209
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	0	0
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	0
FTRs | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	13	0
FTRs | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	7	0
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	205	238
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	71	119
NUGs | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	4	3
NUGs | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	317	229
Interest Rate Swap | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	0	0
Interest Rate Swap | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	0
Interest Rate Swap | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	4	0
Interest Rate Swap | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	5	0
Other | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	0	0
Other | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	0
Other | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	10
Other | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	$ 0	$ 0

XML



Consolidated Statements of Income (Unaudited) (Parenthetical) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements of Income [Abstract]
Excise tax collections	$ 116	$ 99	$ 235	$ 208

XML



Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
NET INCOME	$ 171,000	$ 256,000	$ 216,000	$ 405,000
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	111,000	17,000	130,000	30,000
Unrealized gain on derivative hedges	17,000	6,000	11,000	10,000
Change in unrealized gain on available-for-sale securities	10,000	6,000	19,000	12,000
Other comprehensive income	138,000	29,000	160,000	52,000
Income tax expense (benefit) related to other comprehensive income	53,000	9,000	54,000	16,000
Other comprehensive income, net of tax	85,000	20,000	106,000	36,000
COMPREHENSIVE INCOME	256,000	276,000	322,000	441,000
COMPREHENSIVE INCOME/LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST	(10,000)	(9,000)	(15,000)	(15,000)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	266,000	285,000	337,000	456,000
FES
NET INCOME	20,000	134,000	56,000	214,000
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	1,000	1,000	3,000	(9,000)
Unrealized gain on derivative hedges	14,000	3,000	5,000	4,000
Change in unrealized gain on available-for-sale securities	8,000	6,000	15,000	11,000
Other comprehensive income	23,000	10,000	23,000	6,000
Income tax expense (benefit) related to other comprehensive income	10,000	4,000	8,000	2,000
Other comprehensive income, net of tax	13,000	6,000	15,000	4,000
COMPREHENSIVE INCOME	33,000	140,000	71,000	218,000
OE
NET INCOME	38,625	37,323	68,765	73,484
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	1,122	322	1,461	4,337
Change in unrealized gain on available-for-sale securities	1,591	520	1,569	811
Other comprehensive income	2,713	842	3,030	5,148
Income tax expense (benefit) related to other comprehensive income	386	(26)	(1,110)	667
Other comprehensive income, net of tax	2,327	868	4,140	4,481
COMPREHENSIVE INCOME	40,952	38,191	72,905	77,965
COMPREHENSIVE INCOME/LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST	114	130	230	262
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	40,838	38,061	72,675	77,703
CEI
NET INCOME	21,849	21,922	35,050	35,918
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	2,975	3,228	5,942	(19,357)
Income tax expense (benefit) related to other comprehensive income	860	976	398	(7,301)
Other comprehensive income, net of tax	2,115	2,252	5,544	(12,056)
COMPREHENSIVE INCOME	23,964	24,174	40,594	23,862
COMPREHENSIVE INCOME/LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST	309	366	675	785
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	23,655	23,808	39,919	23,077
TE
NET INCOME	11,561	7,216	17,408	14,725
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	575	714	1,167	1,010
Change in unrealized gain on available-for-sale securities	754	(330)	2,059	39
Other comprehensive income	1,329	384	3,226	1,049
Income tax expense (benefit) related to other comprehensive income	351	65	685	235
Other comprehensive income, net of tax	978	319	2,541	814
COMPREHENSIVE INCOME	12,539	7,535	19,949	15,539
COMPREHENSIVE INCOME/LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST	2	2	4	5
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	12,537	7,533	19,945	15,534
JCP&L
NET INCOME	41,761	49,893	61,314	79,119
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	4,290	4,135	8,511	20,063
Unrealized gain on derivative hedges	69	69	138	138
Other comprehensive income	4,359	4,204	8,649	20,201
Income tax expense (benefit) related to other comprehensive income	1,612	1,441	3,202	7,999
Other comprehensive income, net of tax	2,747	2,763	5,447	12,202
COMPREHENSIVE INCOME	44,508	52,656	66,761	91,321
Met-Ed
NET INCOME	16,778	17,109	39,365	29,424
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	2,227	2,162	4,190	11,871
Unrealized gain on derivative hedges	84	84	168	168
Other comprehensive income	2,311	2,246	4,358	12,039
Income tax expense (benefit) related to other comprehensive income	869	724	1,632	4,901
Other comprehensive income, net of tax	1,442	1,522	2,726	7,138
COMPREHENSIVE INCOME	18,220	18,631	42,091	36,562
Penelec
NET INCOME	14,718	12,974	32,024	30,273
OTHER COMPREHENSIVE INCOME:
Pension and other postretirement benefits	1,890	1,830	3,475	10,377
Unrealized gain on derivative hedges	17	16	33	32
Other comprehensive income	1,907	1,846	3,508	10,409
Income tax expense (benefit) related to other comprehensive income	678	483	1,233	3,767
Other comprehensive income, net of tax	1,229	1,363	2,275	6,642
COMPREHENSIVE INCOME	$ 15,947	$ 14,337	$ 34,299	$ 36,915

XML



Supplemental Guarantor Information (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
Consolidating Statements of Income
Revenues	$ 4,060,000,000	[1]	$ 3,139,000,000	[1]	$ 7,636,000,000	[1]	$ 6,438,000,000	[1]
EXPENSES:
Fuel	635,000,000		350,000,000		1,088,000,000		684,000,000
Purchased power	1,220,000,000		1,063,000,000		2,406,000,000		2,301,000,000
Other operating expenses	1,105,000,000		673,000,000		2,138,000,000		1,374,000,000
Provision for depreciation	282,000,000		190,000,000		502,000,000		383,000,000
General taxes	242,000,000		176,000,000		479,000,000		381,000,000
Total expenses	3,574,000,000		2,613,000,000		6,835,000,000		5,496,000,000
OPERATING INCOME	486,000,000		526,000,000		801,000,000		942,000,000
OTHER INCOME (EXPENSE):
Investment income	31,000,000		31,000,000		52,000,000		47,000,000
Interest expense	(265,000,000)		(207,000,000)		(496,000,000)		(420,000,000)
Capitalized interest	20,000,000		40,000,000		38,000,000		81,000,000
Total other expense	(214,000,000)		(136,000,000)		(406,000,000)		(292,000,000)
INCOME (LOSS) BEFORE INCOME TAXES	272,000,000		390,000,000		395,000,000		650,000,000
INCOME TAXES	101,000,000		134,000,000		179,000,000		245,000,000
NET INCOME	171,000,000		256,000,000		216,000,000		405,000,000
FES Corp
Consolidating Statements of Income
Revenues	1,275,000,000		1,307,000,000		2,642,000,000		2,674,000,000
EXPENSES:
Fuel	6,000,000		7,000,000		7,000,000		12,000,000
Other operating expenses	159,000,000		81,000,000		321,000,000		134,000,000
Provision for depreciation	1,000,000		1,000,000		2,000,000		2,000,000
General taxes	16,000,000		6,000,000		27,000,000		11,000,000
Total expenses	1,416,000,000		1,318,000,000		3,073,000,000		2,800,000,000
OPERATING INCOME	(141,000,000)		(11,000,000)		(431,000,000)		(126,000,000)
OTHER INCOME (EXPENSE):
Investment income			2,000,000		1,000,000		4,000,000
Miscellaneous income, including net income from equity investees	123,000,000		151,000,000		356,000,000		317,000,000
Interest expense	(24,000,000)		(24,000,000)		(48,000,000)		(48,000,000)
Total other expense	99,000,000		129,000,000		308,000,000		273,000,000
INCOME (LOSS) BEFORE INCOME TAXES	(42,000,000)		118,000,000		(123,000,000)		147,000,000
INCOME TAXES	(62,000,000)		(16,000,000)		(179,000,000)		(67,000,000)
NET INCOME	20,000,000		134,000,000		56,000,000		214,000,000
Affiliates | FES Corp
EXPENSES:
Purchased power	902,000,000		913,000,000		2,087,000,000		1,881,000,000
OTHER INCOME (EXPENSE):
Interest expense					(1,000,000)
Non-Affiliates | FES Corp
EXPENSES:
Purchased power	332,000,000		310,000,000		629,000,000		760,000,000
FGCO
Consolidating Statements of Income
Revenues	535,000,000		581,000,000		1,278,000,000		1,149,000,000
EXPENSES:
Fuel	266,000,000		302,000,000		560,000,000		582,000,000
Other operating expenses	115,000,000		94,000,000		233,000,000		194,000,000
Provision for depreciation	32,000,000		27,000,000		63,000,000		54,000,000
General taxes	8,000,000		9,000,000		19,000,000		24,000,000
Impairment of long-lived assets	7,000,000				20,000,000		2,000,000
Total expenses	434,000,000		440,000,000		903,000,000		868,000,000
OPERATING INCOME	101,000,000		141,000,000		375,000,000		281,000,000
OTHER INCOME (EXPENSE):
Investment income	1,000,000				1,000,000
Miscellaneous income, including net income from equity investees	1,000,000		1,000,000		2,000,000		1,000,000
Interest expense	(28,000,000)		(28,000,000)		(56,000,000)		(54,000,000)
Capitalized interest	5,000,000		20,000,000		10,000,000		36,000,000
Total other expense	(22,000,000)		(9,000,000)		(44,000,000)		(21,000,000)
INCOME (LOSS) BEFORE INCOME TAXES	79,000,000		132,000,000		331,000,000		260,000,000
INCOME TAXES	25,000,000		48,000,000		119,000,000		97,000,000
NET INCOME	54,000,000		84,000,000		212,000,000		163,000,000
Affiliates | FGCO
EXPENSES:
Purchased power	9,000,000		8,000,000		11,000,000		12,000,000
OTHER INCOME (EXPENSE):
Interest expense	(1,000,000)		(2,000,000)		(1,000,000)		(4,000,000)
Non-Affiliates | FGCO
EXPENSES:
Purchased power	(3,000,000)				(3,000,000)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues	393,000,000		339,000,000		862,000,000		765,000,000
EXPENSES:
Fuel	44,000,000		34,000,000		92,000,000		77,000,000
Other operating expenses	143,000,000		117,000,000		331,000,000		256,000,000
Provision for depreciation	36,000,000		36,000,000		74,000,000		73,000,000
General taxes	6,000,000		7,000,000		14,000,000		14,000,000
Total expenses	294,000,000		243,000,000		645,000,000		531,000,000
OPERATING INCOME	99,000,000		96,000,000		217,000,000		234,000,000
OTHER INCOME (EXPENSE):
Investment income	15,000,000		11,000,000		20,000,000		10,000,000
Interest expense	(16,000,000)		(15,000,000)		(33,000,000)		(31,000,000)
Capitalized interest	5,000,000		4,000,000		10,000,000		8,000,000
Total other expense	3,000,000				(4,000,000)		(14,000,000)
INCOME (LOSS) BEFORE INCOME TAXES	102,000,000		96,000,000		213,000,000		220,000,000
INCOME TAXES	38,000,000		34,000,000		80,000,000		78,000,000
NET INCOME	64,000,000		62,000,000		133,000,000		142,000,000
Affiliates | Nuclear Generation Corp
EXPENSES:
Purchased power	65,000,000		49,000,000		134,000,000		111,000,000
OTHER INCOME (EXPENSE):
Interest expense	(1,000,000)				(1,000,000)		(1,000,000)
Eliminations
Consolidating Statements of Income
Revenues	(911,000,000)		(901,000,000)		(2,098,000,000)		(1,874,000,000)
EXPENSES:
Other operating expenses	12,000,000		12,000,000		25,000,000		24,000,000
Provision for depreciation	(1,000,000)		(1,000,000)		(3,000,000)		(3,000,000)
Total expenses	(900,000,000)		(890,000,000)		(2,076,000,000)		(1,853,000,000)
OPERATING INCOME	(11,000,000)		(11,000,000)		(22,000,000)		(21,000,000)
OTHER INCOME (EXPENSE):
Miscellaneous income, including net income from equity investees	(120,000,000)		(148,000,000)		(350,000,000)		(311,000,000)
Interest expense	16,000,000		16,000,000		32,000,000		32,000,000
Total other expense	(104,000,000)		(132,000,000)		(318,000,000)		(279,000,000)
INCOME (LOSS) BEFORE INCOME TAXES	(115,000,000)		(143,000,000)		(340,000,000)		(300,000,000)
INCOME TAXES	3,000,000		3,000,000		5,000,000		5,000,000
NET INCOME	(118,000,000)		(146,000,000)		(345,000,000)		(305,000,000)
Affiliates | Eliminations
EXPENSES:
Purchased power	(911,000,000)		(901,000,000)		(2,098,000,000)		(1,874,000,000)
FES
Consolidating Statements of Income
Revenues	1,292,000,000		1,326,000,000		2,684,000,000		2,714,000,000
EXPENSES:
Fuel	316,000,000		343,000,000		659,000,000		671,000,000
Other operating expenses	429,000,000		304,000,000		910,000,000		608,000,000
Provision for depreciation	68,000,000		63,000,000		136,000,000		126,000,000
General taxes	30,000,000		22,000,000		60,000,000		49,000,000
Impairment of long-lived assets	7,000,000				20,000,000		2,000,000
Total expenses	1,244,000,000		1,111,000,000		2,545,000,000		2,346,000,000
OPERATING INCOME	48,000,000		215,000,000		139,000,000		368,000,000
OTHER INCOME (EXPENSE):
Investment income	16,000,000		13,000,000		22,000,000		14,000,000
Miscellaneous income, including net income from equity investees	4,000,000		4,000,000		8,000,000		7,000,000
Interest expense	(52,000,000)		(51,000,000)		(105,000,000)		(101,000,000)
Capitalized interest	10,000,000		24,000,000		20,000,000		44,000,000
Total other expense	(24,000,000)		(12,000,000)		(58,000,000)		(41,000,000)
INCOME (LOSS) BEFORE INCOME TAXES	24,000,000		203,000,000		81,000,000		327,000,000
INCOME TAXES	4,000,000		69,000,000		25,000,000		113,000,000
NET INCOME	20,000,000		134,000,000		56,000,000		214,000,000
FES | Affiliates
EXPENSES:
Purchased power	65,000,000		69,000,000		134,000,000		130,000,000
OTHER INCOME (EXPENSE):
Interest expense	(2,000,000)		(2,000,000)		(3,000,000)		(5,000,000)
FES | Non-Affiliates
EXPENSES:
Purchased power	$ 329,000,000		$ 310,000,000		$ 626,000,000		$ 760,000,000

[1] *Includes excise tax collections of $116 million and $99 million in the three months ended June 30,2011 and 2010, respectively, and $235 million and $208 million in the six months ended June 30, 2011 and 2010, respectively.

XML



Derivative Instruments (Details 3) (USD $) In Millions	3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011 NUGs	Jun. 30, 2010 NUGs	Jun. 30, 2011 NUGs	Jun. 30, 2010 NUGs	Jun. 30, 2011 Other	Jun. 30, 2011 Other	Jun. 30, 2010 Other	Mar. 31, 2010 Other
Reconciliation of changes in the fair value of certain contracts that are deferred
Outstanding net asset (liability), Beginning Balance	$ (362)	$ (580)	$ (335)	$ (425)	$ (362)	$ (590)	$ (345)	$ (444)		$ 10	$ 19	$ 10
Additions/Change in value of existing contracts	(145)	(35)	(234)	(259)	(147)	(35)	(236)	(259)	2	2
Settled contracts	62	68	124	137	62	68	134	146		(10)	(9)
Outstanding net asset (liability), Ending Balance	$ (445)	$ (547)	$ (445)	$ (547)	$ (447)	$ (557)	$ (447)	$ (557)	$ 2	$ 2	$ 10	$ 10

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Supplemental Guarantor Information

6 Months Ended

Jun. 30, 2011

Supplemental Guarantor Information [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

16. SUPPLEMENTAL GUARANTOR INFORMATION

In 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 six month periods ended June 30, 2011 and 2010, consolidating balance sheets as of June 30, 2011 and December 31, 2010 and consolidating statements of cash flows for the three months ended June 30, 2011 and 2010 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.

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	1,275		$	535		$	393		$	(911	)	$	1,292
EXPENSES:
Fuel		6			266			44			—			316
Purchased power from affiliates		902			9			65			(911	)		65
Purchased power from non-affiliates		332			(3	)		—			—			329
Other operating expenses		159			115			143			12			429
Provision for depreciation		1			32			36			(1	)		68
General taxes		16			8			6			—			30
Impairment of long-lived assets		—			7			—			—			7
Total expenses		1,416			434			294			(900	)		1,244
OPERATING INCOME (LOSS)		(141	)		101			99			(11	)		48
OTHER INCOME (EXPENSE):
Investment income		—			1			15			—			16
Miscellaneous income (expense), including net income from equity investees		123			1			—			(120	)		4
Interest expense — affiliates		—			(1	)		(1	)		—			(2	)
Interest expense — other		(24	)		(28	)		(16	)		16			(52	)
Capitalized interest		—			5			5			—			10
Total other income (expense)		99			(22	)		3			(104	)		(24	)
INCOME (LOSS) BEFORE INCOME TAXES		(42	)		79			102			(115	)		24
INCOME TAXES (BENEFITS)		(62	)		25			38			3			4
NET INCOME	$	20		$	54		$	64		$	(118	)	$	20

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	2,642		$	1,278		$	862		$	(2,098	)	$	2,684
EXPENSES:
Fuel		7			560			92			—			659
Purchased power from affiliates		2,087			11			134			(2,098	)		134
Purchased power from non-affiliates		629			(3	)		—			—			626
Other operating expenses		321			233			331			25			910
Provision for depreciation		2			63			74			(3	)		136
General taxes		27			19			14			—			60
Impairment charges of long-lived assets		—			20			—			—			20
Total expenses		3,073			903			645			(2,076	)		2,545
OPERATING INCOME (LOSS)		(431	)		375			217			(22	)		139
OTHER INCOME (EXPENSE):
Investment income		1			1			20			—			22
Miscellaneous income, including net income from equity investees		356			2			—			(350	)		8
Interest expense — affiliates		(1	)		(1	)		(1	)		—			(3	)
Interest expense — other		(48	)		(56	)		(33	)		32			(105	)
Capitalized interest		—			10			10			—			20
Total other income (expense)		308			(44	)		(4	)		(318	)		(58	)
INCOME (LOSS) BEFORE INCOME TAXES		(123	)		331			213			(340	)		81
INCOME TAXES (BENEFITS)		(179	)		119			80			5			25
NET INCOME	$	56		$	212		$	133		$	(345	)	$	56

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	1,307		$	581		$	339		$	(901	)	$	1,326
EXPENSES:
Fuel		7			302			34			—			343
Purchased power from affiliates		913			8			49			(901	)		69
Purchased power from non-affiliates		310			—			—			—			310
Other operating expenses		81			94			117			12			304
Provision for depreciation		1			27			36			(1	)		63
General taxes		6			9			7			—			22
Total expenses		1,318			440			243			(890	)		1,111
OPERATING INCOME (LOSS)		(11	)		141			96			(11	)		215
OTHER INCOME (EXPENSE):
Investment income		2			—			11			—			13
Miscellaneous income, including net income from equity investees		151			1			—			(148	)		4
Interest expense — affiliates		—			(2	)		—			—			(2	)
Interest expense — other		(24	)		(28	)		(15	)		16			(51	)
Capitalized interest		—			20			4			—			24
Total other income (expense)		129			(9	)		—			(132	)		(12	)
INCOME BEFORE INCOME TAXES		118			132			96			(143	)		203
INCOME TAXES (BENEFITS)		(16	)		48			34			3			69
NET INCOME	$	134		$	84		$	62		$	(146	)	$	134

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	2,674		$	1,149		$	765		$	(1,874	)	$	2,714
EXPENSES:
Fuel		12			582			77			—			671
Purchased power from affiliates		1,881			12			111			(1,874	)		130
Purchased power from non-affiliates		760			—			—			—			760
Other operating expenses		134			194			256			24			608
Provision for depreciation		2			54			73			(3	)		126
General taxes		11			24			14			—			49
Impairment of long-lived assets		—			2			—			—			2
Total expenses		2,800			868			531			(1,853	)		2,346
OPERATING INCOME (LOSS)		(126	)		281			234			(21	)		368
OTHER INCOME (EXPENSE):
Investment income		4			—			10			—			14
Miscellaneous income, including net income from equity investees		317			1			—			(311	)		7
Interest expense to affiliates		—			(4	)		(1	)		—			(5	)
Interest expense — other		(48	)		(54	)		(31	)		32			(101	)
Capitalized interest		—			36			8			—			44
Total other income (expense)		273			(21	)		(14	)		(279	)		(41	)
INCOME BEFORE INCOME TAXES		147			260			220			(300	)		327
INCOME TAXES (BENEFITS)		(67	)		97			78			5			113
NET INCOME	$	214		$	163		$	142		$	(305	)	$	214

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of June 30, 2011	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	6	$	—	$	—		$	6
Receivables-
Customers		450		—		—		—			450
Associated companies		481		425		263		(679	)		490
Other		24		23		4		—			51
Notes receivable from associated companies		6		410		74		—			490
Materials and supplies, at average cost		54		253		192		—			499
Derivatives		221		—		—		—			221
Prepayments and other		34		14		1		—			49
		1,270		1,131		534		(679	)		2,256
PROPERTY, PLANT AND EQUIPMENT:
In service		101		6,105		5,634		(385	)		11,455
Less — Accumulated provision for depreciation		19		2,067		2,298		(178	)		4,206
		82		4,038		3,336		(207	)		7,249
Construction work in progress		10		198		486		—			694
Property, plant and equipment held for sale, net		—		487		—		—			487
		92		4,723		3,822		(207	)		8,430
INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,184		—			1,184
Investment in associated companies		5,302		—		—		(5,302	)		—
Other		1		9		—		—			10
		5,303		9		1,184		(5,302	)		1,194
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		18		344		—		(362	)		—
Customer intangibles		129		—		—		—			129
Goodwill		24		—		—		—			24
Property taxes		—		16		25		—			41
Unamortized sale and leaseback costs		—		6		—		70			76
Derivatives		135		—		—		—			135
Other		39		97		7		(68	)		75
		345		463		32		(360	)		480
	$	7,010	$	6,326	$	5,572	$	(6,548	)	$	12,360
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	436	$	671	$	(20	)	$	1,088
Short-term borrowings-
Associated companies		453		88		—		—			541
Other		—		1		—		—			1
Accounts payable-
Associated companies		665		231		165		(668	)		393
Other		80		111		—		—			191
Derivatives		242		—		—		—			242
Other		69		137		46		10			262
		1,510		1,004		882		(678	)		2,718
CAPITALIZATION:
Total equity		3,858		2,728		2,556		(5,285	)		3,857
Long-term debt and other long-term obligations		1,483		2,050		706		(1,239	)		3,000
		5,341		4,778		3,262		(6,524	)		6,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		942			942
Accumulated deferred income taxes		—		—		504		(288	)		216
Asset retirement obligations		—		28		847		—			875
Retirement benefits		50		245		—		—			295
Lease market valuation liability		—		194		—		—			194
Derivatives		85		—		—		—			85
Other		24		77		77		—			178
		159		544		1,428		654			2,785
	$	7,010	$	6,326	$	5,572	$	(6,548	)	$	12,360

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of December 31, 2010	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	9	$	—	$	—		$	9
Receivables-
Customers		366		—		—		—			366
Associated companies		333		357		126		(338	)		478
Other		21		56		13		—			90
Notes receivable from associated companies		34		189		174		—			397
Materials and supplies, at average cost		41		276		228		—			545
Derivatives		182		—		—		—			182
Prepayments and other		48		10		1		—			59
		1,025		897		542		(338	)		2,126
PROPERTY, PLANT AND EQUIPMENT:
In service		96		6,198		5,412		(385	)		11,321
Less — Accumulated provision for depreciation		17		2,020		2,162		(175	)		4,024
		79		4,178		3,250		(210	)		7,297
Construction work in progress		9		520		534		—			1,063
		88		4,698		3,784		(210	)		8,360
INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,146		—			1,146
Investment in associated companies		4,942		—		—		(4,942	)		—
Other		—		12		—		—			12
		4,942		12		1,146		(4,942	)		1,158
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		43		412		—		(455	)		—
Customer intangibles		134		—		—		—			134
Goodwill		24		—		—		—			24
Property taxes		—		16		25		—			41
Unamortized sale and leaseback costs		—		10		—		63			73
Derivatives		98		—		—		—			98
Other		21		71		14		(58	)		48
		320		509		39		(450	)		418
	$	6,375	$	6,116	$	5,511	$	(5,940	)	$	12,062
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	101	$	419	$	632	$	(20	)	$	1,132
Short-term borrowings-
Associated companies		—		12		—		—			12
Accounts payable-
Associated companies		351		213		250		(347	)		467
Other		139		102		—		—			241
Derivatives		266		—		—		—			266
Other		56		183		46		37			322
		913		929		928		(330	)		2,440
CAPITALIZATION:
Common stockholder’s equity		3,788		2,515		2,414		(4,929	)		3,788
Long-term debt and other long-term obligations		1,519		2,119		793		(1,250	)		3,181
		5,307		4,634		3,207		(6,179	)		6,969
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		959			959
Accumulated deferred income taxes		—		—		448		(390	)		58
Asset retirement obligations		—		27		865		—			892
Retirement benefits		48		237		—		—			285
Lease market valuation liability		—		217		—		—			217
Derivatives		81		—		—		—			81
Other		26		72		63		—			161
		155		553		1,376		569			2,653
	$	6,375	$	6,116	$	5,511	$	(5,940	)	$	12,062

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(329	)	$	321		$	200		$	(10	)	$	182
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			140			107			—			247
Short-term borrowings, net		453			77			—			—			530
Redemptions and Repayments-
Long-term debt		(135	)		(192	)		(155	)		10			(472	)
Other		(9	)		(1	)		(1	)		—			(11	)
Net cash provided from (used for) financing activities		309			24			(49	)		10			294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(6	)		(109	)		(219	)		—			(334	)
Sales of investment securities held in trusts		—			—			513			—			513
Purchases of investment securities held in trusts		—			—			(545	)		—			(545	)
Loans to associated companies, net		28			(221	)		100			—			(93	)
Customer acquisition costs		(2	)		—			—			—			(2	)
Other		—			(18	)		—			—			(18	)
Net cash provided from (used for) investing activities		20			(348	)		(151	)		—			(479	)
Net change in cash and cash equivalents		—			(3	)		—			—			(3	)
Cash and cash equivalents at beginning of period		—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	6		$	—		$	—		$	6

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(223	)	$	163		$	287		$	(9	)	$	218
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		—			76			—			—			76
Redemptions and Repayments-
Long-term debt		—			(261	)		(43	)		9			(295	)
Other		(1	)		—			—			—			(1	)
Net cash used for financing activities		(1	)		(185	)		(43	)		9			(220	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(4	)		(333	)		(229	)		—			(566	)
Proceeds from asset sales		—			116			—			—			116
Sales of investment securities held in trusts		—			—			957			—			957
Purchases of investment securities held in trusts		—			—			(979	)		—			(979	)
Loans to associated companies, net		332			241			58			—			631
Customer acquisition costs		(105	)		—			—			—			(105	)
Leasehold improvement payments to associated companies		—			—			(51	)		—			(51	)
Other		1			(2	)		—			—			(1	)
Net cash provided from (used for) investing activities		224			22			(244	)		—			2
Net change in cash and cash equivalents		—			—			—			—			—
Cash and cash equivalents at beginning of period		—			—			—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—		$	—		$	—

XML



Document and Entity Information	6 Months Ended
	Jun. 30, 2011	Jul. 29, 2011
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	0001031296
Document Type	10-Q
Document Period End Date	Jun. 30, 2011
Amendment Flag	false
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		418,216,437
FES
Entity Common Stock Shares Outstanding		7
OE
Entity Common Stock Shares Outstanding		60
CEI
Entity Common Stock Shares Outstanding		67,930,743
TE
Entity Common Stock Shares Outstanding		29,402,054
JCP&L
Entity Common Stock Shares Outstanding		13,628,447
Met-Ed
Entity Common Stock Shares Outstanding		740,905
Penelec
Entity Common Stock Shares Outstanding		4,427,577

XML



Fair Value Measurements (Details 6) (USD $) In Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2010
JCP&L | Non Utility Generation Contract
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	$ 6	$ 8
Beginning Balance, Derivative Liability	(233)	(399)
Beginning Balance, Derivative, Total	(227)	(391)
Realized gain (loss), Derivative Asset
Realized gain (loss), Derivative Liability
Realized gain (loss), Derivative Total
Unrealized gain (loss), Derivative Asset	(1)	(1)
Unrealized gain (loss), Derivative Liability	(71)	36
Unrealized gain (loss), Derivative total	(72)	35
Purchases, Derivative Asset
Purchases, Derivative Liability
Purchases, Derivative Asset and Liability, total
Issuances, Derivative Asset
Issuances, Derivative Liability
Issuances, Derivative Asset and Liability, total
Sales, Derivative Asset
Sales, Derivative Liability
Sales, Derivative Asset and Liability, total
Settlements, Derivative Asset		(1)
Settlements, Derivative Liability	64	130
Settlements, Derivative Asset and Liability, total	64	129
Transfers into Level 3, Derivative Asset
Transfers into Level 3, Derivative Liability
Transfers into Level 3, Derivative Asset and Liability, total
Ending Balance, Derivative Asset	5	6
Ending Balance, Derivative Liability	(240)	(233)
Ending Balance, Derivative, Total	(235)	(227)
Met-Ed | Non Utility Generation Contract
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	112	176
Beginning Balance, Derivative Liability	(116)	(143)
Beginning Balance, Derivative, Total	(4)	33
Realized gain (loss), Derivative Asset
Realized gain (loss), Derivative Liability
Realized gain (loss), Derivative Total
Unrealized gain (loss), Derivative Asset	(42)	(59)
Unrealized gain (loss), Derivative Liability	(36)	(38)
Unrealized gain (loss), Derivative total	(78)	(97)
Purchases, Derivative Asset
Purchases, Derivative Liability
Purchases, Derivative Asset and Liability, total
Issuances, Derivative Asset
Issuances, Derivative Liability
Issuances, Derivative Asset and Liability, total
Sales, Derivative Asset
Sales, Derivative Liability
Sales, Derivative Asset and Liability, total
Settlements, Derivative Asset	(4)	(5)
Settlements, Derivative Liability	30	65
Settlements, Derivative Asset and Liability, total	26	60
Transfers into Level 3, Derivative Asset
Transfers into Level 3, Derivative Liability
Transfers into Level 3, Derivative Asset and Liability, total
Ending Balance, Derivative Asset	66	112
Ending Balance, Derivative Liability	(122)	(116)
Ending Balance, Derivative, Total	(56)	(4)
Penelec | Non Utility Generation Contract
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	4	16
Beginning Balance, Derivative Liability	(117)	(101)
Beginning Balance, Derivative, Total	(113)	(85)
Realized gain (loss), Derivative Asset
Realized gain (loss), Derivative Liability
Realized gain (loss), Derivative Total
Unrealized gain (loss), Derivative Asset		(11)
Unrealized gain (loss), Derivative Liability	(88)	(108)
Unrealized gain (loss), Derivative total	(88)	(119)
Purchases, Derivative Asset
Purchases, Derivative Liability
Purchases, Derivative Asset and Liability, total
Issuances, Derivative Asset
Issuances, Derivative Liability
Issuances, Derivative Asset and Liability, total
Sales, Derivative Asset
Sales, Derivative Liability
Sales, Derivative Asset and Liability, total
Settlements, Derivative Asset		(1)
Settlements, Derivative Liability	45	92
Settlements, Derivative Asset and Liability, total	45	91
Transfers into Level 3, Derivative Asset
Transfers into Level 3, Derivative Liability
Transfers into Level 3, Derivative Asset and Liability, total
Ending Balance, Derivative Asset	4	4
Ending Balance, Derivative Liability	(160)	(117)
Ending Balance, Derivative, Total	(156)	(113)
Non Utility Generation Contract
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	122	200
Beginning Balance, Derivative Liability	(466)	(643)
Beginning Balance, Derivative, Total	(344)	(443)
Realized gain (loss), Derivative Asset
Realized gain (loss), Derivative Liability
Realized gain (loss), Derivative Total
Unrealized gain (loss), Derivative Asset	(40)	(71)
Unrealized gain (loss), Derivative Liability	(203)	(110)
Unrealized gain (loss), Derivative total	(243)	(181)
Purchases, Derivative Asset	13
Purchases, Derivative Liability	(3)
Purchases, Derivative Asset and Liability, total	10
Issuances, Derivative Asset
Issuances, Derivative Liability
Issuances, Derivative Asset and Liability, total
Sales, Derivative Asset
Sales, Derivative Liability
Sales, Derivative Asset and Liability, total
Settlements, Derivative Asset	(6)	(7)
Settlements, Derivative Liability	154	287
Settlements, Derivative Asset and Liability, total	148	280
Transfers into Level 3, Derivative Asset
Transfers into Level 3, Derivative Liability	(12)
Transfers into Level 3, Derivative Asset and Liability, total	(12)
Ending Balance, Derivative Asset	89	122
Ending Balance, Derivative Liability	(530)	(466)
Ending Balance, Derivative, Total	(441)	(344)
FES | FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	0
Beginning Balance, Derivative Liability	0
Beginning Balance, Derivative, Total	0
Realized gain (loss), Derivative Asset
Realized gain (loss), Derivative Liability
Realized gain (loss), Derivative Total
Unrealized gain (loss), Derivative Asset	1
Unrealized gain (loss), Derivative Liability
Unrealized gain (loss), Derivative total	1
Purchases, Derivative Asset	2
Purchases, Derivative Liability
Purchases, Derivative Asset and Liability, total	2
Issuances, Derivative Asset
Issuances, Derivative Liability
Issuances, Derivative Asset and Liability, total
Sales, Derivative Asset
Sales, Derivative Liability
Sales, Derivative Asset and Liability, total
Settlements, Derivative Asset	(1)
Settlements, Derivative Liability
Settlements, Derivative Asset and Liability, total	(1)
Transfers into Level 3, Derivative Asset
Transfers into Level 3, Derivative Liability
Transfers into Level 3, Derivative Asset and Liability, total
Ending Balance, Derivative Asset	2
Ending Balance, Derivative Liability	0
Ending Balance, Derivative, Total	$ 2

XML



Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2011

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share

	Three Months				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2011		2010		2011		2010
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	181	$	265	$	231	$	420
Weighted average number of basic shares outstanding(1)		418		304		380		304
Assumed exercise of dilutive stock options and awards		2		1		2		1
Weighted average number of diluted shares outstanding(1)		420		305		382		305
Basic earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.38
Diluted earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.37

⁽¹⁾ Includes 113 million shares issued to AE stockholders for the periods subsequent to the merger date. (See Note 2)

XML



Fair Value Measurements (Details 5) (Recurring, USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Assets
Fair value, assets	$ 2,801	$ 2,649
Liabilities
Fair value, liabilities	(896)	(814)
Net assets (liabilities)	1,905	1,835
FES
Assets
Fair value, assets	1,468	1,378
Liabilities
Fair value, liabilities	(327)	(348)
Net assets (liabilities)	1,141	1,030
FES | Level 1
Assets
Fair value, assets	96	0
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	96	0
FES | Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
FES | Level 1 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	0	0
FES | Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0
FES | Level 1 | Equity Securities
Assets
Fair value, assets	96
FES | Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
FES | Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
FES | Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
FES | Level 1 | Other
Assets
Fair value, assets	0	0
FES | Level 1 | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
FES | Level 2
Assets
Fair value, assets	1,370	1,378
Liabilities
Fair value, liabilities	(327)	(348)
Net assets (liabilities)	1,043	1,030
FES | Level 2 | Corporate debt securities
Assets
Fair value, assets	562	528
FES | Level 2 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	283	241
FES | Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0
FES | Level 2 | Equity Securities
Assets
Fair value, assets	0
FES | Level 2 | Foreign government debt securities
Assets
Fair value, assets	160	147
FES | Level 2 | U.S. government debt securities
Assets
Fair value, assets	316	308
FES | Level 2 | U.S. state debt securities
Assets
Fair value, assets	7	6
FES | Level 2 | Other
Assets
Fair value, assets	42	148
FES | Level 2 | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(327)	(348)
FES | Level 3
Assets
Fair value, assets	2	0
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	2	0
FES | Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
FES | Level 3 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	0	0
FES | Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	2
FES | Level 3 | Equity Securities
Assets
Fair value, assets	0
FES | Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
FES | Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
FES | Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
FES | Level 3 | Other
Assets
Fair value, assets	0	0
FES | Level 3 | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
FES | Corporate debt securities
Assets
Fair value, assets	562	528
FES | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	283	241
FES | FTRs | Derivative Assets
Assets
Fair value, assets	2
FES | Equity Securities
Assets
Fair value, assets	96
FES | Foreign government debt securities
Assets
Fair value, assets	160	147
FES | U.S. government debt securities
Assets
Fair value, assets	316	308
FES | U.S. state debt securities
Assets
Fair value, assets	7	6
FES | Other
Assets
Fair value, assets	42	148
FES | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(327)	(348)
OE
Assets
Fair value, assets	133	126
OE | Level 1
Assets
Fair value, assets	0	0
OE | Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
OE | Level 1 | Other
Assets
Fair value, assets	0	0
OE | Level 2
Assets
Fair value, assets	133	126
OE | Level 2 | U.S. government debt securities
Assets
Fair value, assets	131	124
OE | Level 2 | Other
Assets
Fair value, assets	2	2
OE | Level 3
Assets
Fair value, assets	0	0
OE | Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
OE | Level 3 | Other
Assets
Fair value, assets	0	0
OE | U.S. government debt securities
Assets
Fair value, assets	131	124
OE | Other
Assets
Fair value, assets	2	2
TE
Assets
Fair value, assets	79	76
TE | Level 1
Assets
Fair value, assets	26	0
TE | Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
TE | Level 1 | Equity Securities
Assets
Fair value, assets	26
TE | Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
TE | Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
TE | Level 1 | Other
Assets
Fair value, assets	0	0
TE | Level 2
Assets
Fair value, assets	53	76
TE | Level 2 | Corporate debt securities
Assets
Fair value, assets	16	7
TE | Level 2 | Equity Securities
Assets
Fair value, assets	0
TE | Level 2 | U.S. government debt securities
Assets
Fair value, assets	33	33
TE | Level 2 | U.S. state debt securities
Assets
Fair value, assets	1	1
TE | Level 2 | Other
Assets
Fair value, assets	3	35
TE | Level 3
Assets
Fair value, assets	0	0
TE | Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
TE | Level 3 | Equity Securities
Assets
Fair value, assets	0
TE | Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
TE | Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
TE | Level 3 | Other
Assets
Fair value, assets	0	0
TE | Corporate debt securities
Assets
Fair value, assets	16	7
TE | Equity Securities
Assets
Fair value, assets	26
TE | U.S. government debt securities
Assets
Fair value, assets	33	33
TE | U.S. state debt securities
Assets
Fair value, assets	1	1
TE | Other
Assets
Fair value, assets	3	35
JCP&L
Assets
Fair value, assets	403	400
Liabilities
Fair value, liabilities	(240)	(233)
Net assets (liabilities)	163	167
JCP&L | Level 1
Assets
Fair value, assets	21	96
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	21	96
JCP&L | Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
JCP&L | Level 1 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		0
JCP&L | Level 1 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
JCP&L | Level 1 | Equity Securities
Assets
Fair value, assets	21	96
JCP&L | Level 1 | Foreign government debt securities
Assets
Fair value, assets	0
JCP&L | Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
JCP&L | Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
JCP&L | Level 1 | Other
Assets
Fair value, assets	0	0
JCP&L | Level 1 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
JCP&L | Level 2
Assets
Fair value, assets	377	298
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	377	298
JCP&L | Level 2 | Corporate debt securities
Assets
Fair value, assets	81	23
JCP&L | Level 2 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		2
JCP&L | Level 2 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
JCP&L | Level 2 | Equity Securities
Assets
Fair value, assets	0	0
JCP&L | Level 2 | Foreign government debt securities
Assets
Fair value, assets	13
JCP&L | Level 2 | U.S. government debt securities
Assets
Fair value, assets	54	33
JCP&L | Level 2 | U.S. state debt securities
Assets
Fair value, assets	215	236
JCP&L | Level 2 | Other
Assets
Fair value, assets	14	4
JCP&L | Level 2 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
JCP&L | Level 3
Assets
Fair value, assets	5	6
Liabilities
Fair value, liabilities	(240)	(233)
Net assets (liabilities)	(235)	(227)
JCP&L | Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
JCP&L | Level 3 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		0
JCP&L | Level 3 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	5	6
JCP&L | Level 3 | Equity Securities
Assets
Fair value, assets	0	0
JCP&L | Level 3 | Foreign government debt securities
Assets
Fair value, assets	0
JCP&L | Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
JCP&L | Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
JCP&L | Level 3 | Other
Assets
Fair value, assets	0	0
JCP&L | Level 3 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(240)	(233)
JCP&L | Corporate debt securities
Assets
Fair value, assets	81	23
JCP&L | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		2
JCP&L | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	5	6
JCP&L | Equity Securities
Assets
Fair value, assets	21	96
JCP&L | Foreign government debt securities
Assets
Fair value, assets	13
JCP&L | U.S. government debt securities
Assets
Fair value, assets	54	33
JCP&L | U.S. state debt securities
Assets
Fair value, assets	215	236
JCP&L | Other
Assets
Fair value, assets	14	4
JCP&L | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(240)	(233)
Met-Ed
Assets
Fair value, assets	368	414
Liabilities
Fair value, liabilities	(122)	(116)
Net assets (liabilities)	246	298
Met-Ed | Level 1
Assets
Fair value, assets	33	160
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	33	160
Met-Ed | Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 1 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		0
Met-Ed | Level 1 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
Met-Ed | Level 1 | Equity Securities
Assets
Fair value, assets	33	160
Met-Ed | Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 1 | Other
Assets
Fair value, assets	0	0
Met-Ed | Level 1 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Met-Ed | Level 2
Assets
Fair value, assets	269	142
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	269	142
Met-Ed | Level 2 | Corporate debt securities
Assets
Fair value, assets	138	32
Met-Ed | Level 2 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		5
Met-Ed | Level 2 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
Met-Ed | Level 2 | Equity Securities
Assets
Fair value, assets	0	0
Met-Ed | Level 2 | Foreign government debt securities
Assets
Fair value, assets	20	1
Met-Ed | Level 2 | U.S. government debt securities
Assets
Fair value, assets	87	88
Met-Ed | Level 2 | U.S. state debt securities
Assets
Fair value, assets	2	2
Met-Ed | Level 2 | Other
Assets
Fair value, assets	22	14
Met-Ed | Level 2 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Met-Ed | Level 3
Assets
Fair value, assets	66	112
Liabilities
Fair value, liabilities	(122)	(116)
Net assets (liabilities)	(56)	(4)
Met-Ed | Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 3 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		0
Met-Ed | Level 3 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	66	112
Met-Ed | Level 3 | Equity Securities
Assets
Fair value, assets	0	0
Met-Ed | Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Met-Ed | Level 3 | Other
Assets
Fair value, assets	0	0
Met-Ed | Level 3 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(122)	(116)
Met-Ed | Corporate debt securities
Assets
Fair value, assets	138	32
Met-Ed | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		5
Met-Ed | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	66	112
Met-Ed | Equity Securities
Assets
Fair value, assets	33	160
Met-Ed | Foreign government debt securities
Assets
Fair value, assets	20	1
Met-Ed | U.S. government debt securities
Assets
Fair value, assets	87	88
Met-Ed | U.S. state debt securities
Assets
Fair value, assets	2	2
Met-Ed | Other
Assets
Fair value, assets	22	14
Met-Ed | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(122)	(116)
Penelec
Assets
Fair value, assets	291	242
Liabilities
Fair value, liabilities	(160)	(117)
Net assets (liabilities)	131	125
Penelec | Level 1
Assets
Fair value, assets	20	81
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	20	81
Penelec | Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Penelec | Level 1 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		0
Penelec | Level 1 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
Penelec | Level 1 | Equity Securities
Assets
Fair value, assets	20	81
Penelec | Level 1 | Foreign government debt securities
Assets
Fair value, assets	0
Penelec | Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Penelec | Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Penelec | Level 1 | Other
Assets
Fair value, assets	0	0
Penelec | Level 1 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Penelec | Level 2
Assets
Fair value, assets	267	157
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	267	157
Penelec | Level 2 | Corporate debt securities
Assets
Fair value, assets	69	8
Penelec | Level 2 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		2
Penelec | Level 2 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
Penelec | Level 2 | Equity Securities
Assets
Fair value, assets	0	0
Penelec | Level 2 | Foreign government debt securities
Assets
Fair value, assets	12
Penelec | Level 2 | U.S. government debt securities
Assets
Fair value, assets	52	9
Penelec | Level 2 | U.S. state debt securities
Assets
Fair value, assets	81	133
Penelec | Level 2 | Other
Assets
Fair value, assets	53	5
Penelec | Level 2 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Penelec | Level 3
Assets
Fair value, assets	4	4
Liabilities
Fair value, liabilities	(160)	(117)
Net assets (liabilities)	(156)	(113)
Penelec | Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Penelec | Level 3 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		0
Penelec | Level 3 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	4	4
Penelec | Level 3 | Equity Securities
Assets
Fair value, assets	0	0
Penelec | Level 3 | Foreign government debt securities
Assets
Fair value, assets	0
Penelec | Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Penelec | Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Penelec | Level 3 | Other
Assets
Fair value, assets	0	0
Penelec | Level 3 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(160)	(117)
Penelec | Corporate debt securities
Assets
Fair value, assets	69	8
Penelec | Commodity Contracts | Derivative Assets
Assets
Fair value, assets		2
Penelec | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	4	4
Penelec | Equity Securities
Assets
Fair value, assets	20	81
Penelec | Foreign government debt securities
Assets
Fair value, assets	12
Penelec | U.S. government debt securities
Assets
Fair value, assets	52	9
Penelec | U.S. state debt securities
Assets
Fair value, assets	81	133
Penelec | Other
Assets
Fair value, assets	53	5
Penelec | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(160)	(117)
Level 1
Assets
Fair value, assets	198	338
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	198	338
Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 1 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0
Level 1 | Interest Rate Swap | Derivative Assets
Assets
Fair value, assets	0
Level 1 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity Securities
Assets
Fair value, assets	198	338
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 1 | Other
Assets
Fair value, assets	0	0
Level 1 | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0
Level 1 | Interest Rate Swap | Derivative Liabilities
Liabilities
Fair value, liabilities	0
Level 1 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2
Assets
Fair value, assets	2,515	2,189
Liabilities
Fair value, liabilities	(367)	(348)
Net assets (liabilities)	2,148	1,841
Level 2 | Corporate debt securities
Assets
Fair value, assets	868	597
Level 2 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	312	250
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0
Level 2 | Interest Rate Swap | Derivative Assets
Assets
Fair value, assets	4
Level 2 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity Securities
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	206	149
Level 2 | U.S. government debt securities
Assets
Fair value, assets	673	595
Level 2 | U.S. state debt securities
Assets
Fair value, assets	306	379
Level 2 | Other
Assets
Fair value, assets	146	219
Level 2 | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(362)	(348)
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0
Level 2 | Interest Rate Swap | Derivative Liabilities
Liabilities
Fair value, liabilities	(5)
Level 2 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3
Assets
Fair value, assets	88	122
Liabilities
Fair value, liabilities	(529)	(466)
Net assets (liabilities)	(441)	(344)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | Commodity Contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	13
Level 3 | Interest Rate Swap | Derivative Assets
Assets
Fair value, assets	0
Level 3 | Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	75	122
Level 3 | Equity Securities
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 3 | Other
Assets
Fair value, assets	0	0
Level 3 | Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)
Level 3 | Interest Rate Swap | Derivative Liabilities
Liabilities
Fair value, liabilities	0
Level 3 | Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(522)	(466)
Corporate debt securities
Assets
Fair value, assets	868	597
Commodity Contracts | Derivative Assets
Assets
Fair value, assets	312	250
FTRs | Derivative Assets
Assets
Fair value, assets	13
Interest Rate Swap | Derivative Assets
Assets
Fair value, assets	4
Non Utility Generation Contract | Derivative Assets
Assets
Fair value, assets	75	122
Equity Securities
Assets
Fair value, assets	198	338
Foreign government debt securities
Assets
Fair value, assets	206	149
U.S. government debt securities
Assets
Fair value, assets	673	595
U.S. state debt securities
Assets
Fair value, assets	306	379
Other
Assets
Fair value, assets	146	219
Commodity Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(362)	(348)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)
Interest Rate Swap | Derivative Liabilities
Liabilities
Fair value, liabilities	(5)
Non Utility Generation Contract | Derivative Liabilities
Liabilities
Fair value, liabilities	$ (522)	$ (466)

XML



Derivative Instruments

6 Months Ended

Jun. 30, 2011

Derivative Instruments [Abstract]

DERIVATIVE INSTRUMENTS

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’s Risk Policy Committee, comprised 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 practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. In addition to derivatives, FirstEnergy also enters into master netting agreements with certain third parties.

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value unless they meet the normal purchases and normal sales criteria. Derivatives that meet those criteria are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance. Changes in the fair value of derivative instruments that qualify and are designated as cash flow hedge instruments are recorded in AOCL. Changes in the fair value of derivative instruments that are not designated as cash flow hedge instruments are recorded in net income on a mark-to-market basis. FirstEnergy has contractual derivative agreements through December 2018.

Cash Flow Hedges

FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating interest rates and commodity prices. The effective portion of gains and losses on the derivative contract are reported as a component of AOCL with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

As of December 31, 2010, commodity derivative contracts designated in cash flow hedging relationships were $104 million of assets and $101 million of liabilities. In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships. Total net unamortized gains included in AOCL associated with dedesignated cash flow hedges totaled $8 million as of June 30, 2011. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCL into other operating expenses totaled $14 million and $19 million during the three months and six months ended June 30, 2011, respectively. Approximately $3 million is expected to be amortized to expense during the next twelve months.

FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of June 30, 2011, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCL associated with prior interest rate cash flow hedges totaled $84 million ($55 million net of tax) as of June 30, 2011. Based on current estimates, approximately $10 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCL into interest expense totaled $3 million during the three months ended June 30, 2011 and 2010 and $6 million during the six months ended June 30, 2011 and 2010.

Fair Value Hedges

FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of June 30, 2011, no fixed-for-floating interest rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $113 million ($73 million net of tax) as of June 30, 2011. Based on current estimates, approximately $22 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $6 million and $2 million during the three months ended June 30, 2011 and 2010, respectively and $11 million and $3 million during the six months ended June 30, 2011 and 2010, respectively.

Commodity Derivatives

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

Electricity forwards are used to balance expected sales with expected generation and purchased power. Natural gas futures are entered into based on expected consumption of natural gas; primarily natural gas is 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. Interest rate swaps include two interest rate swap agreements that expire during 2011 with an aggregate notional value of $200 million that were entered into during 2003 to substantially offset two existing interest rate swaps with the same counterparty. The 2003 agreements effectively locked in a net liability and substantially eliminated future income volatility from the interest rate swap positions but do not qualify for cash flow hedge accounting. Derivative instruments are not used in quantities greater than forecasted needs.

As of June 30, 2011, FirstEnergy’s net liability position under commodity derivative contracts was $45 million, which primarily related to FES positions. Under these commodity derivative contracts, FES posted $81 million and Allegheny posted $2 million in collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $49 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on derivative contracts held as of June 30, 2011, an adverse 10% change in commodity prices would decrease net income by approximately $31 million ($20 million net of tax) during the next twelve months.

FTRs

FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of an RTO that have load serving obligations and through the direct allocation of FTRs from the PJM RTO. The PJM RTO has a rule that allows directly allocated FTRs to be granted to LSEs in zones that have newly entered PJM. For the first two planning years, PJM permits the LSEs to request a direct allocation of FTRs in these new zones at no cost as opposed to receiving ARRs. The directly allocated FTRs differ from traditional FTRs in that the ownership of all or part of the FTRs may shift to another LSE if customers choose to shop with the other LSE.

The future obligations for the FTRs acquired at auction are reflected on the Consolidated Balance Sheets and have not been designated as cash flow hedge instruments. FirstEnergy initially records these FTRs at the auction price less the obligation due to the RTO, and subsequently adjusts the carrying value of remaining FTRs to their estimated fair value at the end of each accounting period prior to settlement. Changes in the fair value of FTRs held by FirstEnergy’s unregulated subsidiaries are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s regulated subsidiaries are recorded as regulatory assets or liabilities. Directly allocated FTRs are accounted for under the accrual method of accounting, and their effects are included in earnings at the time of contract performance.

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

Derivatives not designated as hedging instruments as of June 30, 2011:

Derivative Assets
	Fair Value
	June 30,		December 31,
	2011		2010
	(In millions)
Power Contracts
Current Assets	$	210	$	96
Noncurrent Assets		102		40
FTRs
Current Assets		13		—
Noncurrent Assets		—		—
NUGs
Current Assets		4		3
Noncurrent Assets		71		119
Interest Rate Swaps
Current Assets		4		—
Noncurrent Assets		—		—
Other
Current Assets		—		10
Noncurrent Assets		—		—
Total Derivatives	$	404	$	268

Derivative Liabilities
	Fair Value
	June 30,		December 31,
	2011		2010
	(In millions)
Power Contracts
Current Liabilities	$	274	$	209
Noncurrent Liabilities		88		38
FTRs
Current Liabilities		7		—
Noncurrent Liabilities		—		—
NUGs
Current Liabilities		317		229
Noncurrent Liabilities		205		238
Interest Rate Swaps
Current Liabilities		5		—
Noncurrent Liabilities		—		—
Other
Current Liabilities		—		—
Noncurrent Liabilities		—		—
Total Derivatives	$	896	$	714

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2011:

	Purchases		Sales			Net			Units
	(In thousands)
Power Contracts		45,573		(59,549	)		(13,976	)	MWH
FTRs		53,656		—			53,656		MWH
Interest Rate Swaps		200,000		(200,000	)		—		notional dollars
NUGs		26,903		—			26,903		MWH

The effect of derivative instruments on the Consolidated Statements of Income during the three months and six months ended June 30, 2011 and 2010, are summarized in the following tables:

	Three Months Ended June 30,
	Power					Interest
	Contracts			FTRs		Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	14		$	—	$	—	$	—		$	14
Effective Gain (Loss) Reclassified to: (1)
Purchase Power Expense		—			—		—		—			—
Revenues		—			—		—		—			—
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	—		$	—	$	—	$	3		$	3
Effective Gain (Loss) Reclassified to:(1)
Purchase Power Expense		(3	)		—		—		—			(3	)
Revenues		(5	)		—		—		—			(5	)
Fuel Expense		—			—		—		(4	)		(4	)

Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	33		$	—		$	—	$	—	$	33
Revenues		(4	)		—			—		—		(4	)
Other Operating Expense		(34	)		13			—		—		(21	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		1			—			—		—		1
Revenues		(39	)		18			—		—		(21	)
Other Operating Expense		—			(59	)		—		—		(59	)
2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	66		$	—		$	—	$	—	$	66
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(26	)		—			—		—		(26	)

Derivatives Not in a Hedging	Three Months Ended June 30,
Relationship with Regulatory Offset(2)	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(147	)	$	2		$	(145	)
Unrealized Gain (Loss) to Regulatory Assets:		147			(2	)		145
Realized Gain (Loss) to Derivative Instrument:		62			—			62
Realized Gain (Loss) to Regulatory Assets:		(62	)		—			(62	)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(35	)		—		$	(35	)
Unrealized Gain (Loss) to Regulatory Assets:		35			—			35
Realized Gain (Loss) to Derivative Instrument:		68			—			68
Realized Gain (Loss) to Regulatory Assets:		(68	)		—			(68	)

	Six Months Ended June 30,
	Power						Interest
	Contracts			FTRs			Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	5		$	—		$	—	$	—		$	5
Effective Gain (Loss) Reclassified to: (1)
Purchase Power Expense		16			—			—		—			16
Revenues		(12	)		—			—		—			(12	)
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(2	)	$	—		$	—	$	6		$	4
Effective Gain (Loss) Reclassified to:(1)
Purchase Power Expense		(7	)		—			—		—			(7	)
Revenues		(5	)		—			—		—			(5	)
Fuel Expense		—			—			—		(8	)		(8	)
Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	61		$	—		$	—	$	—		$	61
Revenues		(3	)		—			—		—			(3	)
Other Operating Expense		(54	)		13			1		—			(40	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(36	)		—			—		—			(36	)
Revenues		(29	)		26			—		—			(3	)
Other Operating Expense		—			(87	)		—		—			(87	)
2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	39		$	—		$	—	$	—		$	39
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(49	)		—			—		—			(49	)

Derivatives Not in a Hedging	Six Months Ended June 30,
Relationship with Regulatory Offset(2)	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(236	)	$	2		$	(234	)
Unrealized Gain (Loss) to Regulatory Assets:		236			(2	)		234
Realized Gain (Loss) to Derivative Instrument:		134			(10	)		124
Realized Gain (Loss) to Regulatory Assets:		(134	)		10			(124	)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(259	)		—		$	(259	)
Unrealized Gain (Loss) to Regulatory Assets:		259			—			259
Realized Gain (Loss) to Derivative Instrument:		146			(9	)		137
Realized Gain (Loss) to Regulatory Assets:		(146	)		9			(137	)

(1)	The ineffective portion was immaterial.
(2)	Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or refund to) customers during the three months and six months ended June 30, 2011 and 2010:

	Three Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other		Total
	(In millions)
Outstanding net asset (liability) as of April 1, 2011	$	(362	)	$	—	$	(362	)
Additions/Change in value of existing contracts		(147	)		2		(145	)
Settled contracts		62			—		62
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	2	$	(445	)
Outstanding net asset (liability) as of April 1, 2010	$	(590	)	$	10	$	(580	)
Additions/Change in value of existing contracts		(35	)		—		(35	)
Settled contracts		68			—		68
Outstanding net asset (liability) as of June 30, 2010	$	(557	)	$	10	$	(547	)

	Six Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts		(236	)		2			(234	)
Settled contracts		134			(10	)		124
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	2		$	(445	)
Outstanding net asset (liability) as of January 1, 2010	$	(444	)	$	19		$	(425	)
Additions/Change in value of existing contracts		(259	)		—			(259	)
Settled contracts		146			(9	)		137
Outstanding net asset (liability) as of June 30, 2010	$	(557	)	$	10		$	(547	)

⁽¹⁾ Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2011

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	868		$	—		$	868
Derivative assets — commodity contracts		—		312			—			312
Derivative assets — FTRs		—		—			13			13
Derivative assets — interest rate swaps		—		4			—			4
Derivative assets — NUG contracts(1)		—		—			75			75
Equity securities(2)		198		—			—			198
Foreign government debt securities		—		206			—			206
U.S. government debt securities		—		673			—			673
U.S. state debt securities		—		306			—			306
Other(4)		—		146			—			146
Total assets	$	198	$	2,515		$	88		$	2,801
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(362	)	$	—		$	(362	)
Derivative liabilities — FTRs		—		—			(7	)		(7	)
Derivative liabilities — interest rate swaps		—		(5	)		—			(5	)
Derivative liabilities — NUG contracts(1)		—		—			(522	)		(522	)
Total liabilities	$	—	$	(367	)	$	(529	)	$	(896	)
Net assets (liabilities)(3)	$	198	$	2,148		$	(441	)	$	1,905

December 31, 2010	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	597		$	—		$	597
Derivative assets — commodity contracts		—		250			—			250
Derivative assets — NUG contracts(1)		—		—			122			122
Equity securities(2)		338		—			—			338
Foreign government debt securities		—		149			—			149
U.S. government debt securities		—		595			—			595
U.S. state debt securities		—		379			—			379
Other(4)		—		219			—			219
Total assets	$	338	$	2,189		$	122		$	2,649
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—		$	(348	)
Derivative liabilities — NUG contracts(1)		—		—			(466	)		(466	)
Total liabilities	$	—	$	(348	)	$	(466	)	$	(814	)
Net assets (liabilities)(3)	$	338	$	1,841		$	(344	)	$	1,835

(1)	NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $6 million and $(7) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(4)	Primarily consists of cash and cash equivalents.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

	Derivative Asset(1)			Derivative Liability(1)			Net(1)
	(In millions)
January 1, 2011 Balance	$	122		$	(466	)	$	(344	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(40	)		(203	)		(243	)
Purchases		13			(3	)		10
Issuances		—			—			—
Sales		—			—			—
Settlements		(6	)		154			148
Transfers into  Level 3		—			(12	)		(12	)
June 30, 2011 Balance	$	89		$	(530	)	$	(441	)
January 1, 2010 Balance	$	200		$	(643	)	$	(443	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(71	)		(110	)		(181	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(7	)		287			280
Transfers into  Level 3		—			—			—
December 31, 2010 Balance	$	122		$	(466	)	$	(344	)

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

Fair value and related carrying amounts of long-term debt and other long-term obligations

	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy(1)	$	18,371	$	19,436	$	13,928	$	14,845
FES		4,056		4,310		4,279		4,403
OE		1,158		1,367		1,159		1,321
CEI		1,831		2,083		1,853		2,035
TE		600		690		600		653
JCP&L		1,795		2,008		1,810		1,962
Met-Ed		729		828		742		821
Penelec		1,120		1,231		1,120		1,189

⁽¹⁾ Includes debt assumed in the Allegheny merger (See Note 2) with a carrying value and a fair value as of June 30, 2011 of $4,530 million and $4,127 million, respectively.

Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities

	June 30, 2011(1)								December 31, 2010(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities
FirstEnergy	$	2,015	$	48	$	—	$	2,063	$	1,699	$	31	$	—	$	1,730
FES		1,023		26		—		1,049		980		13		—		993
OE		128		3		—		131		123		1		—		124
TE		52		1		—		53		42		—		—		42
JCP&L		353		9		—		362		281		9		—		290
Met-Ed		249		5		—		254		127		4		—		131
Penelec		210		4		—		214		145		4		—		149
Equity securities
FirstEnergy	$	187	$	11	$	—	$	198	$	268	$	69	$	—	$	337
FES		90		6		—		96		—		—		—		—
TE		24		2		—		26		—		—		—		—
JCP&L		21		1		—		22		80		17		—		97
Met-Ed		32		1		—		33		125		35		—		160
Penelec		20		1		—		21		63		16		—		79

(1)	Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $130 million; FES – $39 million; OE – $3 million; JCP&L – $19 million; Met-Ed – $14 million and Penelec – $55 million.
(2)	Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $193 million; FES – $153 million; OE – $3 million; TE – $34 million; JCP&L – $3 million; Met-Ed – $(3) million and Penelec – $4 million.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income

Three Months Ended June 30,
								Interest and
2011	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	734	$	22	$	(16	)	$	28
FES		297		10		(7	)		17
OE		12		—		—			1
TE		15		1		(1	)		1
JCP&L		159		4		(2	)		4
Met-Ed		165		4		(3	)		3
Penelec		86		3		(3	)		2

								Interest and
2010	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,183	$	46	$	(36	)	$	16
FES		685		41		(35	)		9
OE		57		2		—			—
TE		76		2		—			—
JCP&L		91		—		—			3
Met-Ed		233		1		(1	)		2
Penelec		41		—		—			2

Six Months Ended June 30,
								Interest and
2011	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,703	$	122	$	(45	)	$	52
FES		513		22		(23	)		32
OE		20		—		—			2
TE		28		1		(2	)		1
JCP&L		376		26		(6	)		8
Met-Ed		501		48		(7	)		5
Penelec		265		25		(7	)		4

								Interest and
2010	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,915	$	83	$	(86	)	$	37
FES		957		54		(58	)		22
OE		60		2		—			1
TE		107		3		—			1
JCP&L		281		9		(9	)		7
Met-Ed		377		9		(12	)		3
Penelec		134		6		(7	)		3

Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities

	June 30, 2011								December 31, 2010
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt Securities
FirstEnergy	$	414	$	84	$	—		498	$	476	$	91	$	—	$	567
OE		178		45		—		223		190		51		—		241
CEI		287		39		—		326		340		41		—		381

Approximate fair value and related carrying amounts of notes receivable

	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Notes Receivable
FirstEnergy	$	6	$	7	$	7	$	8
TE		82		94		104		118

FES

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2			Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	562		$	—	$	562
Derivative assets — commodity contracts		—		283			—		283
Derivative assets — FTRs		—		—			2		2
Equity securities(3)		96		—			—		96
Foreign government debt securities		—		160			—		160
U.S. government debt securities		—		316			—		316
U.S. state debt securities		—		7			—		7
Other(2)		—		42			—		42
Total assets	$	96	$	1,370		$	2	$	1,468
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(327	)	$	—	$	(327	)
Total liabilities	$	—	$	(327	)	$	—	$	(327	)
Net assets (liabilities)(1)	$	96	$	1,043		$	2	$	1,141

December 31, 2010	Level 1		Level 2			Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	528		$	—	$	528
Derivative assets — commodity contracts		—		241			—		241
Foreign government debt securities		—		147			—		147
U.S. government debt securities		—		308			—		308
U.S. state debt securities		—		6			—		6
Other(2)		—		148			—		148
Total assets	$	—	$	1,378		$	—	$	1,378
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—	$	(348	)
Total liabilities	$	—	$	(348	)	$	—	$	(348	)
Net assets (liabilities)(1)	$	—	$	1,030		$	—	$	1,030

(1)	Excludes $7 million as of December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)	Primarily consists of cash and cash equivalents.
(3)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

	Derivative Asset			Derivative Liability		Net
	FTRs			FTRs		FTRs
	(In millions)
January 1, 2011 Balance	$	—		$	—	$	—
Realized gain (loss)		—			—		—
Unrealized gain (loss)		1			—		1
Purchases		2			—		2
Issuances		—			—		—
Sales		—			—		—
Settlements		(1	)		—		(1	)
Transfers in (out) of Level 3		—			—		—
June 30, 2011 Balance	$	2		$	—	$	2

OE

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	131	$	—	$	131
Other		—		2		—		2
Total assets(1)	$	—	$	133	$	—	$	133

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	124	$	—	$	124
Other		—		2		—		2
Total assets(1)	$	—	$	126	$	—	$	126

⁽¹⁾ Excludes $2 million and $1 million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

TE

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	16	$	—	$	16
Equity securities(3)		26		—		—		26
U.S. government debt securities		—		33		—		33
U.S. state debt securities		—		1		—		1
Other(2)		—		3		—		3
Total assets(1)	$	26	$	53	$	—	$	79

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	7	$	—	$	7
U.S. government debt securities		—		33		—		33
U.S. state debt securities		—		1		—		1
Other(2)		—		35		—		35
Total assets(1)	$	—	$	76	$	—	$	76

(1)	Excludes $(1) million and $2 million as of June 30, 2011 and December 31, 2010, respectively of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)	Primarily consists of cash and cash equivalents.
(3)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

JCP&L

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	81	$	—		$	81
Derivative assets — NUG contracts(1)		—		—		5			5
Equity securities(2)		21		—		—			21
Foreign government debt securities		—		13		—			13
U.S. government debt securities		—		54		—			54
U.S. state debt securities		—		215		—			215
Other		—		14		—			14
Total assets	$	21	$	377	$	5		$	403
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(240	)	$	(240	)
Total liabilities	$	—	$	—	$	(240	)	$	(240	)
Net assets (liabilities)(3)	$	21	$	377	$	(235	)	$	163

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	23	$	—		$	23
Derivative assets — commodity contracts		—		2		—			2
Derivative assets — NUG contracts(1)		—		—		6			6
Equity securities(2)		96		—		—			96
U.S. government debt securities		—		33		—			33
U.S. state debt securities		—		236		—			236
Other		—		4		—			4
Total assets	$	96	$	298	$	6		$	400
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(233	)	$	(233	)
Total liabilities	$	—	$	—	$	(233	)	$	(233	)
Net assets (liabilities)(3)	$	96	$	298	$	(227	)	$	167

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $5 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	6		$	(233	)	$	(227	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(1	)		(71	)		(72	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		—			64			64
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	5		$	(240	)	$	(235	)
January 1, 2010 Balance	$	8		$	(399	)	$	(391	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(1	)		36			35
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(1	)		130			129
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	6		$	(233	)	$	(227	)

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

Met-Ed

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	138	$	—		$	138
Derivative assets — NUG contracts(1)		—		—		66			66
Equity securities(2)		33		—		—			33
Foreign government debt securities		—		20		—			20
U.S. government debt securities		—		87		—			87
U.S. state debt securities		—		2		—			2
Other		—		22		—			22
Total assets	$	33	$	269	$	66		$	368
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(122	)	$	(122	)
Total liabilities	$	—	$	—	$	(122	)	$	(122	)
Net assets (liabilities)(3)	$	33	$	269	$	(56	)	$	246

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	32	$	—		$	32
Derivative assets — commodity contracts		—		5		—			5
Derivative assets — NUG contracts(1)		—		—		112			112
Equity securities(2)		160		—		—			160
Foreign government debt securities		—		1		—			1
U.S. government debt securities		—		88		—			88
U.S. state debt securities		—		2		—			2
Other		—		14		—			14
Total assets	$	160	$	142	$	112		$	414
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(116	)	$	(116	)
Total liabilities	$	—	$	—	$	(116	)	$	(116	)
Net assets (liabilities)(3)	$	160	$	142	$	(4	)	$	298

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $(1) million and $(9) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	112		$	(116	)	$	(4	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(42	)		(36	)		(78	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(4	)		30			26
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	66		$	(122	)	$	(56	)
January 1, 2010 Balance	$	176		$	(143	)	$	33
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(59	)		(38	)		(97	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(5	)		65			60
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	112		$	(116	)	$	(4	)

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

Penelec

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	69	$	—		$	69
Derivative assets — NUG contracts(1)		—		—		4			4
Equity securities(2)		20		—		—			20
Foreign government debt securities				12					12
U.S. government debt securities		—		52		—			52
U.S. state debt securities		—		81		—			81
Other		—		53		—			53
Total assets	$	20	$	267	$	4		$	291
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(160	)	$	(160	)
Total liabilities	$	—	$	—	$	(160	)	$	(160	)
Net assets (liabilities)(3)	$	20	$	267	$	(156	)	$	131

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	8	$	—		$	8
Derivative assets — commodity contracts		—		2		—			2
Derivative assets — NUG contracts(1)		—		—		4			4
Equity securities(2)		81		—		—			81
U.S. government debt securities		—		9		—			9
U.S. state debt securities		—		133		—			133
Other		—		5		—			5
Total assets	$	81	$	157	$	4		$	242
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(117	)	$	(117	)
Total liabilities	$	—	$	—	$	(117	)	$	(117	)
Net assets (liabilities)(3)	$	81	$	157	$	(113	)	$	125

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $1 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	4		$	(117	)	$	(113	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		—			(88	)		(88	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		—			45			45
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	4		$	(160	)	$	(156	)
January 1, 2010 Balance	$	16		$	(101	)	$	(85	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(11	)		(108	)		(119	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(1	)		92			91
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	4		$	(117	)	$	(113	)

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

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Fair Value Measurements (Details 1) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
FES | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	$ 1,023	$ 980
Unrealized Gains	26	13
Unrealized Losses	0	0
Fair Value	1,049	993
FES | Equity Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	90	0
Unrealized Gains	6	0
Unrealized Losses	0	0
Fair Value	96	0
OE | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	128	123
Unrealized Gains	3	1
Unrealized Losses	0	0
Fair Value	131	124
TE | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	52	42
Unrealized Gains	1	0
Unrealized Losses	0	0
Fair Value	53	42
TE | Equity Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	24	0
Unrealized Gains	2	0
Unrealized Losses	0	0
Fair Value	26	0
JCP&L | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	353	281
Unrealized Gains	9	9
Unrealized Losses	0	0
Fair Value	362	290
JCP&L | Equity Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	21	80
Unrealized Gains	1	17
Unrealized Losses	0	0
Fair Value	22	97
Met-Ed | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	249	127
Unrealized Gains	5	4
Unrealized Losses	0	0
Fair Value	254	131
Met-Ed | Equity Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	32	125
Unrealized Gains	1	35
Unrealized Losses	0	0
Fair Value	33	160
Penelec | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	210	145
Unrealized Gains	4	4
Unrealized Losses	0	0
Fair Value	214	149
Penelec | Equity Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	20	63
Unrealized Gains	1	16
Unrealized Losses	0	0
Fair Value	21	79
Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	2,015	1,699
Unrealized Gains	48	31
Unrealized Losses	0	0
Fair Value	2,063	1,730
Equity Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	187	268
Unrealized Gains	11	69
Unrealized Losses	0	0
Fair Value	$ 198	$ 337

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Merger (Details 4) (USD $) In Thousands, except Per Share data	3 Months Ended				6 Months Ended				3 Months Ended	4 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011 Allegheny Energy Inc	Jun. 30, 2011 Allegheny Energy Inc
Revenue and earnings of Allegheny
Total revenues	$ 4,060,000	[1]	$ 3,139,000	[1]	$ 7,636,000	[1]	$ 6,438,000	[1]	$ 1,181,000	$ 1,618,000
NET INCOME	$ 171,000		$ 256,000		$ 216,000		$ 405,000		$ 63,000	$ 17,000
Basic Earnings Per Share	$ 0.43		$ 0.87		$ 0.61		$ 1.38		$ 0.15	$ 0.04
Diluted Earnings Per Share	$ 0.43		$ 0.87		$ 0.61		$ 1.37		$ 0.15	$ 0.04

[1] *Includes excise tax collections of $116 million and $99 million in the three months ended June 30,2011 and 2010, respectively, and $235 million and $208 million in the six months ended June 30, 2011 and 2010, respectively.

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Merger (Tables)

6 Months Ended

Jun. 30, 2011

Merger [Abstract]

Purchase price calculation

Shares of Allegheny common stock outstanding on February 24, 2011		170
Exchange ratio		0.667
Number of shares of FirstEnergy common stock issued		113
Closing price of FirstEnergy common stock on February 24, 2011	$	38.16
Fair value of shares issued by FirstEnergy	$	4,327
Fair value of replacement share-based compensation awards relating to pre-merger service		27
Total consideration transferred	$	4,354

The preliminary allocation of the total consideration transferred to the assets acquired and liabilities assumed

(In millions)
Current assets	$	1,494
Property, plant and equipment		9,656
Investments		138
Goodwill		881
Other noncurrent assets		1,347
Current liabilities		(716	)
Noncurrent liabilities		(3,452	)
Long-term debt and other long-term obligations		(4,994	)
	$	4,354

Goodwill recognized by segment

			Competitive		Regulated
	Regulated		Energy		Independent		Other/
(In millions)	Distribution		Services		Transmission		Corporate		Consolidated
Balance as of December 31, 2010	$	5,551	$	24	$	—	$	—	$	5,575
Merger with Allegheny		—		881		—		—		881
Balance as of June 30, 2011	$	5,551	$	905	$	—	$	—	$	6,456

The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger

	Preliminary		Weighted Average
(In millions)	Valuation		Amortization Period
Above market contracts:
Energy contracts	$	189	10 years
NUG contracts		124	25 years
Coal supply contracts		516	8 years
		829
Below market contracts:
NUG contracts		143	13 years
Coal supply contracts		83	7 years
Transportation contract		35	8 years
		261
Net intangible assets	$	568

Total intangible assets recorded

	Intangible
(In millions)	Assets
Purchase contract assets
NUG	$	198
OVEC		54
		252
Intangible assets
Coal contracts		487
FES customer intangible assets		129
Energy contracts		105
		721
Total intangible assets	$	973

Revenue and earnings of Allegheny

	April 1 –		February 26 –
(In millions, except per share amounts)	June 30, 2011		June 30, 2011
Total revenues	$	1,181	$	1,618
Earnings available to FirstEnergy Corp.(1)		63		17
Basic Earnings Per Share	$	0.15	$	0.04
Diluted Earnings Per Share	$	0.15	$	0.04

⁽¹⁾ Includes Allegheny’s after-tax merger costs of $4 million and $56 million, respectively.

Summary of consolidated results of operations

	Three Months Ended				Six Months Ended
(Pro forma amounts in millions, except	June 30				June 30
per share amounts)	2011		2010		2011		2010
Revenues	$	4,062	$	4,401	$	8,848	$	9,086
Earnings available to FirstEnergy	$	186	$	389	$	323	$	644
Basic Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.54
Diluted Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.53

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Regulatory Matters

6 Months Ended

Jun. 30, 2011

Regulatory Matters [Abstract]

REGULATORY MATTERS

10. REGULATORY MATTERS

(A) RELIABILITY INITIATIVES

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO charged with establishing and enforcing these reliability standards, although it has delegated day-to-day implementation and enforcement of these reliability standards 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 implemented and enforced by the ReliabilityFirst Corporation.

FirstEnergy believes that it generally is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such items are found, FirstEnergy develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to ReliabilityFirst. Moreover, it is clear that the NERC, ReliabilityFirst and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. The financial impact of complying with future new or amended standards cannot be determined at this time; however, 2005 amendments to the FPA provide that all prudent costs incurred to comply with the future reliability standards be recovered in rates. Still, any future inability on FirstEnergy’s part to comply with the reliability standards for its bulk power system could result in the imposition of financial penalties that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 resulting in customers losing power for up to eleven hours. 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. NERC has submitted first and second Requests for Information regarding this and another related matter. JCP&L is complying with these requests. JCP&L is not able to predict what actions, if any, that the NERC may take with respect to this matter.

On August 23, 2010, FirstEnergy self-reported to ReliabilityFirst a vegetation encroachment event on a Met-Ed 230 kV line. This event did not result in a fault, outage, operation of protective equipment, or any other meaningful electric effect on any FirstEnergy transmission facilities or systems. On August 25, 2010, ReliabilityFirst issued a Notice of Enforcement to investigate the incident. FirstEnergy submitted a data response to ReliabilityFirst on September 27, 2010. In March 2011, ReliabilityFirst submitted its proposed findings and settlement, although a final determination has not yet been made by FERC.

Allegheny has been subject to routine audits with respect to its compliance with applicable reliability standards and has settled certain related issues. In addition, ReliabilityFirst is currently conducting certain investigations with regard to certain matters of compliance by Allegheny.

(B) MARYLAND

By statute enacted in 2007, the obligation of Maryland utilities to provide standard offer service (SOS) to residential and small commercial customers, in exchange for recovery of their costs plus a reasonable profit, was extended indefinitely. The legislation also established a five-year cycle (to begin in 2008) for the MDPSC to report to the legislature on the status of SOS. PE now conducts rolling auctions to procure the power supply necessary to serve its customer load pursuant to a plan approved by the MDPSC. However, the terms on which PE will provide SOS to residential customers after the settlement beyond 2012 will depend on developments with respect to SOS in Maryland between now and then, including but not limited to possible MDPSC decisions in the proceedings discussed below.

The MDPSC opened a new docket in August 2007 to consider matters relating to possible “managed portfolio” approaches to SOS and other matters. “Phase II” of the case addressed utility purchases or construction of generation, bidding for procurement of demand response resources and possible alternatives if the TrAIL and PATH projects were delayed or defeated. It is unclear when the MDPSC will issue its findings in this and other SOS-related pending proceedings discussed below.

In September 2009, the MDPSC opened a new proceeding to receive and consider proposals for construction of new generation resources in Maryland. In December 2009, Governor Martin O’Malley filed a letter in this proceeding in which he characterized the electricity market in Maryland as a “failure” and urged the MDPSC to use its existing authority to order the construction of new generation in Maryland, vary the means used by utilities to procure generation and include more renewables in the generation mix. In August 2010, the MDPSC opened another new proceeding to solicit comments on the PJM RPM process. Public hearings on the comments were held in October 2010. In December 2010, the MDPSC issued an order soliciting comments on a model request for proposal for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and at this time no further proceedings have been set by the MDPSC in this matter.

In September 2007, the MDPSC issued an order that required the Maryland utilities to file detailed plans for how they will meet the “EmPOWER Maryland” proposal that electric consumption be reduced by 10% and electricity demand be reduced by 15%, in each case by 2015.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals. In 2008, PE filed its comprehensive plans for attempting to achieve those goals, asking the MDPSC to approve programs for residential, commercial, industrial, and governmental customers, as well as a customer education program. The MDPSC ultimately approved the programs in August 2009 after certain modifications had been made as required by the MDPSC, and approved cost recovery for the programs in October 2009. Expenditures were estimated to be approximately $101 million and would be recovered over the following six years. Meanwhile, extensive meetings with the MDPSC Staff and other stakeholders to discuss details of PE’s plans for additional and improved programs for the period 2012-2014 began in April 2011 and those programs are to be filed by September 1, 2011.

In March 2009, the MDPSC issued an order suspending until further notice the right of all electric and gas utilities in the state to terminate service to residential customers for non-payment of bills. The MDPSC subsequently issued an order making various rule changes relating to terminations, payment plans, and customer deposits that make it more difficult for Maryland utilities to collect deposits or to terminate service for non-payment. The MDPSC is continuing to conduct hearings and collect data on payment plan and related issues and has adopted a set of proposed regulations that expand the summer and winter “severe weather” termination moratoria when temperatures are very high or very low, from one day, as provided by statute, to three days on each occurrence.

On March 24, 2011, the MDPSC held an initial hearing to discuss possible new regulations relating to service interruptions, storm response, call center metrics, and related reliability standards. The proposed rules included provisions for civil penalties for non-compliance. Numerous parties filed comments on the proposed rules and participated in the hearing, with many noting issues of cost and practicality relating to implementation. The Maryland legislature passed a bill on April 11, 2011, which requires the MDPSC to promulgate rules by July 1, 2012 that address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. In crafting the regulations, the legislation directs the MDPSC to consider cost-effectiveness, and provides that the MDPSC may adopt different standards for different utilities based on such factors as system design and existing infrastructure, geography, and customer density. Beginning in July 2013, the MDPSC is to assess each utility’s compliance with the standards, and may assess penalties of up to $25,000 per day per violation. The MDPSC has ordered that a working group of utilities, regulators, and other interested stakeholders meet to address the topics of the proposed rules, with proposed rules to be filed by September 15, 2011. Separately, on April 7, 2011, the MDPSC initiated a rulemaking with respect to issues related to contact voltage. On June 3, 2011, the MDPSC’s Staff issued a report and draft regulations. Comments on the draft regulations were submitted on June 17, 2011, and a hearing was held July 7, 2011. Final regulations related to contact voltage have not yet been adopted.

(C) NEW JERSEY

In March 2009 and again in February 2010, JCP&L filed annual SBC Petitions with the NJBPU that included a requested zero level of recovery of TMI-2 decommissioning costs based on an updated TMI-2 decommissioning cost analysis dated January 2009 estimated at $736 million (in 2003 dollars). In its order of June 15, 2011, the NJBPU adopted a Stipulation reached among JCP&L, the NJBPU Staff and the Division of Rate Counsel which resolved both Petitions, resulting in a net reduction in recovery of $0.8 million annually for all components of the SBC (including, as requested, a zero level of recovery of TMI-2 decommissioning costs).

(D) OHIO

The Ohio Companies operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include: generation supplied through a CBP commencing June 1, 2011 (initial auctions held on October 20, 2010 and January 25, 2011); a load cap of no less than 80%, which also applies to tranches assigned post-auction; a 6% generation discount to certain low income customers provided by the Ohio Companies through a bilateral wholesale contract with FES (FES is one of the wholesale suppliers to the Ohio Companies); no increase in base distribution rates through May 31, 2014; and a new distribution rider, Delivery Capital Recovery Rider (Rider DCR), to recover a return of, and on, capital investments in the delivery system. The Ohio Companies also agreed not to recover from retail customers certain costs related to transmission cost allocations by PJM as a result of ATSI’s integration into PJM for the longer of the five-year period from June 1, 2011 through May 31, 2015 or when the amount of costs avoided by customers for certain types of products totals $360 million dependent on the outcome of certain PJM proceedings, agreed to establish a $12 million fund to assist low income customers over the term of the ESP and agreed to additional matters related to energy efficiency and alternative energy requirements.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent to 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 were also required to reduce peak demand in 2009 by 1%, with an additional 0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed the required three year portfolio plan seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The Ohio Companies expect that all costs associated with compliance will be recoverable from customers. The PUCO issued an Opinion and Order generally approving the Ohio Companies’ 3-year plan, and the Companies are in the process of implementing those programs included in the Plan. OE fell short of its statutory 2010 energy efficiency and peak demand reduction benchmarks and therefore, on January 11, 2011, it requested that its 2010 energy efficiency and peak demand reduction benchmarks be amended to actual levels achieved in 2010. The PUCO granted this request on May 19, 2011 for OE, finding that the motion was moot for CEI and TE. Moreover, because the PUCO indicated, when approving the 2009 benchmark request, that it would modify the Companies’ 2010 (and 2011 and 2012) energy efficiency benchmarks when addressing the portfolio plan, the Ohio Companies were not certain of their 2010 energy efficiency obligations. Therefore, CEI and TE (each of which achieved its 2010 energy efficiency and peak demand reduction statutory benchmarks) also requested an amendment if and only to the degree one was deemed necessary to bring them into compliance with their yet-to-be-defined modified benchmarks. On June 2, 2011, the Companies filed an application for rehearing to clarify the decision related to CEI and TE. Failure to comply with the benchmarks or to obtain such an amendment may subject the companies to an assessment by the PUCO of a penalty. In addition to approving the programs included in the plan, with only minor modifications, the PUCO authorized the Companies to recover all costs related to the original CFL program that the Ohio Companies had previously suspended at the request of the PUCO. Applications for Rehearing were filed on April 22, 2011, regarding portions of the PUCO’s decision, including the method for calculating savings and certain changes made by the PUCO to specific programs. On May 4, 2011, the PUCO granted applications for rehearing for the purpose of further consideration; however, no substantive ruling has been issued.

Additionally under SB221, electric utilities and electric service companies are required to serve part of their load from renewable energy resources equivalent to 0.25% of the KWH they served in 2009 and 0.50% of the KWH they served in 2010. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through these two RFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In March 2010, the PUCO found that there was an insufficient quantity of solar energy resources reasonably available in the market and reduced the Ohio Companies’ aggregate 2009 benchmark to the level of solar RECs the Ohio Companies acquired through their 2009 RFP processes, provided the Ohio Companies’ 2010 alternative energy requirements be increased to include the shortfall for the 2009 solar REC benchmark. FES also applied for a force majeure determination from the PUCO regarding a portion of their compliance with the 2009 solar energy resource benchmark. On February 23, 2011, the PUCO granted FES’ force majeure request for 2009 and increased its 2010 benchmark by the amount of SRECs that FES was short of in its 2009 benchmark. On April 15, 2011, the Ohio Companies filed an application seeking an amendment to each of their 2010 alternative energy requirements for solar RECs generated in Ohio on the basis that an insufficient quantity of solar resources are available in the market but reflecting solar RECs that they have obtained and providing additional information regarding efforts to secure solar RECs. Other parties to the proceeding filed comments asserting that the force majeure determination should not be granted, and others requesting the PUCO to review the costs the Ohio companies’ have incurred to comply with the renewable energy requirements. The PUCO has not yet acted on that application.

In February 2010, OE and CEI filed an application with the PUCO to establish a new credit for all-electric customers. In March 2010, the PUCO ordered that rates for the affected customers be set at a level that will provide bill impacts commensurate with charges in place on December 31, 2008 and authorized the Ohio Companies to defer incurred costs equivalent to the difference between what the affected customers would have paid under previously existing rates and what they pay with the new credit in place. Tariffs implementing this new credit went into effect in March 2010. In April 2010, the PUCO issued a Second Entry on Rehearing that expanded the group of customers to which the new credit would apply and authorized deferral for the associated additional amounts. The PUCO also stated that it expected that the new credit would remain in place through at least the 2011 winter season and charged its staff to work with parties to seek a long term solution to the issue. Tariffs implementing this newly expanded credit went into effect in May 2010 and the proceeding remains open. The hearing on the matter was held in February 2011. The PUCO modified and approved the companies’ application on May 25, 2011, ruling that the new credit be phased out over an eight-year period and granting authority for the companies to recover deferred costs and associated carrying charges. OCC filed applications for rehearing on June 24, 2011 and the Ohio Companies filed their responses on July 5, 2011. The PUCO has not yet acted on the applications for rehearing.

(E) PENNSYLVANIA

The PPUC entered an Order on March 3, 2010 that denied the recovery of marginal transmission losses through the TSC rider for the period of June 1, 2007 through March 31, 2008, directed Met-Ed and Penelec to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC, and instructed Met-Ed and Penelec to work with the various intervening parties to file a recommendation to the PPUC regarding the establishment of a separate account for all marginal transmission losses collected from ratepayers plus interest to be used to mitigate future generation rate increases beginning January 1, 2011. In March 2010, Met-Ed and Penelec filed a Petition with the PPUC requesting that it stay the portion of the March 3, 2010 Order requiring the filing of tariff supplements to end collection of costs for marginal transmission losses. The PPUC granted the requested stay until December 31, 2010. Pursuant to the PPUC’s order, Met-Ed and Penelec filed plans to establish separate accounts for marginal transmission loss revenues and related interest and carrying charges. Pursuant to the plan approved by the PPUC, Met-Ed and Penelec began to refund those amounts to customers in January 2011, and the refunds will continue over a 29 month period until the full amounts previously recovered for marginal transmission loses are refunded. In April 2010, Met-Ed and Penelec filed a Petition for Review with the Commonwealth Court of Pennsylvania appealing the PPUC’s March 3, 2010 Order. On June 14, 2011, the Commonwealth Court issued an opinion and order affirming the PPUC’s Order to the extent that it holds that line loss costs are not transmission costs and, therefore, the approximately $254 million in marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under Met-Ed’s and Penelec’s TSC riders. Met-Ed and Penelec filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in federal district court. Although the ultimate outcome of this matter cannot be determined at this time, Met-Ed and Penelec believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately $254 million ($189 million for Met-Ed and $65 million for Penelec) in marginal transmission losses for the period prior to January 1, 2011.

In May 2008, May 2009 and May 2010, the PPUC approved Met-Ed’s and Penelec’s annual updates to their TSC rider for the annual periods between June 1, 2008 to December 31, 2010, including marginal transmission losses as approved by the PPUC, although the recovery of marginal losses will be subject to the outcome of the proceeding related to the 2008 TSC filing as described above. The PPUC’s approval in May 2010 authorized an increase to the TSC for Met-Ed’s customers to provide for full recovery by December 31, 2010.

In February 2010, Penn filed a Petition for Approval of its Default Service Plan for the period June 1, 2011 through May 31, 2013. In July 2010, the parties to the proceeding filed a Joint Petition for Settlement of all issues. Although the PPUC’s Order approving the Joint Petition held that the provisions relating to the recovery of MISO exit fees and one-time PJM integration costs (resulting from Penn’s June 1, 2011 exit from MISO and integration into PJM) were approved, it made such provisions subject to the approval of cost recovery by FERC. Therefore, Penn may not put these provisions into effect until FERC has approved the recovery and allocation of MISO exit fees and PJM integration costs.

Pennsylvania adopted Act 129 in 2008 to address issues such as: energy efficiency and peak load reduction; generation procurement; time-of-use rates; smart meters; and alternative energy. Among other things, Act 129 required utilities to file with the PPUC an energy efficiency and peak load reduction plan, or EE&C Plan, by July 1, 2009, setting forth the utilities’ plans to reduce energy consumption by a minimum of 1% and 3% by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of 4.5% by May 31, 2013. Act 129 also required utilities to file with the PPUC a Smart Meter Implementation Plan (SMIP).

The PPUC entered an Order in February 2010 giving final approval to all aspects of the EE&C Plans of Met-Ed, Penelec and Penn and the tariff rider with rates effective March 1, 2010. On February 18, 2011, the companies filed a petition to approve their First Amended EE&C Plans. On June 28, 2011, a hearing on the petition was held before an administrative law judge.

WP filed its original EE&C Plan in June 2009, which the PPUC approved, in large part, by Opinion and Order entered in October 2009. In November 2009, the Office of Consumer Advocate (OCA) filed an appeal with the Commonwealth Court of the PPUC’s October Order. The OCA contends that the PPUC’s Order failed to include WP’s costs for smart meter implementation in the EE&C Plan, and that inclusion of such costs would cause the EE&C Plan to exceed the statutory cap for EE&C expenditures. The OCA also contends that WP’s EE&C plan does not meet the Total Resource Cost Test. The appeal remains pending but has been stayed by the Commonwealth Court pending possible settlement of WP’s SMIP. In September 2010, WP filed an amended EE&C Plan that is less reliant on smart meter deployment, which the PPUC approved in January 2011.

Met-Ed, Penelec and Penn jointly filed a SMIP with the PPUC in August 2009. This plan proposed a 24-month assessment period in which Met-Ed, Penelec and Penn will assess their needs, select the necessary technology, secure vendors, train personnel, install and test support equipment, and establish a cost effective and strategic deployment schedule, which currently is expected to be completed in fifteen years. Met-Ed, Penelec and Penn estimate assessment period costs of approximately $29.5 million, which the Met-Ed, Penelec and Penn, in their plan, proposed to recover through an automatic adjustment clause. The ALJ’s Initial Decision approved the SMIP as modified by the ALJ, including: ensuring that the smart meters to be deployed include the capabilities listed in the PPUC’s Implementation Order; denying the recovery of interest through the automatic adjustment clause; providing for the recovery of reasonable and prudent costs net of resulting savings from installation and use of smart meters; and requiring that administrative start-up costs be expensed and the costs incurred for research and development in the assessment period be capitalized. The PPUC entered its Order in June 2010, consistent with the Chairman’s Motion. Met-Ed, Penelec and Penn filed a Petition for Reconsideration of a single portion of the PPUC’s Order regarding the future ability to include smart meter costs in base rates, which the PPUC granted in part by deleting language from its original order that would have precluded Met-Ed, Penelec and Penn from seeking to include smart meter costs in base rates at a later time. The costs to implement the SMIP could be material. However, assuming these costs satisfy a just and reasonable standard, they are expected to be recovered in a rider (Smart Meter Technologies Charge Rider) which was approved when the PPUC approved the SMIP.

In August 2009, WP filed its original SMIP, which provided for extensive deployment of smart meter infrastructure with replacement of all of WP’s approximately 725,000 meters by the end of 2014. In December 2009, WP filed a motion to reopen the evidentiary record to submit an alternative smart meter plan proposing, among other things, a less-rapid deployment of smart meters. In an Initial Decision dated April 29, 2010, an ALJ determined that WP’s alternative smart meter deployment plan, complied with the requirements of Act 129 and recommended approval of the alternative plan, including WP’s proposed cost recovery mechanism.

In light of the significant expenditures that would be associated with its smart meter deployment plans and related infrastructure upgrades, as well as its evaluation of recent PPUC decisions approving less-rapid deployment proposals by other utilities, WP re-evaluated its Act 129 compliance strategy, including both its plans with respect to smart meter deployment and certain smart meter dependent aspects of the EE&C Plan. In October 2010, WP and Pennsylvania’s OCA filed a Joint Petition for Settlement addressing WP’s smart meter implementation plan with the PPUC. Under the terms of the proposed settlement, WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately 25,000 smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. The proposed settlement also contemplates that WP take advantage of the 30-month grace period authorized by the PPUC to continue WP’s efforts to re-evaluate full-scale smart meter deployment plans. WP currently anticipates filing its plan for full-scale deployment of smart meters in June 2012. Under the terms of the proposed settlement, WP would be permitted to recover certain previously incurred and anticipated smart-meter related expenditures through a levelized customer surcharge, with certain expenditures amortized over a ten-year period. Additionally, WP would be permitted to seek recovery of certain other costs as part of its revised SMIP that it currently intends to file in June 2012, or in a future base distribution rate case.

In December 2010, the PPUC directed that the SMIP proceeding be referred to the ALJ for further proceedings to ensure that the impact of the proposed merger with FirstEnergy is considered and that the Joint Petition for Settlement has adequate support in the record. On March 9, 2011, WP submitted an Amended Joint Petition for Settlement which restates the Joint Petition for Settlement filed in October 2010, adds the PPUC’s Office of Trial Staff as a signatory party, and confirms the support or non-opposition of all parties to the settlement. One party retained the ability to challenge the recovery of amounts spent on WP’s original smart meter implementation plan. The proposed settlement also obligates OCA to withdraw its November 2009 appeal of the PPUC’s Order in WP’s EE&C plan proceeding. A Joint Stipulation with the OSBA was also filed on March 9, 2011. On May 3, 2011, the ALJ issued an Initial Decision recommending that the PPUC approve the Amended Joint Petition for Full Settlement. The PPUC approved the Initial Decision by order entered June 30, 2011.

By Tentative Order entered in September 2009, the PPUC provided for an additional 30-day comment period on whether the 1998 Restructuring Settlement, which addressed how Met-Ed and Penelec were going to implement direct access to a competitive market for the generation of electricity, allows Met-Ed and Penelec to apply over-collection of NUG costs for select and isolated months to reduce non-NUG stranded costs when a cumulative NUG stranded cost balance exists. In response to the Tentative Order, various parties filed comments objecting to the above accounting method utilized by Met-Ed and Penelec. Met-Ed and Penelec are awaiting further action by the PPUC.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania’s retail electricity market will be conducted with the goal of making recommendations for improvements to ensure that a properly functioning and workable competitive retail electricity market exists in the state. On April 29, 2011, the PPUC entered an Order initiating the investigation and requesting comments from interested parties on eleven directed questions. Met-Ed, Penelec, Penn Power and West Penn submitted joint comments on June 3, 2011. FES also submitted comments on June 3, 2011. On June 8, 2011, the PPUC conducted an en banc hearing on these issues at which both the Pennsylvania Companies and FES participated and offered testimony.

(F) VIRGINIA

In September 2010, PATH-VA filed an application with the VSCC for authorization to construct the Virginia portions of the PATH Project. On February 28, 2011, PATH-VA filed a motion to withdraw the application. On May 24, 2011, the VSCC granted PATH-VA’s motion to withdraw its application for authorization to construct the Virginia portions of the PATH Project. See “Transmission Expansion” in the Federal Regulation and Rate Matters section for further discussion of this matter.

(G) WEST VIRGINIA

In August 2009, MP and PE filed with the WVPSC a request to increase retail rates, which was amended through subsequent filings. MP and PE ultimately requested an annual increase in retail rates of approximately $95 million. In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in the proceeding that provided for:

• a $40 million annualized base rate increase effective June 29, 2010;

• a deferral of February 2010 storm restoration expenses in West Virginia over a maximum five-year period;

• an additional $20 million annualized base rate increase effective in January 2011;

• a decrease of $20 million in ENEC rates effective January 2011, which amount is deferred for later recovery in 2012; and

• a moratorium on filing for further increases in base rates before December 1, 2011, except under specified circumstances.

The WVPSC approved the Joint Petition and Agreement of Settlement in June 2010.

In 2009, the West Virginia Legislature enacted the Alternative and Renewable Energy Portfolio Act (Portfolio Act), which generally requires that a specified minimum percentage of electricity sold to retail customers in West Virginia by electric utilities each year be derived from alternative and renewable energy resources according to a predetermined schedule of increasing percentage targets, including ten percent by 2015, fifteen percent by 2020, and twenty-five percent by 2025. In November 2010, the WVPSC issued Rules Governing Alternative and Renewable Energy Portfolio Standard (RPS Rules), which became effective on January 4, 2011. Under the RPS Rules, on or before January 1, 2011, each electric utility subject to the provisions of this rule was required to prepare an alternative and renewable energy portfolio standard compliance plan and file an application with the WVPSC seeking approval of such plan. MP and PE filed their combined compliance plan in December 2010. A hearing was held at the WVPSC on June 13, 2011. An order is expected by late September 2011.

Additionally, in January 2011, MP and PE filed an application with the WVPSC seeking to certify three facilities as Qualified Energy Resource Facilities. If the application is approved, the three facilities would then be capable of generating renewable credits which would assist the companies in meeting their combined requirements under the Portfolio Act. Further, in February 2011, MP and PE filed a petition with the WVPSC seeking an Order declaring that MP is entitled to all alternative and renewable energy resource credits associated with the electric energy, or energy and capacity, that MP is required to purchase pursuant to electric energy purchase agreements between MP and three non-utility electric generating facilities in WV. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, has participated in the case in opposition to the Petition.

(H) FERC MATTERS

Rates for Transmission Service Between MISO and PJM

In November 2004, FERC issued an order eliminating the through and out rate for transmission service between the MISO and PJM regions. 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 SECA) during a 16-month transition period. In 2005, FERC set the SECA for hearing. The presiding ALJ issued an initial decision in August 2006, rejecting the compliance filings made by MISO, PJM and the transmission owners, and directing new compliance filings. This decision was subject to review and approval by FERC. In May 2010, FERC issued an order denying pending rehearing requests and an Order on Initial Decision which reversed the presiding ALJ’s rulings in many respects. Most notably, these orders affirmed the right of transmission owners to collect SECA charges with adjustments that modestly reduce the level of such charges, and changes to the entities deemed responsible for payment of the SECA charges. The Ohio Companies were identified as load serving entities responsible for payment of additional SECA charges for a portion of the SECA period (Green Mountain/Quest issue). FirstEnergy executed settlements with AEP, Dayton and the Exelon parties to fix FirstEnergy’s liability for SECA charges originally billed to Green Mountain and Quest for load that returned to regulated service during the SECA period. The AEP, Dayton and Exelon, settlements were approved by FERC in November 2010, and the relevant payments made. The subsidiaries of Allegheny entered into nine settlements to fix their liability for SECA charges with various parties. All of the settlements were approved by FERC and the relevant payments have been made for eight of the settlements. Payments due under the remaining settlement will be made as a part of the refund obligations of the Utilities that are under review by FERC as part of a compliance filing. Potential refund obligations of FirstEnergy and the Allegheny subsidiaries are not expected to be material. Rehearings remain pending in this proceeding.

PJM Transmission Rate

In April 2007, 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, 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 based on the amount of load served in a transmission zone. Costs for new transmission facilities that are rated at less than 500 kV, however, are to be allocated on a load flow methodology (DFAX), which is generally referred to as a “beneficiary pays” approach to allocating the cost of high voltage transmission facilities.

FERC’s Opinion 494 order was appealed to the U.S. Court of Appeals for the Seventh Circuit, which issued a decision in August 2009. The court affirmed FERC’s ratemaking treatment for existing transmission facilities, but found that FERC had not supported its decision to allocate costs for new 500+ kV facilities on a load ratio share basis and, based on this finding, remanded the rate design issue back to FERC.

In an order dated January 21, 2010, FERC set the matter for a “paper hearing"— meaning that FERC called for parties to submit written comments pursuant to the schedule described in the order. FERC identified nine separate issues for comments and directed PJM to file the first round of comments on February 22, 2010, with other parties submitting responsive comments and then reply comments on later dates. PJM filed certain studies with FERC on April 13, 2010, in response to the FERC order. PJM’s filing demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain eastern utilities in PJM bearing the majority of the costs. Numerous parties filed responsive comments or studies on May 28, 2010 and reply comments on June 28, 2010. FirstEnergy and a number of other utilities, industrial customers and state commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Certain eastern utilities and their state commissions supported continued socialization of these costs on a load ratio share basis. This matter is awaiting action by FERC.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone entered into PJM. The move was performed as planned with no known operational or reliability issues for ATSI or for the wholesale transmission customers in the ATSI zone.

On February 1, 2011, ATSI in conjunction with PJM filed its proposal with FERC for moving its transmission rate into PJM’s tariffs. On April 1, 2011, the MISO Transmission Owners (including ATSI) filed proposed tariff language that describes the mechanics of collecting and administering MTEP costs from ATSI-zone ratepayers. From March 20, 2011 through April 1, 2011, FirstEnergy, PJM and the MISO submitted numerous filings for the purpose of effecting movement of the ATSI zone to PJM on June 1, 2011. These filings include amendments to the MISO’s tariffs (to remove the ATSI zone), submission of load and generation interconnection agreements to reflect the move into PJM, and submission of changes to PJM’s tariffs to support the move into PJM.

On May 31, 2011, FERC issued orders that address the proposed ATSI transmission rate, and certain parts of the MISO tariffs that reflect the mechanics of transmission cost allocation and collection. In its May 31, 2011 orders, FERC approved ATSI’s proposal to move the ATSI formula rate into the PJM tariff without significant change. Speaking to ATSI’s proposed treatment of the MISO’s exit fees and charges for transmission costs that were allocated to the ATSI zone, FERC required ATSI to present a cost-benefit study that demonstrates that the benefits of the move for transmission customers exceed the costs of any such move, which FERC had not previously required. Accordingly, FERC ruled that these costs must be removed from ATSI’s proposed transmission rates until such time as ATSI files and FERC approves the cost-benefit study. On June 30, 2011, ATSI submitted the compliance filing that removed the MISO exit fees and transmission cost allocation charges from ATSI’s proposed transmission rates. Also on June 30, 2011, ATSI requested rehearing of FERC’s decision to require a cost-benefit study analysis as part of FERC’s evaluation of ATSI’s proposed transmission rates. The compliance filing, and ATSI’s request for rehearing, are currently pending before FERC.

From late April 2011 through June 2011, FERC issued other orders that address ATSI’s move into PJM. These orders approve ATSI’s proposed interconnection agreements for large wholesale transmission customers and generators, and revisions to the PJM and MISO tariffs that reflect ATSI’s move into PJM. In addition, FERC approved an “Exit Fee Agreement” that memorializes the agreement between ATSI and MISO with regard to ATSI’s obligation to pay certain administrative charges to the MISO upon exit. Finally, ATSI and the MISO were able to negotiate an agreement of ATSI’s responsibility for certain charges associated with long term firm transmission rights — that, according to the MISO, were payable by the ATSI zone upon its departure from the MISO. ATSI did not and does not agree that these costs should be charged to ATSI but, in order to settle the case and all claims associated with the case, ATSI agreed to a one-time payment of $1.8 million to the MISO. This settlement agreement has been submitted for FERC’s review and approval. The final outcome of those proceedings that address the remaining open issues related to ATSI’s move into PJM and their impact, if any, on FirstEnergy cannot be predicted at this time.

MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners jointly filed with FERC their proposed cost allocation methodology for certain new transmission projects. The new transmission projects—described as MVPs — are a class of transmission projects that are approved via MISO’s formal transmission planning process (the MTEP). The filing parties proposed to allocate the costs of MVPs by means of a usage-based charge that will be applied to all loads within the MISO footprint, and to energy transactions that call for power to be “wheeled through” the MISO as well as to energy transactions that “source” in the MISO but “sink” outside of MISO. The filing parties expect that the MVP proposal will fund the costs of large transmission projects designed to bring wind generation from the upper Midwest to load centers in the east. The filing parties requested an effective date for the proposal of July 16, 2011. On August 19, 2010, MISO’s Board approved the first MVP project — the “Michigan Thumb Project.” Under MISO’s proposal, the costs of MVP projects approved by MISO’s Board prior to the June 1, 2011 effective date of FirstEnergy’s integration into PJM would continue to be allocated to FirstEnergy. MISO estimated that approximately $15 million in annual revenue requirements would be allocated to the ATSI zone associated with the Michigan Thumb Project upon its completion.

In September 2010, FirstEnergy filed a protest to the MVP proposal arguing that MISO’s proposal to allocate costs of MVPs projects across the entire MISO footprint does not align with the established rule that cost allocation is to be based on cost causation (the “beneficiary pays” approach). FirstEnergy also argued that, in light of progress that had been made to date in the ATSI integration into PJM, it would be unjust and unreasonable to allocate any MVP costs to the ATSI zone, or to ATSI. Numerous other parties filed pleadings on MISO’s MVP proposal.

In December 2010, FERC issued an order approving the MVP proposal without significant change. FERC’s order was not clear, however, as to whether the MVP costs would be payable by ATSI or load in the ATSI zone. FERC stated that the MISO’s tariffs obligate ATSI to pay all charges that attached prior to ATSI’s exit but ruled that the question of the amount of costs that are to be allocated to ATSI or to load in the ATSI zone were beyond the scope of FERC’s order and would be addressed in future proceedings.

On January 18, 2011, FirstEnergy filed for rehearing of FERC’s order. In its rehearing request, FirstEnergy argued that because the MVP rate is usage-based, costs could not be applied to ATSI, which is a stand-alone transmission company that does not use the transmission system. FirstEnergy also renewed its arguments regarding cost causation and the impropriety of allocating costs to the ATSI zone or to ATSI.

As noted above, on February 1, 2011, ATSI filed proposed transmission rates related to its move into PJM. The proposed rates included line items that were intended to recover all MVP costs (if any) that might be charged to ATSI or to the ATSI zone. In its May 31, 2011 order on ATSI’s proposed transmission rates FERC ruled that ATSI must submit a cost-benefit study before ATSI can recover the MVP costs. FERC further directed that ATSI remove the line-items from ATSI’s formula rate that would recover the MVP costs until such time as ATSI submits and FERC approves the cost- benefit study. ATSI requested a rehearing of these parts of FERC’s order and, pending this further legal process, has removed the MVP line items from its transmission rates.

FirstEnergy cannot predict the outcome of these proceedings at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the California Department of Water Resources (CDWR) during 2001. The settlement proposal claims that CDWR is owed approximately $190 million for these alleged overcharges. This proposal was made in the context of mediation efforts by FERC and the United States Court of Appeals for the Ninth Circuit in pending proceedings to resolve all outstanding refund and other claims, including claims of alleged price manipulation in the California energy markets during 2000 and 2001. The Ninth Circuit has since remanded one of those proceedings to FERC, which arises out of claims previously filed with FERC by the California Attorney General on behalf of certain California parties against various sellers in the California wholesale power market, including AE Supply (the Lockyer case). AE Supply and several other sellers filed motions to dismiss the Lockyer case. In March 2010, the judge assigned to the case entered an opinion that granted the motions to dismiss filed by AE Supply and other sellers and dismissed the claims of the California Parties. On May 4, 2011, FERC affirmed the judge’s ruling.

In June 2009, the California Attorney General, on behalf of certain California parties, filed a second complaint with FERC against various sellers, including AE Supply (the Brown case), again seeking refunds for trades in the California energy markets during 2000 and 2001. The above-noted trades with CDWR are the basis for including AE Supply in this new complaint. AE Supply filed a motion to dismiss the Brown complaint that was granted by FERC on May 24, 2011. On June 23, 2011, the California Attorney General requested rehearing of the May 24, 2011 order. FirstEnergy cannot predict the outcome of this matter.

Transmission Expansion

TrAIL Project. TrAIL is a 500 kV transmission line extending from southwest Pennsylvania through West Virginia and into northern Virginia. Effective May 19, 2011, all segments of TrAIL were energized and in service.

PATH Project. The PATH Project is comprised of a 765 kV transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland.

PJM initially authorized construction of the PATH Project in June 2007. In December 2010, PJM advised that its 2011 Load Forecast Report included load projections that are different from previous forecasts and that may have an impact on the proposed in-service date for the PATH Project. As part of its 2011 RTEP, and in response to a January 19, 2011 directive by a Virginia Hearing Examiner, PJM conducted a series of analyses using the most current economic forecasts and demand response commitments, as well as potential new generation resources. Preliminary analysis revealed the expected reliability violations that necessitated the PATH Project had moved several years into the future. Based on those results, PJM announced on February 28, 2011 that its Board of Managers had decided to hold the PATH Project in abeyance in its 2011 RTEP and directed FirstEnergy and AEP, as the sponsoring transmission owners, to suspend current development efforts on the project, subject to those activities necessary to maintain the project in its current state, while PJM conducts more rigorous analysis of the need for the project as part of its continuing RTEP process. PJM stated that its action did not constitute a directive to FirstEnergy and AEP to cancel or abandon the PATH Project. PJM further stated that it will complete a more rigorous analysis of the PATH Project and other transmission requirements and its Board will review this comprehensive analysis as part of its consideration of the 2011 RTEP. On February 28, 2011, affiliates of FirstEnergy and AEP filed motions or notices to withdraw applications for authorization to construct the project that were pending before state commissions in West Virginia, Virginia and Maryland. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

PATH, LLC submitted a filing to FERC to implement a formula rate tariff effective March 1, 2008. In a November 19, 2010 order addressing various matters relating to the formula rate, FERC set the project’s base return on equity for hearing and reaffirmed its prior authorization of a return on CWIP, recovery of start-up costs and recovery of abandonment costs. In the order, FERC also granted a 1.5% return on equity incentive adder and a 0.50% return on equity adder for RTO participation. These adders will be applied to the base return on equity determined as a result of the hearing. PATH, LLC is currently engaged in settlement discussions with the staff of FERC and intervenors regarding resolution of the base return on equity.

Seneca Pumped Storage Project Relicensing

The Seneca (Kinzua) Pumped Storage Project is a 451 MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FGCO. FGCO holds the current FERC license that authorizes ownership and operation of the project. The current FERC license will expire on November 30, 2015. FERC’s regulations call for a five-year relicensing process. On November 24, 2010, and acting pursuant to applicable FERC regulations and rules, FGCO initiated the relicensing process by filing its notice of intent to relicense and pre-application document (PAD) in the license docket.

On November 30, 2010, the Seneca Nation of Indians filed its notice of intent to relicense and PAD documents necessary for them to submit a competing application. Section 15 of the FPA contemplates that third parties may file a ‘competing application’ to assume ownership and operation of a hydroelectric facility upon (i) relicensure and (ii) payment of net book value of the plant to the original owner/operator. Nonetheless, FGCO believes it is entitled to a statutory “incumbent preference” under Section 15.

The Seneca Nation and certain other intervenors have asked FERC to redefine the “project boundary” of the hydroelectric plant to include the dam and reservoir facilities operated by the U.S. Army Corps. of Engineers. On May 16, 2011, FirstEnergy filed a Petition for Declaratory Order with FERC seeking an order to exclude the dam and reservoir facilities from the project. The Seneca Nation, the New York State Department of Environmental Conservation, and the U.S. Department of Interior each submitted responses to FirstEnergy’s petition, including motions to dismiss FirstEnergy’s petition. The “project boundary” issue is pending before FERC.

The next steps in the relicensing process are for FirstEnergy and the Seneca Nation to define and perform certain environmental and operational studies to support their respective applications. These steps are expected to run through approximately November of 2013. FirstEnergy cannot predict the outcome of these proceedings at this time.

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Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2011

Organization and Basis of Presentation [Abstract]

ORGANIZATION AND BASIS OF PRESENTATION

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, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and TrAIL), FES and its subsidiaries FGCO and NGC, and FESC. AE merged with a subsidiary of FirstEnergy on February 25, 2011, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy (See Note 2, Merger).

FirstEnergy and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC and the NJBPU. These unaudited interim financial statements and notes were prepared in accordance with GAAP for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. The preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not indicative of results of operations for any future period.

These unaudited interim financial 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, 2010 for FirstEnergy, FES and the Utility Registrants, as applicable. The consolidated unaudited financial statements of FirstEnergy, FES and each of the Utility Registrants reflect all normal recurring adjustments that, in the opinion of management, are necessary to fairly present results of operations for the interim periods. Certain prior year amounts have been reclassified to conform to the current year presentation. Unless otherwise indicated, defined terms used herein have the meanings set forth in the accompanying Glossary of Terms.

FirstEnergy and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary (see Note 7, Variable Interest Entities). Investments in affiliates over which FirstEnergy and its subsidiaries have the ability to exercise significant influence, but with respect to which are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income.

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Merger (Details 1) (USD $)	6 Months Ended					6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011 Regulated Distribution	Dec. 31, 2010 Regulated Distribution	Jun. 30, 2010 Regulated Distribution	Jun. 30, 2011 Competitive Energy Services	Jun. 30, 2010 Competitive Energy Services	Jun. 30, 2011 Regulated Independent Transmission	Dec. 31, 2010 Regulated Independent Transmission	Jun. 30, 2011 Other/Corporate	Dec. 31, 2010 Other/Corporate
Goodwill recognized by segments
Balance at December 31, 2010	$ 5,575,000,000	$ 5,575,000,000	$ 5,551,000,000	$ 5,551,000,000	$ 5,551,000,000	$ 24,000,000	$ 24,000,000	$ 0	$ 0	$ 0	$ 0
Merger with Allegheny	881,000,000					881,000,000
Balance at June 30, 2011	$ 6,456,000,000	$ 5,575,000,000	$ 5,551,000,000	$ 5,551,000,000	$ 5,551,000,000	$ 905,000,000	$ 24,000,000	$ 0	$ 0	$ 0	$ 0

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Variable Interest Entities

6 Months Ended

Jun. 30, 2011

Variable Interest Entities [Abstract]

VARIABLE INTEREST ENTITIES

7. VARIABLE INTEREST ENTITIES

FirstEnergy and its subsidiaries perform qualitative analyses to determine whether a variable interest gives FirstEnergy or its subsidiaries a controlling financial interest in a VIE. This analysis identifies the primary beneficiary of a VIE as the enterprise that has both the power to direct the activities of a VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE.

VIEs included in FirstEnergy’s consolidated financial statements are: FEV’s joint venture in the Signal Peak mining and coal transportation operations; the PNBV and Shippingport bond trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; and wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station, of which $295 million was outstanding as of June 30, 2011.

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 primarily the result of net losses of the noncontrolling interests ($15 million) and distributions to owners ($4 million) during the six months ended June 30, 2011.

In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregated variable interests into the following categories based on similar risk characteristics and significance.

PATH-WV

PATH, LLC was formed to construct, through its operating companies, the PATH Project, which is a high-voltage transmission line that was proposed to extend from West Virginia through Virginia and into Maryland, including modifications to an existing substation in Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH, LLC is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of AE owns 100% of the Allegheny Series and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of the portion of the PATH Project to be constructed by PATH-WV.

Because of the nature of PATH-WV’s operations and its FERC approved rate mechanism, FirstEnergy’s maximum exposure to loss, through AE, consists of its equity investment in PATH-WV, which was $27 million at June 30, 2011.

Power Purchase Agreements

FirstEnergy evaluated its power purchase agreements and determined that certain NUG entities may be VIEs to the extent that they own a plant that sells substantially all of its output to the Utilities if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, Met-Ed, Penelec, PE, WP and MP, maintains 23 long-term power purchase agreements with NUG entities that were entered into pursuant to PURPA. 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 four of these NUG entities, its subsidiaries do not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. JCP&L, PE and WP may hold variable interests in the remaining four entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Because JCP&L, PE and WP have no equity or debt interests in the NUG entities, their maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred by its subsidiaries to be recovered from customers, except as described further below. Purchased power costs related to the four contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months ended June 30, 2011, were $55 million, $47 million and $21 million for JCP&L, PE and WP, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, respectively. Purchased power costs related to the two contracts that may contain a variable interest that were held by JCP&L during the three months and six months ended June 30, 2010 were $53 million and $117 million, respectively.

In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount for an adverse power purchase commitment related to the NUG entity that WP may hold a variable interest, for which WP has taken the scope exception. As of June 30, 2011, WP’s reserve for this adverse purchase power commitment was $59 million, including a current liability of $11 million, and is being amortized over the life of the commitment.

Loss Contingencies

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

FES and the Ohio Companies are exposed to losses under their applicable sale and leaseback agreements upon the occurrence of certain contingent events. The maximum exposure under these provisions represents the net amount of casualty value payments due upon the occurrence of specified casualty events. 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 as of June 30, 2011:

	Maximum		Discounted Lease		Net
	Exposure		Payments, net(1)		Exposure
	(In millions)
FES	$	1,348	$	1,156	$	192
OE		635		445		190
CEI(2)		624		69		555
TE(2)		624		303		321

(1)	The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6 billion.
(2)	CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

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New Accounting Standards and Interpretations

6 Months Ended

Jun. 30, 2011

New Accounting Standards and Interpretations [Abstract]

NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

12. NEW ACCOUNTING STANDARDS AND INTERPRETATIONS

In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective for FirstEnergy in the first quarter of 2012. FirstEnergy does not expect this amendment to have a material effect on its financial statements.

In June 2011, the FASB issued new accounting guidance that revises the manner in which entities presents comprehensive income in their financial statements. The new guidance requires entities to report components of comprehensive income in either a continuous statement of comprehensive income or two separate but consecutive statements. The new guidance does not change the items that must be reported in other comprehensive income and does not affect the calculation or reporting of earnings per share. The amendment is effective for FirstEnergy in the first quarter of 2012. This amendment will not have a material effect on FirstEnergy’s financial statements.

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Supplemental Guarantor Information (Details 2) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			$ 1,031,000,000	$ 858,000,000
New Financing-
Long-term debt			503,000,000
Short-term borrowings, net				281,000,000
Redemptions and Repayments-
Long-term debt			(1,002,000,000)	(407,000,000)
Short-term borrowings, net			(44,000,000)
Common stock dividend payments			(420,000,000)	(335,000,000)
Other			(76,000,000)	(23,000,000)
Net cash used for financing activities			(1,039,000,000)	(484,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(569,000,000)	(489,000,000)	(1,018,000,000)	(997,000,000)
Proceeds from asset sales				116,000,000
Sales of investment securities held in trusts			1,703,000,000	1,915,000,000
Purchases of investment securities held in trusts			(1,807,000,000)	(1,934,000,000)
Customer acquisition costs			(2,000,000)	(105,000,000)
Other			(51,000,000)	(21,000,000)
Net cash provided from (used for) investing activities			(535,000,000)	(967,000,000)
Net change in cash and cash equivalents			(543,000,000)	(593,000,000)
Cash and cash equivalents at beginning of period			1,019,000,000	874,000,000
Cash and cash equivalents at end of period	476,000,000	281,000,000	476,000,000	281,000,000
FES Corp
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			(329,000,000)	(223,000,000)
New Financing-
Short-term borrowings, net			453,000,000
Redemptions and Repayments-
Long-term debt			(135,000,000)
Other			(9,000,000)	(1,000,000)
Net cash used for financing activities			309,000,000	(1,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(6,000,000)	(4,000,000)
Loans to associated companies, net			28,000,000	332,000,000
Customer acquisition costs			(2,000,000)	(105,000,000)
Other				1,000,000
Net cash provided from (used for) investing activities			20,000,000	224,000,000
Cash and cash equivalents at beginning of period			0	0
Cash and cash equivalents at end of period	0	0	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			321,000,000	163,000,000
New Financing-
Long-term debt			140,000,000
Short-term borrowings, net			77,000,000	76,000,000
Redemptions and Repayments-
Long-term debt			(192,000,000)	(261,000,000)
Other			(1,000,000)
Net cash used for financing activities			24,000,000	(185,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(109,000,000)	(333,000,000)
Proceeds from asset sales				116,000,000
Loans to associated companies, net			(221,000,000)	241,000,000
Other			(18,000,000)	(2,000,000)
Net cash provided from (used for) investing activities			(348,000,000)	22,000,000
Net change in cash and cash equivalents			(3,000,000)	0
Cash and cash equivalents at beginning of period			9,000,000	0
Cash and cash equivalents at end of period	6,000,000	0	6,000,000	0
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			200,000,000	287,000,000
New Financing-
Long-term debt			107,000,000
Redemptions and Repayments-
Long-term debt			(155,000,000)	(43,000,000)
Other			(1,000,000)
Net cash used for financing activities			(49,000,000)	(43,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(219,000,000)	(229,000,000)
Sales of investment securities held in trusts			513,000,000	957,000,000
Purchases of investment securities held in trusts			(545,000,000)	(979,000,000)
Loans to associated companies, net			100,000,000	58,000,000
Leasehold improvement payments to (from) associated companies				(51,000,000)
Net cash provided from (used for) investing activities			(151,000,000)	(244,000,000)
Cash and cash equivalents at beginning of period			0	0
Cash and cash equivalents at end of period	0	0	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			(10,000,000)	(9,000,000)
Redemptions and Repayments-
Long-term debt			10,000,000	9,000,000
Net cash used for financing activities			10,000,000	9,000,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash and cash equivalents at beginning of period			0	0
Cash and cash equivalents at end of period	0	0	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES			182,000,000	218,000,000
New Financing-
Long-term debt			247,000,000
Short-term borrowings, net			530,000,000	76,000,000
Redemptions and Repayments-
Long-term debt			(472,000,000)	(295,000,000)
Other			(11,000,000)	(1,000,000)
Net cash used for financing activities			294,000,000	(220,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(334,000,000)	(566,000,000)
Proceeds from asset sales				116,000,000
Sales of investment securities held in trusts			513,000,000	957,000,000
Purchases of investment securities held in trusts			(545,000,000)	(979,000,000)
Loans to associated companies, net			(93,000,000)	631,000,000
Customer acquisition costs			(2,000,000)	(105,000,000)
Leasehold improvement payments to (from) associated companies				(51,000,000)
Other			(18,000,000)	(1,000,000)
Net cash provided from (used for) investing activities			(479,000,000)	2,000,000
Net change in cash and cash equivalents			(3,000,000)	0
Cash and cash equivalents at beginning of period			9,000,000	0
Cash and cash equivalents at end of period	$ 6,000,000	$ 0	$ 6,000,000	$ 0

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Income Taxes

6 Months Ended

Jun. 30, 2011

Income Taxes [Abstract]

INCOME TAXES

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. As a result of the merger with Allegheny in the first quarter of 2011, FirstEnergy’s unrecognized tax benefits increased by $97 million. During the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy’s effective tax rate for the second quarter and first six months of 2011. There were no other material changes to FirstEnergy’s unrecognized income tax benefits during the first six months of 2011. After reaching a tentative agreement with the IRS on a tax item at appeals related to the capitalization of certain costs for tax years 2005-2008, as well as reaching a settlement on an unrelated state tax matter in the second quarter of 2010, FirstEnergy recognized approximately $70 million of net income tax benefits, including $13 million that favorably affected FirstEnergy’s effective tax rate for the second quarter of 2010. The remaining portion of the income tax benefit recognized in the first six months of 2010 increased FirstEnergy’s accumulated deferred income taxes for the settled temporary tax item.

As of June 30, 2011, it is reasonably possible that approximately $46 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $4 million, if recognized, would affect FirstEnergy’s effective tax rate. The potential decrease in the amount of unrecognized income tax benefits is primarily associated with issues related to the capitalization of certain costs and various state tax items.

FirstEnergy recognizes interest expense or income related to uncertain tax positions. That amount is computed by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken or expected to be taken on the tax return. FirstEnergy includes net interest and penalties in the provision for income taxes. The interest associated with the settlement of the claim noted above favorably affected FirstEnergy’s effective tax rate by $6 million in the first half of 2011. During the first six months of 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest as a result of the merger with Allegheny. The reversal of accrued interest associated with the recognized income tax benefits noted above favorably affected FirstEnergy’s effective tax rate by $11 million in the first six months of 2010. The net amount of interest accrued as of June 30, 2011 was $10 million, compared with $3 million as of December 31, 2010.

As a result of the non-deductible portion of merger transaction costs, FirstEnergy’s effective tax rate was unfavorably impacted by $28 million in the first six months of 2011.

As a result of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act signed into law in March 2010, beginning in 2013 the tax deduction available to FirstEnergy will be reduced to the extent that drug costs are reimbursed under the Medicare Part D retiree subsidy program. As retiree healthcare liabilities and related tax impacts under prior law were already reflected in FirstEnergy’s consolidated financial statements, the change resulted in a charge to FirstEnergy’s earnings in the first quarter of 2010 of approximately $13 million and a reduction in accumulated deferred tax assets associated with these subsidies. That charge reflected the anticipated increase in income taxes that will occur as a result of the change in tax law.

Allegheny is currently under audit by the IRS for tax years 2007 and 2008. The 2009 federal return was filed and is subject to review. State tax returns for tax years 2006 through 2009 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. Tax returns for all state jurisdictions are open from 2006-2009. The IRS began auditing the year 2008 in February 2008 and the audit was completed in July 2010 with one item under appeal. The 2009 tax year audit began in February 2009 and the 2010 tax year audit began in February 2010. Management believes that adequate reserves have been recognized and final settlement of these audits is not expected to have a material adverse effect on FirstEnergy’s financial condition or results of operations.

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2011

Segment Information [Abstract]

Segment Financial Information

			Competitive		Regulated
	Regulated		Energy		Independent		Other/			Reconciling
Three Months Ended	Distribution		Services		Transmission		Corporate			Adjustments			Consolidated
	(In millions)
June 30, 2011
External revenues	$	2,485	$	1,495	$	105	$	(30	)	$	(7	)	$	4,048
Internal revenues		—		318		—		—			(306	)		12
Total revenues		2,485		1,813		105		(30	)		(313	)		4,060
Depreciation and amortization		240		107		18		7			—			372
Investment income (loss), net		27		15		—		1			(12	)		31
Net interest charges		145		67		11		21			1			245
Income taxes		108		7		18		(30	)		(2	)		101
Net income (loss)		184		12		31		(51	)		(5	)		171
Total assets		26,932		17,146		2,339		1,179			—			47,596
Total goodwill		5,551		905		—		—			—			6,456
Property additions		302		197		45		25			—			569
June 30, 2010
External revenues	$	2,314	$	795	$	59	$	(21	)	$	(8	)	$	3,139
Internal revenues		19		539		—		—			(558	)		—
Total revenues		2,333		1,334		59		(21	)		(566	)		3,139
Depreciation and amortization		264		71		13		3			—			351
Investment income (loss), net		28		13		—		—			(10	)		31
Net interest charges		124		33		5		9			(4	)		167
Income taxes		81		75		7		(12	)		(17	)		134
Net income (loss)		132		121		11		(20	)		12			256
Total assets		21,457		11,102		993		914			—			34,466
Total goodwill		5,551		24		—		—			—			5,575
Property additions		157		290		15		27			—			489
Six Months Ended
June 30, 2011
External revenues	$	4,753	$	2,736	$	172	$	(53	)	$	(16	)	$	7,592
Internal revenues		—		661		—		—			(617	)		44
Total revenues		4,753		3,397		172		(53	)		(633	)		7,636
Depreciation and amortization		485		195		31		13			—			724
Investment income (loss), net		52		21		—		1			(22	)		52
Net interest charges		276		122		20		40			—			458
Income taxes		164		10		25		(50	)		30			179
Net income (loss)		280		17		44		(86	)		(39	)		216
Total assets		26,932		17,146		2,339		1,179			—			47,596
Total goodwill		5,551		905		—		—			—			6,456
Property additions		479		411		72		56			—			1,018
June 30, 2010
External revenues	$	4,798	$	1,514	$	116	$	(43	)	$	(14	)	$	6,371
Internal revenues		19		1,213		—		—			(1,165	)		67
Total revenues		4,817		2,727		116		(43	)		(1,179	)		6,438
Depreciation and amortization		577		148		25		6			—			756
Investment income (loss), net		54		14		—		1			(22	)		47
Net interest charges		248		66		10		22			(7	)		339
Income taxes		143		117		14		(24	)		(5	)		245
Net income (loss)		235		190		23		(39	)		(4	)		405
Total assets		21,457		11,102		993		914			—			34,466
Total goodwill		5,551		24		—		—			—			5,575
Property additions		309		619		29		40			—			997

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Pension and Other Postretirement Benefits

6 Months Ended

Jun. 30, 2011

Pension and Other Postretirement Benefits [Abstract]

PENSION AND OTHER POSTRETIREMENT BENEFITS

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 provides a portion of non-contributory pre-retirement basic life insurance for employees who are eligible to retire. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits.

FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. During the three months and six months ended June 30, 2011, FirstEnergy made pre-tax contributions to its qualified pension plans of $105 million and $262 million, respectively. FirstEnergy intends to make additional contributions of $116 million and $2 million to its qualified pension plans and postretirement benefit plans, respectively, in the last two quarters of 2011.

As result of the merger with Allegheny, FirstEnergy assumed certain pension and OPEB plans. FirstEnergy measured the funded status of the Allegheny pension plans and postretirement benefit plans other than pensions as of the merger closing date using discount rates of 5.50% and 5.25%, respectively. The fair values of plan assets for Allegheny’s pension plans and postretirement benefit plans other than pensions at the date of the merger were $954 million and $75 million, respectively, and the actuarially determined benefit obligations for such plans as of that date were $1,341 million and $272 million, respectively. The expected returns on plan assets used to calculate net periodic costs for periods in 2011 subsequent to the date of the merger are 8.25% for Allegheny’s qualified pension plan and 5.00% for Allegheny’s postretirement benefit plans other than pensions.

The components of the consolidated net periodic cost for pension and OPEB benefits (including amounts capitalized) were as follows:

	Three Months Ended						Six Months Ended
	June 30						June 30
Pension Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	34		$	25		$	62		$	49
Interest cost		97			79			181			157
Expected return on plan assets		(115	)		(90	)		(216	)		(181	)
Amortization of prior service cost		4			3			7			6
Recognized net actuarial loss		48			47			97			94
Curtailments(1)		—			—			(2	)		—
Special termination benefits(1)		—			—			9			—
Net periodic cost	$	68		$	64		$	138		$	125

⁽¹⁾ Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger.

	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	3		$	3		$	7		$	5
Interest cost		12			11			23			22
Expected return on plan assets		(10	)		(9	)		(20	)		(18	)
Amortization of prior service cost		(52	)		(48	)		(100	)		(96	)
Recognized net actuarial loss		14			15			28			30
Net periodic cost (credit)	$	(33	)	$	(28	)	$	(62	)	$	(57	)

Pension and OPEB obligations are allocated to FirstEnergy’s subsidiaries employing the plan participants. The net periodic pension costs and net periodic OPEB (including amounts capitalized) recognized by FirstEnergy’s subsidiaries were as follows:

	Three Months Ended				Six Months Ended
	June 30				June 30
Pension Benefit Cost	2011		2010		2011		2010
	(In millions)
FES	$	22	$	22	$	43	$	44
OE		5		6		11		11
CEI		5		5		10		11
TE		2		2		3		4
JCP&L		5		6		11		12
Met-Ed		3		3		5		5
Penelec		4		5		9		9
Other FirstEnergy Subsidiaries		22		15		46		29
	$	68	$	64	$	138	$	125

	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefit Credit	2011			2010			2011			2010
	(In millions)
FES	$	(8	)	$	(7	)	$	(14	)	$	(13	)
OE		(5	)		(6	)		(12	)		(12	)
CEI		(2	)		(1	)		(3	)		(3	)
TE		—			—			(1	)		(1	)
JCP&L		(2	)		(2	)		(3	)		(4	)
Met-Ed		(2	)		(2	)		(5	)		(4	)
Penelec		(2	)		(2	)		(5	)		(4	)
Other FirstEnergy Subsidiaries		(12	)		(8	)		(19	)		(16	)
	$	(33	)	$	(28	)	$	(62	)	$	(57	)

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Derivative Instruments (Details 2) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Gain (Loss) Recognized in AOCL (Effective Portion)	$ 14	$ 3	$ 5	$ 4
Unrealized Gain (Loss) Recognized				(43)
Power Contracts
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Gain (Loss) Recognized in AOCL (Effective Portion)	14	0	5	(2)
Power Contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	(3)	16	(7)
Unrealized Gain (Loss) Recognized	33	66	61	39
Additions/Change in value of existing contracts	1	(26)	(36)	(49)
Power Contracts | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	(5)	(12)	(5)
Unrealized Gain (Loss) Recognized	(4)		(3)
Additions/Change in value of existing contracts	(39)		(29)
Power Contracts | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:		0		0
Power Contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(34)		(54)
Additions/Change in value of existing contracts	0		0
FTRs
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Gain (Loss) Recognized in AOCL (Effective Portion)	0	0	0	0
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	0	0	0
Unrealized Gain (Loss) Recognized	0	0	0	0
Additions/Change in value of existing contracts	0	0	0	0
FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	0	0	0
Unrealized Gain (Loss) Recognized	0		0
Additions/Change in value of existing contracts	18		26
FTRs | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:		0		0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	13		13
Additions/Change in value of existing contracts	(59)		(87)
Interest Rate Swap
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Gain (Loss) Recognized in AOCL (Effective Portion)	0	0	0	0
Interest Rate Swap | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	0	0	0
Unrealized Gain (Loss) Recognized	0	0	0	0
Additions/Change in value of existing contracts		0	0	0
Interest Rate Swap | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	0	0	0
Unrealized Gain (Loss) Recognized	0		0
Additions/Change in value of existing contracts	0		0
Interest Rate Swap | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:		0		0
Interest Rate Swap | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	0		1
Additions/Change in value of existing contracts	0		0
NUGs | Regulatory Asset
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	147	35	236	259
Realized Loss to Regulatory Assets:	(62)	(68)	(134)	(146)
NUGs | Derivative Instrument
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(147)	(35)	(236)	(259)
Additions/Change in value of existing contracts	62	68	134	146
Other
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Gain (Loss) Recognized in AOCL (Effective Portion)	0	3	0	6
Other | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	0	0	0
Unrealized Gain (Loss) Recognized	0	0	0	0
Additions/Change in value of existing contracts	(2)	0	0	0
Other | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	0	0	0
Unrealized Gain (Loss) Recognized	0		0
Additions/Change in value of existing contracts	0		0
Other | Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:		(4)		(8)
Other | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	0		0
Additions/Change in value of existing contracts	0		0
Other | Regulatory Asset
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(2)	0	(2)	0
Realized Loss to Regulatory Assets:	0	0	10	9
Other | Derivative Instrument
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	2	0	2	0
Additions/Change in value of existing contracts	0	0	(10)	(9)
Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	(3)	16	(7)
Unrealized Gain (Loss) Recognized	33	66	61	39
Additions/Change in value of existing contracts	1	(26)	(36)	(49)
Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:	0	(5)	(12)	(5)
Unrealized Gain (Loss) Recognized	(4)		(3)
Additions/Change in value of existing contracts	(21)		(3)
Fuel Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Effective Gain (Loss) Reclassified to:		(4)		(8)
Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(21)		(40)
Additions/Change in value of existing contracts	(59)		(87)
Regulatory Asset
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	145	35	234	259
Realized Loss to Regulatory Assets:	(62)	(68)	(124)	(137)
Derivative Instrument
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(145)	(35)	(234)	(259)
Additions/Change in value of existing contracts	$ 62	$ 68	$ 124	$ 137

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Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Thousands, except Share data	Jun. 30, 2011	Dec. 31, 2010
Common stockholders' equity-
Common stock, par value	$ 0.10	$ 0.10
Common stock, shares authorized	490,000,000	375,000,000
Common stock, shares outstanding	418,216,437	304,835,407
FES
Common stockholders' equity-
Common Stock, No Par Value	$ 0
Common stock, shares authorized	750
Common stock, shares outstanding	7
FES | Other [Member]
Receivables-
Accumulated provision for uncollectible accounts	$ 3,000	$ 7,000
FES | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	18,000	17,000
OE
Common stockholders' equity-
Common Stock, No Par Value	$ 0
Common stock, shares authorized	175,000,000
Common stock, shares outstanding	60
OE | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	3,564	4,086
CEI
Common stockholders' equity-
Common Stock, No Par Value	$ 0
Common stock, shares authorized	105,000,000
Common stock, shares outstanding	67,930,743
CEI | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	2,801	4,589
TE
Common stockholders' equity-
Common stock, par value	$ 5
Common stock, shares authorized	60,000,000
Common stock, shares outstanding	29,402,054
TE | Other [Member]
Receivables-
Accumulated provision for uncollectible accounts	339	330
TE | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	1,142	1
JCP&L
Common stockholders' equity-
Common stock, par value	$ 10
Common stock, shares authorized	16,000,000
Common stock, shares outstanding	13,628,447
JCP&L | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	3,306	3,769
Met-Ed
Common stockholders' equity-
Common Stock, No Par Value	$ 0
Common stock, shares authorized	900,000
Common stock, shares outstanding	740,905	859,500
Met-Ed | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	3,087	3,868
Penelec
Common stockholders' equity-
Common stock, par value	$ 20
Common stock, shares authorized	5,400,000
Common stock, shares outstanding	4,427,577
Penelec | Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	2,856	3,369
Other [Member]
Receivables-
Accumulated provision for uncollectible accounts	8,000	8,000
Customer [Member]
Receivables-
Accumulated provision for uncollectible accounts	$ 35,000	$ 36,000

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Merger

6 Months Ended

Jun. 30, 2011

Merger [Abstract]

MERGER

2. MERGER

Merger

On February 25, 2011, the merger between FirstEnergy and Allegheny closed. Pursuant to the terms of the Agreement and Plan of Merger among FirstEnergy, Element Merger Sub, Inc., a Maryland corporation and a wholly-owned subsidiary of FirstEnergy (Merger Sub) and AE, Merger Sub merged with and into AE, with AE continuing as the surviving corporation and becoming a wholly-owned subsidiary of FirstEnergy. As part of the merger, AE shareholders received 0.667 of a share of FirstEnergy common stock for each share of AE common stock outstanding as of the date the merger was completed, and all outstanding AE equity-based employee compensation awards were converted into FirstEnergy equity-based awards on the same basis.

The total consideration in the merger was based on the closing price of a share of FirstEnergy common stock on February 24, 2011, the day prior to the date the merger was completed, and was calculated as follows (in millions, except per share data):

Shares of Allegheny common stock outstanding on February 24, 2011		170
Exchange ratio		0.667
Number of shares of FirstEnergy common stock issued		113
Closing price of FirstEnergy common stock on February 24, 2011	$	38.16
Fair value of shares issued by FirstEnergy	$	4,327
Fair value of replacement share-based compensation awards relating to pre-merger service		27
Total consideration transferred	$	4,354

The allocation of the total consideration transferred to the assets acquired and liabilities assumed includes adjustments for the fair value of coal contracts, energy supply contracts, emission allowances, unregulated property, plant and equipment, derivative instruments, goodwill, intangible assets, long-term debt and accumulated deferred income taxes. The preliminary allocation of the purchase price is as follows:

(In millions)
Current assets	$	1,494
Property, plant and equipment		9,656
Investments		138
Goodwill		881
Other noncurrent assets		1,347
Current liabilities		(716	)
Noncurrent liabilities		(3,452	)
Long-term debt and other long-term obligations		(4,994	)
	$	4,354

The allocation of purchase price in the table above reflects a refinement made during the quarter ended June 30, 2011 in the determination of the fair values of income tax benefits, certain coal contracts and an adverse purchase power contract. This resulted in an increase in noncurrent assets of approximately $85 million and decreases in current assets and goodwill of $15 million and $71 million, respectively. The impact of the refinements on the amortization of purchase accounting adjustments recorded during the quarter ended March 31, 2011 was not significant. Further modifications to the purchase price allocation may occur as a result of continuing review of the assets acquired and liabilities assumed.

The estimated fair values of the assets acquired and liabilities assumed have been determined based on the accounting guidance for fair value measurements under GAAP, which defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date.

The excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill. The Allegheny delivery, transmission and generation businesses have been assigned to the Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services segments, respectively. The preliminary estimate of goodwill from the merger of $881 million has been assigned to the Competitive Energy Services segment based on expected synergies from the merger. The goodwill is not deductible for tax purposes.

Total goodwill recognized by segment in FirstEnergy’s Consolidated Balance Sheet is as follows:

			Competitive		Regulated
	Regulated		Energy		Independent		Other/
(In millions)	Distribution		Services		Transmission		Corporate		Consolidated
Balance as of December 31, 2010	$	5,551	$	24	$	—	$	—	$	5,575
Merger with Allegheny		—		881		—		—		881
Balance as of June 30, 2011	$	5,551	$	905	$	—	$	—	$	6,456

The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger is as follows:

	Preliminary		Weighted Average
(In millions)	Valuation		Amortization Period
Above market contracts:
Energy contracts	$	189	10 years
NUG contracts		124	25 years
Coal supply contracts		516	8 years
		829
Below market contracts:
NUG contracts		143	13 years
Coal supply contracts		83	7 years
Transportation contract		35	8 years
		261
Net intangible assets	$	568

The fair value measurements of intangible assets and liabilities were based on significant unobservable inputs and thus represent level 3 measurements as defined in accounting guidance for fair value measurements.

The fair value of Allegheny’s energy, NUG and gas transportation contracts, both above-market and below-market, were estimated based on the present value of the above/below market cash flows attributable to the contracts based on the contract type, discounted by a current market interest rate consistent with the overall credit quality of the portfolio. The above/below market cash flows were estimated by comparing the expected cash flow based on existing contracted prices and expected volumes with the cash flows from estimated current market contract prices for the same expected volumes. The estimated current market contract prices were derived considering current market prices, such as the price of energy and transmission, miscellaneous fees and a normal profit margin. The weighted average amortization period was determined based on the expected volumes to be delivered over the life of the contract.

The fair value of coal supply contracts was determined in a similar manner based on the present value of the above/below market cash flows attributable to the contracts. The fair value adjustment for these contracts is being amortized based on expected deliveries under each contract.

As of June 30, 2011, intangible assets on FirstEnergy’s Consolidated Balance Sheet, including those recorded in connection with the merger, include the following:

	Intangible
(In millions)	Assets
Purchase contract assets
NUG	$	198
OVEC		54
		252
Intangible assets
Coal contracts		487
FES customer intangible assets		129
Energy contracts		105
		721
Total intangible assets	$	973

Acquired land easements and software with a fair value of $169 million are included in “Property, plant and equipment” on FirstEnergy’s Consolidated Balance Sheet as of June 30, 2011.

In connection with the merger, FirstEnergy recorded merger transaction costs of approximately $7 million ($5 million net of tax) and $7 million ($5 million net of tax) during the three months ended June 30, 2011 and 2010, respectively and approximately $89 million ($72 million net of tax) and $21 million ($15 million net of tax) during the first six months of 2011 and 2010, respectively. These costs are included in “Other operating expenses” in the Consolidated Statements of Income. Merger transaction costs recognized in the first six months of 2011 include $56 million ($47 net of tax) of change in control and other benefit payments to AE executives.

FirstEnergy also recorded approximately $10 million ($6 million net of tax) and $85 million ($66 million net of tax) in merger integration costs during the three and six months ended June 30 2011, respectively, including an inventory valuation adjustment. In connection with the merger, FirstEnergy reviewed its inventory levels as a result of combining the inventory of both companies. Following this review, FirstEnergy management determined that the combined inventory stock contained excess and duplicative items. FirstEnergy management also adopted a consistent excess and obsolete inventory practice for the combined entity. Application of the revised practice, in conjunction with those items identified as excess and duplicative, resulted in an inventory valuation adjustment of $67 million ($42 million net of tax) in the first quarter of 2011.

Revenues and earnings of Allegheny included in FirstEnergy’s Consolidated Statement of Income for the periods subsequent to the February 25, 2011 merger date are as follows:

	April 1 –		February 26 –
(In millions, except per share amounts)	June 30, 2011		June 30, 2011
Total revenues	$	1,181	$	1,618
Earnings available to FirstEnergy Corp.(1)		63		17
Basic Earnings Per Share	$	0.15	$	0.04
Diluted Earnings Per Share	$	0.15	$	0.04

⁽¹⁾ Includes Allegheny’s after-tax merger costs of $4 million and $56 million, respectively.

Pro Forma Financial Information

The following unaudited pro forma financial information reflects the consolidated results of operations of FirstEnergy as if the merger with Allegheny had taken place on January 1, 2010. The unaudited pro forma information has been calculated after applying FirstEnergy’s accounting policies and adjusting Allegheny’s results to reflect the depreciation and amortization that would have been charged assuming fair value adjustments to property, plant and equipment, debt and intangible assets had been applied on January 1, 2010, together with the consequential tax effects.

FirstEnergy and Allegheny both incurred non-recurring costs directly related to the merger that have been included in the pro forma earnings presented below. Combined pre-tax transaction costs incurred were approximately $7 million and $11 million in the three months ended June 30, 2011 and 2010, respectively, and approximately $90 million and $39 million in the six months ended June 30, 2011 and 2010, respectively. In addition, during the six months ended June 30, 2011, $85 million of pre-tax merger integration costs and $32 million of charges from merger settlements approved by regulatory agencies were recognized. Charges resulting from merger settlements are not expected to be material in future periods.

The unaudited pro forma financial information has been presented below for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved or the future consolidated results of operations of the combined company.

	Three Months Ended				Six Months Ended
(Pro forma amounts in millions, except	June 30				June 30
per share amounts)	2011		2010		2011		2010
Revenues	$	4,062	$	4,401	$	8,848	$	9,086
Earnings available to FirstEnergy	$	186	$	389	$	323	$	644
Basic Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.54
Diluted Earnings Per Share	$	0.44	$	0.93	$	0.77	$	1.53

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Merger (Details Textuals) (USD $) In Millions, except Share data	3 Months Ended	6 Months Ended			6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Feb. 25, 2011	Jun. 30, 2011 Land easements and computer equipment [Member]	Jun. 30, 2011 Allegheny Energy Inc	Jun. 30, 2010 Allegheny Energy Inc	Jun. 30, 2011 Allegheny Energy Inc Pre-tax [Member]	Jun. 30, 2010 Allegheny Energy Inc Pre-tax [Member]	Jun. 30, 2011 Allegheny Energy Inc Pre-tax [Member]	Jun. 30, 2010 Allegheny Energy Inc Pre-tax [Member]	Jun. 30, 2011 Pre-tax [Member]	Jun. 30, 2010 Pre-tax [Member]	Jun. 30, 2011 Pre-tax [Member]	Jun. 30, 2010 Pre-tax [Member]	Jun. 30, 2011 Net of Tax [Member]	Jun. 30, 2010 Net of Tax [Member]	Jun. 30, 2011 Net of Tax [Member]
Acquired Finite-Lived Intangible Assets [Line Items]
Fair value of intangible assets acquired				$ 169
Business Acquisition [Line Items]
Merger related Expenses					56		7	7	89	21							47
Merger transaction costs					72	15					7	11	90	39	5	5
Merger integration costs											10		85		6		66
Merger (Textuals) [Abstract]
Exchange ratio			0.667
Increase in noncurrent assets		85
Decrease in current assets		15
Decrease in goodwill		71
Allegheny's after-tax merger costs	4	56
Expenses related to merger settlements approved by regulatory agencies		32
Inventory valuation adjustment	67	67
Inventory valuation adjustment, net of tax	$ 42	$ 42

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Stock-Based Compensation Plans (Tables)

6 Months Ended

Jun. 30, 2011

Stock Based Compensation Plans [Abstract]

Restricted Stock and Restricted Stock Units

	Six Months
	Ended
	June 30, 2011
Restricted stock and stock units outstanding as of January 1, 2011		1,878,022
Granted		891,881
Converted Allegheny restricted stock		645,197
Exercised		(428,686	)
Forfeited		(71,775	)
Restricted stock and stock units outstanding as of June 30, 2011		2,914,639

Summary of stock option activities

				Weighted
				Average
	Number of			Exercise
Stock Option Activities	Shares			Price
Stock options outstanding as of January 1, 2011 (all exercisable)		2,889,066		$	35.18
Options granted		662,122			37.75
Converted Allegheny options		1,805,811			41.75
Options exercised		(691,304	)		31.38
Options forfeited/expired		(78,978	)		71.71
Stock options outstanding as of June 30, 2011		4,586,717		$	38.09
(3,924,595 options exercisable)

Summary of options outstanding by plan and range of exercise price

			Weighted		Remaining
	Shares Under		Average		Contractual
Exercise Prices	Options		Exercise Price		Life in Years
$20.02 – $30.74		1,045,122	$	26.54		2.02
$30.89 – $40.93		3,160,440		37.30		4.17
$42.72 – $51.82		3,883		51.02		0.70
$53.06 – $62.97		54,559		56.15		3.02
$64.52 – $71.82		9,042		67.50		5.24
$73.39 – $80.47		311,003		80.17		3.81
$81.19 – $89.59		2,668		85.39		6.09
Total		4,586,717	$	38.08		3.64

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Variable Interest Entities (Details) (USD $) In Millions	Jun. 30, 2011
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,348
Discounted Lease Payments, net	1,156
Variable Interest Entities Net Exposure	192
OE
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	635
Discounted Lease Payments, net	445
Variable Interest Entities Net Exposure	190
CEI
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	624
Discounted Lease Payments, net	69
Variable Interest Entities Net Exposure	555
TE
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	624
Discounted Lease Payments, net	303
Variable Interest Entities Net Exposure	$ 321

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Income Taxes (Details) (USD $) In Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2011	Mar. 31, 2011	Jun. 30, 2010	Mar. 31, 2010	Jun. 30, 2011	Jun. 30, 2010	Dec. 31, 2010
Income Taxes (Textuals) [Abstract]
Increase in unrecognized tax benefits		$ 97
Unrecognized tax benefits expected to resolved within the next twelve month	46				46
Unrecognized benefits (if recognized) affecting effective tax rate	4	6			4
Decrease in unrecognized tax benefits			70
Tax benefits favorably affecting effective tax rate			13			11
Accrued Interest	10				10		3
Change in effective tax rate as a result of non-deductible portion of merger transaction and integration costs					28
Change to FirstEnergy's earnings resulting from retiree healthcare liabilities and related tax impact already reflected in consolidated financial statements				13
Income tax benefits on settlement of recognized research and development claim	30
Tax benefits arising from favorable affected tax rate included in Research and development settlement	5				5
Allegheny
Income Tax Contingency [Line Items]
Increase in accrued interest					$ 6

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Derivative Instruments (Details 1)	Jun. 30, 2011 MWH
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases	45,573,000
Sales	(59,549,000)
Net	(13,976,000)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases	53,656,000
Sales	0
Net	53,656,000
Interest Rate Swap
Volume of First Energy's outstanding derivative transactions
Purchases	200,000,000
Sales	(200,000,000)
Net	0
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases	26,903,000
Sales	0
Net	26,903,000

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Stock-Based Compensation Plans (Details 1) (USD $)	6 Months Ended
	Jun. 30, 2011
Summary of stock option activities
Stock option outstanding, Beginning Balance	2,889,066
Weighted Average Exercise Price, Beginning Balance	$ 35.18
Options granted	662,122
Weighted Average Exercise Price of Options granted	$ 37.75
Converted Allegheny options	1,805,811
Converted Allegheny options, Weighted Average Exercise Price	$ 41.75
Options exercised	(691,304)
Weighted Average Exercise Price of Options exercised	$ 31.38
Options forfeited/expired	(78,978)
Weighted Average Exercise Price of forfeited/expired	$ 71.71
Stock option outstanding, Ending Balance	4,586,717
Weighted Average Exercise Price, Ending Balance	$ 38.09

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Earnings Per Share

6 Months Ended

Jun. 30, 2011

Earnings Per Share [Abstract]

EARNINGS PER SHARE

3. EARNINGS PER SHARE

Basic earnings per share of common stock are computed using the weighted average of actual common shares outstanding during the relevant 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 would be issued if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

	Three Months				Six Months
Reconciliation of Basic and Diluted Earnings per Share	Ended June 30				Ended June 30
of Common Stock	2011		2010		2011		2010
	(In millions, except per share amounts)
Earnings available to FirstEnergy Corp.	$	181	$	265	$	231	$	420
Weighted average number of basic shares outstanding(1)		418		304		380		304
Assumed exercise of dilutive stock options and awards		2		1		2		1
Weighted average number of diluted shares outstanding(1)		420		305		382		305
Basic earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.38
Diluted earnings per share of common stock	$	0.43	$	0.87	$	0.61	$	1.37

⁽¹⁾ Includes 113 million shares issued to AE stockholders for the periods subsequent to the merger date. (See Note 2)

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Fair Value Measurements (Details) (USD $) In Thousands	Jun. 30, 2011	Dec. 31, 2010
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 16,491,000	$ 12,579,000
FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	3,000,000	3,181,000
FES | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	4,056,000	4,279,000
FES | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	4,310,000	4,403,000
OE
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,151,720	1,152,134
OE | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,158,000	1,159,000
OE | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,367,000	1,321,000
CEI
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,831,023	1,852,530
CEI | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,831,000	1,853,000
CEI | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	2,083,000	2,035,000
TE
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	600,524	600,493
TE | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	600,000	600,000
TE | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	690,000	653,000
JCP&L
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,754,582	1,769,849
JCP&L | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,795,000	1,810,000
JCP&L | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	2,008,000	1,962,000
Met-Ed
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	704,486	718,860
Met-Ed | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	729,000	742,000
Met-Ed | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	828,000	821,000
Penelec
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,072,417	1,072,262
Penelec | Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,120,000	1,120,000
Penelec | Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,231,000	1,189,000
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	18,371,000	13,928,000
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 19,436,000	$ 14,845,000

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2011

Derivative Instruments [Abstract]

Fair value of derivatives instruments

Derivative Assets
	Fair Value
	June 30,		December 31,
	2011		2010
	(In millions)
Power Contracts
Current Assets	$	210	$	96
Noncurrent Assets		102		40
FTRs
Current Assets		13		—
Noncurrent Assets		—		—
NUGs
Current Assets		4		3
Noncurrent Assets		71		119
Interest Rate Swaps
Current Assets		4		—
Noncurrent Assets		—		—
Other
Current Assets		—		10
Noncurrent Assets		—		—
Total Derivatives	$	404	$	268

Derivative Liabilities
	Fair Value
	June 30,		December 31,
	2011		2010
	(In millions)
Power Contracts
Current Liabilities	$	274	$	209
Noncurrent Liabilities		88		38
FTRs
Current Liabilities		7		—
Noncurrent Liabilities		—		—
NUGs
Current Liabilities		317		229
Noncurrent Liabilities		205		238
Interest Rate Swaps
Current Liabilities		5		—
Noncurrent Liabilities		—		—
Other
Current Liabilities		—		—
Noncurrent Liabilities		—		—
Total Derivatives	$	896	$	714

Volume of First Energy's outstanding derivative transactions

	Purchases		Sales			Net			Units
	(In thousands)
Power Contracts		45,573		(59,549	)		(13,976	)	MWH
FTRs		53,656		—			53,656		MWH
Interest Rate Swaps		200,000		(200,000	)		—		notional dollars
NUGs		26,903		—			26,903		MWH

Effect of derivative instruments on statements of income and comprehensive income

	Three Months Ended June 30,
	Power					Interest
	Contracts			FTRs		Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	14		$	—	$	—	$	—		$	14
Effective Gain (Loss) Reclassified to: (1)
Purchase Power Expense		—			—		—		—			—
Revenues		—			—		—		—			—
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	—		$	—	$	—	$	3		$	3
Effective Gain (Loss) Reclassified to:(1)
Purchase Power Expense		(3	)		—		—		—			(3	)
Revenues		(5	)		—		—		—			(5	)
Fuel Expense		—			—		—		(4	)		(4	)

Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	33		$	—		$	—	$	—	$	33
Revenues		(4	)		—			—		—		(4	)
Other Operating Expense		(34	)		13			—		—		(21	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		1			—			—		—		1
Revenues		(39	)		18			—		—		(21	)
Other Operating Expense		—			(59	)		—		—		(59	)
2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	66		$	—		$	—	$	—	$	66
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(26	)		—			—		—		(26	)

	Six Months Ended June 30,
	Power						Interest
	Contracts			FTRs			Rate Swaps		Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2011
Gain (Loss) Recognized in AOCL (Effective Portion)	$	5		$	—		$	—	$	—		$	5
Effective Gain (Loss) Reclassified to: (1)
Purchase Power Expense		16			—			—		—			16
Revenues		(12	)		—			—		—			(12	)
2010
Gain (Loss) Recognized in AOCL (Effective Portion)	$	(2	)	$	—		$	—	$	6		$	4
Effective Gain (Loss) Reclassified to:(1)
Purchase Power Expense		(7	)		—			—		—			(7	)
Revenues		(5	)		—			—		—			(5	)
Fuel Expense		—			—			—		(8	)		(8	)
Derivatives Not in a Hedging Relationship
2011
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	61		$	—		$	—	$	—		$	61
Revenues		(3	)		—			—		—			(3	)
Other Operating Expense		(54	)		13			1		—			(40	)
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(36	)		—			—		—			(36	)
Revenues		(29	)		26			—		—			(3	)
Other Operating Expense		—			(87	)		—		—			(87	)
2010
Unrealized Gain (Loss) Recognized in:
Purchase Power Expense	$	39		$	—		$	—	$	—		$	39
Realized Gain (Loss) Reclassified to:
Purchase Power Expense		(49	)		—			—		—			(49	)

Derivatives not in a hedging relationship with regulatory offset

Derivatives Not in a Hedging	Three Months Ended June 30,
Relationship with Regulatory Offset(2)	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(147	)	$	2		$	(145	)
Unrealized Gain (Loss) to Regulatory Assets:		147			(2	)		145
Realized Gain (Loss) to Derivative Instrument:		62			—			62
Realized Gain (Loss) to Regulatory Assets:		(62	)		—			(62	)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(35	)		—		$	(35	)
Unrealized Gain (Loss) to Regulatory Assets:		35			—			35
Realized Gain (Loss) to Derivative Instrument:		68			—			68
Realized Gain (Loss) to Regulatory Assets:		(68	)		—			(68	)

Derivatives Not in a Hedging	Six Months Ended June 30,
Relationship with Regulatory Offset(2)	NUGs			Other			Total
	(In millions)
2011
Unrealized Gain (Loss) to Derivative Instrument:	$	(236	)	$	2		$	(234	)
Unrealized Gain (Loss) to Regulatory Assets:		236			(2	)		234
Realized Gain (Loss) to Derivative Instrument:		134			(10	)		124
Realized Gain (Loss) to Regulatory Assets:		(134	)		10			(124	)
2010
Unrealized Gain (Loss) to Derivative Instrument:	$	(259	)		—		$	(259	)
Unrealized Gain (Loss) to Regulatory Assets:		259			—			259
Realized Gain (Loss) to Derivative Instrument:		146			(9	)		137
Realized Gain (Loss) to Regulatory Assets:		(146	)		9			(137	)

(1)	The ineffective portion was immaterial.
(2)	Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

Reconciliation of changes in the fair value of certain contracts that are deferred

	Three Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other		Total
	(In millions)
Outstanding net asset (liability) as of April 1, 2011	$	(362	)	$	—	$	(362	)
Additions/Change in value of existing contracts		(147	)		2		(145	)
Settled contracts		62			—		62
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	2	$	(445	)
Outstanding net asset (liability) as of April 1, 2010	$	(590	)	$	10	$	(580	)
Additions/Change in value of existing contracts		(35	)		—		(35	)
Settled contracts		68			—		68
Outstanding net asset (liability) as of June 30, 2010	$	(557	)	$	10	$	(547	)

	Six Months Ended June 30,
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts		(236	)		2			(234	)
Settled contracts		134			(10	)		124
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	2		$	(445	)
Outstanding net asset (liability) as of January 1, 2010	$	(444	)	$	19		$	(425	)
Additions/Change in value of existing contracts		(259	)		—			(259	)
Settled contracts		146			(9	)		137
Outstanding net asset (liability) as of June 30, 2010	$	(557	)	$	10		$	(547	)

⁽¹⁾ Changes in the fair value of certain contracts are deferred for future recovery from (or refund to) customers.

XML



Stock-Based Compensation Plans (Details Textuals) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
Stock-Based Compensation Plans (Textuals) [Abstract]
Common stock exchange ratio	0.667
Number of forms os stock based compensation awards	4
Number of options exercisable	3,924,595
Restricted Stock and Restricted Stock Units Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted common stock granted	891,881
Restricted common stock grant-date fair value	$ 33.2
Restricted common stock weighted-average vesting period	2.74
Compensation expense (income)	27.0	20.0
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense (income)	2.0	(6.0)
ESOP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense (income)	19.0	10.0
Stock Option
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock option weighted-average vesting period	3.79
Compensation expense (income)	0.3	0
Stock option grant-date fair value	3.3
First Energy LTIP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of stock based compensation programs	4
Maximum limit of total stock awards	29,100,000
Stock-based compensation award vesting period	From 2 months to 10 years
Stock-based compensation award number of shares available for future	5,600,000
EDCP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense (income)	0	0
EDCP and DCPD
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance	1,700,000
Deferred compensation arrangement with individual number of Shares available for grant	1,076,779
DCPD
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense (income)	2.0	2.0
Net liability of stock option	$ 6

XML



Regulatory Matters (Details) (USD $)	6 Months Ended					12 Months Ended		6 Months Ended				6 Months Ended	12 Months Ended						6 Months Ended			6 Months Ended	3 Months Ended			6 Months Ended	60 Months Ended		6 Months Ended		1 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011 2015 WEST VIRGINIA	Jun. 30, 2011 2020 WEST VIRGINIA	Jun. 30, 2011 2025 WEST VIRGINIA	Jun. 30, 2011 MARYLAND	Dec. 31, 2007 MARYLAND	Oct. 06, 2009 MARYLAND	Jun. 30, 2011 NEW JERSEY	Jan. 23, 2009 OE OHIO	Jan. 23, 2009 CEI OHIO	Jan. 23, 2009 TE OHIO	Jun. 30, 2011 OHIO	Dec. 31, 2013 OHIO MWH	Dec. 31, 2012 OHIO MWH	Dec. 31, 2011 OHIO MWH	Dec. 31, 2010 OHIO MWH	Dec. 31, 2009 OHIO MWH	Jan. 23, 2009 OHIO	Jun. 30, 2011 PENNSYLVANIA	May 31, 2013 PENNSYLVANIA	May 31, 2011 PENNSYLVANIA	Jun. 30, 2011 WEST VIRGINIA	Jun. 30, 2011 California Claims Matters	Jun. 30, 2011 The Seneca Pumped Storage Project Relicensing	Jun. 30, 2011 The Seneca Pumped Storage Project FERC MWH	Jun. 30, 2011 PJM Calculation Error FERC	Mar. 31, 2010 PJM Calculation Error FERC	Jun. 16, 2011 PJM Calculation Error FERC	Jun. 30, 2011 FERC	Jun. 30, 2011 FERC TRAIL KV	Nov. 19, 2010 FERC PATH	Jun. 30, 2011 FERC PATH KV	Jun. 30, 2011 Penelec	Jun. 30, 2011 Met-Ed	Apr. 29, 2010 Met-Ed KV
Regulatory Matters [Line Items]
Proposed electric consumption reduction percentage					10.00%
Proposed electric demand reduction percentage					15.00%
Increase electric distribution rates									$ 68,900,000	$ 29,200,000	$ 38,500,000							$ 136,600,000
Total annual energy savings													530,000	470,000	410,000	290,000	166,000
Utilities required to reduce peak demand in 2009																			1.00%
Utilities Required To Additionally Reduce Peak Demand												0.75%
Load Served From Renewable Energy Resources																0.50%	0.25%
Marginal transmission losses																			254,000,000														65,000,000	189,000,000
Approximate increase in retail rates																						95,000,000
Revised decommissioning costs								736,000,000
Number of settlements for which liability charges are fix																													9
Number of settlements for which relevant payment has been made																													8
New Voltage transmission facilities across PJM and a zonal transmission rate (In KV)																														500		765
One time payment, ATSI agreed to MISO																													1,800,000
Annual Revenue requirements in Zone																													15,000,000
Annual Revenue Requirements In Zone Assigned for year to ATSI																													1,800,000
Net underpayments from PJM to MISO																										5,000,000	130,000,000
Maximum Cost Incurred Due To Improper Market To Market Settlements																										25,000,000
Number of complaints for which order approving settlement is issued																												3
Return on equity granted as incentive rider																															1.50%
Return on equity granted for RTO participation																															0.50%
Maximum amount of penalty assessed per day per violation					25,000,000
Number of programs for residential customers						7
Minimum reduction in Utilities peak demand																				4.50%
Description of vegetation encroachment event																																			230
Hydroelectric project																									451
Load cap percentage minimum												80.00%
Specified minimum percentage of electricity sold to retail customers		10.00%	15.00%	25.00%
Expenditures for cost recovery program							101,000,000
Reduction in recovery of societal benefits charge								800,000
Decrease in ENEC rates																						20,000,000
Annualized Base Rate Increase																						40,000,000
Fund to assist low income customers												12,000,000
Settlement proposal claims																							190,000,000
Minimum reduction in Utilities reduce energy consumption																				3.00%	1.00%
Target installation smart meter																			25,000
Generation discount for low income customers												6.00%
Grace period	30 months
Duration of Plan Approved As Per Order																	3 years
Smart meter infrastructure deployed																			725,000
Additional base rate increase																						20,000,000
Contemplated deployment of smart meter infrastructure																			375,000
Period of Cycle						5 years																		5 years
Period of the portfolio plans filed seeking approval for the program																	3 years
Costs avoided by customers												360,000,000
Recovery period for expenditures for cost recovery program							6 years
Requested amendment deemed to be necessary																	1
Number of companies involved in compliance with yet to be defined modified benchmarks																	2
Assessment period costs																			$ 29,500,000
Assessment period	24 months
Comment period	30 days

XML



Supplemental Guarantor Information (Tables)

6 Months Ended

Jun. 30, 2011

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Statements of Income

For the Three Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	1,275		$	535		$	393		$	(911	)	$	1,292
EXPENSES:
Fuel		6			266			44			—			316
Purchased power from affiliates		902			9			65			(911	)		65
Purchased power from non-affiliates		332			(3	)		—			—			329
Other operating expenses		159			115			143			12			429
Provision for depreciation		1			32			36			(1	)		68
General taxes		16			8			6			—			30
Impairment of long-lived assets		—			7			—			—			7
Total expenses		1,416			434			294			(900	)		1,244
OPERATING INCOME (LOSS)		(141	)		101			99			(11	)		48
OTHER INCOME (EXPENSE):
Investment income		—			1			15			—			16
Miscellaneous income (expense), including net income from equity investees		123			1			—			(120	)		4
Interest expense — affiliates		—			(1	)		(1	)		—			(2	)
Interest expense — other		(24	)		(28	)		(16	)		16			(52	)
Capitalized interest		—			5			5			—			10
Total other income (expense)		99			(22	)		3			(104	)		(24	)
INCOME (LOSS) BEFORE INCOME TAXES		(42	)		79			102			(115	)		24
INCOME TAXES (BENEFITS)		(62	)		25			38			3			4
NET INCOME	$	20		$	54		$	64		$	(118	)	$	20

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	2,642		$	1,278		$	862		$	(2,098	)	$	2,684
EXPENSES:
Fuel		7			560			92			—			659
Purchased power from affiliates		2,087			11			134			(2,098	)		134
Purchased power from non-affiliates		629			(3	)		—			—			626
Other operating expenses		321			233			331			25			910
Provision for depreciation		2			63			74			(3	)		136
General taxes		27			19			14			—			60
Impairment charges of long-lived assets		—			20			—			—			20
Total expenses		3,073			903			645			(2,076	)		2,545
OPERATING INCOME (LOSS)		(431	)		375			217			(22	)		139
OTHER INCOME (EXPENSE):
Investment income		1			1			20			—			22
Miscellaneous income, including net income from equity investees		356			2			—			(350	)		8
Interest expense — affiliates		(1	)		(1	)		(1	)		—			(3	)
Interest expense — other		(48	)		(56	)		(33	)		32			(105	)
Capitalized interest		—			10			10			—			20
Total other income (expense)		308			(44	)		(4	)		(318	)		(58	)
INCOME (LOSS) BEFORE INCOME TAXES		(123	)		331			213			(340	)		81
INCOME TAXES (BENEFITS)		(179	)		119			80			5			25
NET INCOME	$	56		$	212		$	133		$	(345	)	$	56

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Three Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	1,307		$	581		$	339		$	(901	)	$	1,326
EXPENSES:
Fuel		7			302			34			—			343
Purchased power from affiliates		913			8			49			(901	)		69
Purchased power from non-affiliates		310			—			—			—			310
Other operating expenses		81			94			117			12			304
Provision for depreciation		1			27			36			(1	)		63
General taxes		6			9			7			—			22
Total expenses		1,318			440			243			(890	)		1,111
OPERATING INCOME (LOSS)		(11	)		141			96			(11	)		215
OTHER INCOME (EXPENSE):
Investment income		2			—			11			—			13
Miscellaneous income, including net income from equity investees		151			1			—			(148	)		4
Interest expense — affiliates		—			(2	)		—			—			(2	)
Interest expense — other		(24	)		(28	)		(15	)		16			(51	)
Capitalized interest		—			20			4			—			24
Total other income (expense)		129			(9	)		—			(132	)		(12	)
INCOME BEFORE INCOME TAXES		118			132			96			(143	)		203
INCOME TAXES (BENEFITS)		(16	)		48			34			3			69
NET INCOME	$	134		$	84		$	62		$	(146	)	$	134

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME
(Unaudited)

For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
REVENUES	$	2,674		$	1,149		$	765		$	(1,874	)	$	2,714
EXPENSES:
Fuel		12			582			77			—			671
Purchased power from affiliates		1,881			12			111			(1,874	)		130
Purchased power from non-affiliates		760			—			—			—			760
Other operating expenses		134			194			256			24			608
Provision for depreciation		2			54			73			(3	)		126
General taxes		11			24			14			—			49
Impairment of long-lived assets		—			2			—			—			2
Total expenses		2,800			868			531			(1,853	)		2,346
OPERATING INCOME (LOSS)		(126	)		281			234			(21	)		368
OTHER INCOME (EXPENSE):
Investment income		4			—			10			—			14
Miscellaneous income, including net income from equity investees		317			1			—			(311	)		7
Interest expense to affiliates		—			(4	)		(1	)		—			(5	)
Interest expense — other		(48	)		(54	)		(31	)		32			(101	)
Capitalized interest		—			36			8			—			44
Total other income (expense)		273			(21	)		(14	)		(279	)		(41	)
INCOME BEFORE INCOME TAXES		147			260			220			(300	)		327
INCOME TAXES (BENEFITS)		(67	)		97			78			5			113
NET INCOME	$	214		$	163		$	142		$	(305	)	$	214

Condensed Consolidating Balance Sheets

As of June 30, 2011	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	6	$	—	$	—		$	6
Receivables-
Customers		450		—		—		—			450
Associated companies		481		425		263		(679	)		490
Other		24		23		4		—			51
Notes receivable from associated companies		6		410		74		—			490
Materials and supplies, at average cost		54		253		192		—			499
Derivatives		221		—		—		—			221
Prepayments and other		34		14		1		—			49
		1,270		1,131		534		(679	)		2,256
PROPERTY, PLANT AND EQUIPMENT:
In service		101		6,105		5,634		(385	)		11,455
Less — Accumulated provision for depreciation		19		2,067		2,298		(178	)		4,206
		82		4,038		3,336		(207	)		7,249
Construction work in progress		10		198		486		—			694
Property, plant and equipment held for sale, net		—		487		—		—			487
		92		4,723		3,822		(207	)		8,430
INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,184		—			1,184
Investment in associated companies		5,302		—		—		(5,302	)		—
Other		1		9		—		—			10
		5,303		9		1,184		(5,302	)		1,194
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		18		344		—		(362	)		—
Customer intangibles		129		—		—		—			129
Goodwill		24		—		—		—			24
Property taxes		—		16		25		—			41
Unamortized sale and leaseback costs		—		6		—		70			76
Derivatives		135		—		—		—			135
Other		39		97		7		(68	)		75
		345		463		32		(360	)		480
	$	7,010	$	6,326	$	5,572	$	(6,548	)	$	12,360
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	436	$	671	$	(20	)	$	1,088
Short-term borrowings-
Associated companies		453		88		—		—			541
Other		—		1		—		—			1
Accounts payable-
Associated companies		665		231		165		(668	)		393
Other		80		111		—		—			191
Derivatives		242		—		—		—			242
Other		69		137		46		10			262
		1,510		1,004		882		(678	)		2,718
CAPITALIZATION:
Total equity		3,858		2,728		2,556		(5,285	)		3,857
Long-term debt and other long-term obligations		1,483		2,050		706		(1,239	)		3,000
		5,341		4,778		3,262		(6,524	)		6,857
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		942			942
Accumulated deferred income taxes		—		—		504		(288	)		216
Asset retirement obligations		—		28		847		—			875
Retirement benefits		50		245		—		—			295
Lease market valuation liability		—		194		—		—			194
Derivatives		85		—		—		—			85
Other		24		77		77		—			178
		159		544		1,428		654			2,785
	$	7,010	$	6,326	$	5,572	$	(6,548	)	$	12,360

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS
(Unaudited)

As of December 31, 2010	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	9	$	—	$	—		$	9
Receivables-
Customers		366		—		—		—			366
Associated companies		333		357		126		(338	)		478
Other		21		56		13		—			90
Notes receivable from associated companies		34		189		174		—			397
Materials and supplies, at average cost		41		276		228		—			545
Derivatives		182		—		—		—			182
Prepayments and other		48		10		1		—			59
		1,025		897		542		(338	)		2,126
PROPERTY, PLANT AND EQUIPMENT:
In service		96		6,198		5,412		(385	)		11,321
Less — Accumulated provision for depreciation		17		2,020		2,162		(175	)		4,024
		79		4,178		3,250		(210	)		7,297
Construction work in progress		9		520		534		—			1,063
		88		4,698		3,784		(210	)		8,360
INVESTMENTS:
Nuclear plant decommissioning trusts		—		—		1,146		—			1,146
Investment in associated companies		4,942		—		—		(4,942	)		—
Other		—		12		—		—			12
		4,942		12		1,146		(4,942	)		1,158
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits		43		412		—		(455	)		—
Customer intangibles		134		—		—		—			134
Goodwill		24		—		—		—			24
Property taxes		—		16		25		—			41
Unamortized sale and leaseback costs		—		10		—		63			73
Derivatives		98		—		—		—			98
Other		21		71		14		(58	)		48
		320		509		39		(450	)		418
	$	6,375	$	6,116	$	5,511	$	(5,940	)	$	12,062
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	101	$	419	$	632	$	(20	)	$	1,132
Short-term borrowings-
Associated companies		—		12		—		—			12
Accounts payable-
Associated companies		351		213		250		(347	)		467
Other		139		102		—		—			241
Derivatives		266		—		—		—			266
Other		56		183		46		37			322
		913		929		928		(330	)		2,440
CAPITALIZATION:
Common stockholder’s equity		3,788		2,515		2,414		(4,929	)		3,788
Long-term debt and other long-term obligations		1,519		2,119		793		(1,250	)		3,181
		5,307		4,634		3,207		(6,179	)		6,969
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction		—		—		—		959			959
Accumulated deferred income taxes		—		—		448		(390	)		58
Asset retirement obligations		—		27		865		—			892
Retirement benefits		48		237		—		—			285
Lease market valuation liability		—		217		—		—			217
Derivatives		81		—		—		—			81
Other		26		72		63		—			161
		155		553		1,376		569			2,653
	$	6,375	$	6,116	$	5,511	$	(5,940	)	$	12,062

Condensed Consolidating Statements of Cash Flows

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(329	)	$	321		$	200		$	(10	)	$	182
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt		—			140			107			—			247
Short-term borrowings, net		453			77			—			—			530
Redemptions and Repayments-
Long-term debt		(135	)		(192	)		(155	)		10			(472	)
Other		(9	)		(1	)		(1	)		—			(11	)
Net cash provided from (used for) financing activities		309			24			(49	)		10			294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(6	)		(109	)		(219	)		—			(334	)
Sales of investment securities held in trusts		—			—			513			—			513
Purchases of investment securities held in trusts		—			—			(545	)		—			(545	)
Loans to associated companies, net		28			(221	)		100			—			(93	)
Customer acquisition costs		(2	)		—			—			—			(2	)
Other		—			(18	)		—			—			(18	)
Net cash provided from (used for) investing activities		20			(348	)		(151	)		—			(479	)
Net change in cash and cash equivalents		—			(3	)		—			—			(3	)
Cash and cash equivalents at beginning of period		—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	6		$	—		$	—		$	6

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(Unaudited)

For the Six Months Ended June 30, 2010	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(223	)	$	163		$	287		$	(9	)	$	218
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net		—			76			—			—			76
Redemptions and Repayments-
Long-term debt		—			(261	)		(43	)		9			(295	)
Other		(1	)		—			—			—			(1	)
Net cash used for financing activities		(1	)		(185	)		(43	)		9			(220	)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(4	)		(333	)		(229	)		—			(566	)
Proceeds from asset sales		—			116			—			—			116
Sales of investment securities held in trusts		—			—			957			—			957
Purchases of investment securities held in trusts		—			—			(979	)		—			(979	)
Loans to associated companies, net		332			241			58			—			631
Customer acquisition costs		(105	)		—			—			—			(105	)
Leasehold improvement payments to associated companies		—			—			(51	)		—			(51	)
Other		1			(2	)		—			—			(1	)
Net cash provided from (used for) investing activities		224			22			(244	)		—			2
Net change in cash and cash equivalents		—			—			—			—			—
Cash and cash equivalents at beginning of period		—			—			—			—			—
Cash and cash equivalents at end of period	$	—		$	—		$	—		$	—		$	—

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Earnings Per Share (Details) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Reconciliation of basic and diluted earnings per share of common stock
Earnings available to FirstEnergy Corp.	$ 181	$ 265	$ 231	$ 420
Weighted average number of basic shares outstanding	418	304	380	304
Assumed exercise of dilutive stock options and awards	2	1	2	1
Diluted	420	305	382	305
Basic Earnings Per Share	$ 0.43	$ 0.87	$ 0.61	$ 1.38
Diluted Earnings Per Share	$ 0.43	$ 0.87	$ 0.61	$ 1.37
Earnings Per Share (Textuals)
Number of shares issued in connection with merger of Allegheny Energy			113

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2011

Variable Interest Entities [Abstract]

Net exposure to loss based upon the casualty value provisions

	Maximum		Discounted Lease		Net
	Exposure		Payments, net(1)		Exposure
	(In millions)
FES	$	1,348	$	1,156	$	192
OE		635		445		190
CEI(2)		624		69		555
TE(2)		624		303		321

(1)	The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6 billion.
(2)	CEI and TE are jointly and severally liable for the maximum loss amounts under certain sale-leaseback agreements.

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Stock Based Compensation Plans

6 Months Ended

Jun. 30, 2011

Stock Based Compensation Plans [Abstract]

STOCK-BASED COMPENSATION PLANS

11. STOCK-BASED COMPENSATION PLANS

FirstEnergy has four types of stock-based compensation programs — LTIP, EDCP, ESOP and DCPD, as described below.

Allegheny’s stock-based awards were converted into FirstEnergy stock-based awards as of the date of the merger. These awards, referred to below as converted Allegheny awards, were adjusted in terms of the number of awards and, where applicable, the exercise price thereof, to reflect the merger’s common stock exchange ratio of 0.667 of a share of FirstEnergy common stock for each share of Allegheny common stock.

(A) LTIP

FirstEnergy’s LTIP includes four forms of stock-based compensation awards — stock options, performance shares, restricted stock and restricted stock units.

Under FirstEnergy’s LTIP, total awards cannot exceed 29.1 million shares of common stock or their equivalent. Only stock options, restricted stock and restricted stock units have currently been designated to be settled in common stock, with vesting periods ranging from two months to ten years. Performance share awards are currently designated to be paid in cash rather than common stock and therefore do not count against the limit on stock-based awards. There were 5.6 million shares available for future awards as of June 30, 2011.

Restricted Stock and Restricted Stock Units

Restricted common stock (restricted stock) and restricted stock unit (stock unit) activity was as follows:

	Six Months
	Ended
	June 30, 2011
Restricted stock and stock units outstanding as of January 1, 2011		1,878,022
Granted		891,881
Converted Allegheny restricted stock		645,197
Exercised		(428,686	)
Forfeited		(71,775	)
Restricted stock and stock units outstanding as of June 30, 2011		2,914,639

The 891,881 shares of restricted common stock granted during the six months ended June 30, 2011 had a grant-date fair value of $33.2 million and a weighted-average vesting period of 2.74 years.

Restricted stock units include awards that will be settled in a specific number of shares of common stock after the service condition has been met. Restricted stock units also include performance-based awards that will be settled after the service condition has been met in a specified number of shares of common stock based on FirstEnergy’s performance compared to annual target performance metrics.

Compensation expense recognized during the six months ended June 30, 2011 and 2010 for restricted stock and restricted stock units, net of amounts capitalized, was approximately $27 million and $20 million, respectively.

Stock Options

Stock option activity for the six months ended June 30, 2011 was as follows:

				Weighted
				Average
	Number of			Exercise
Stock Option Activities	Shares			Price
Stock options outstanding as of January 1, 2011 (all exercisable)		2,889,066		$	35.18
Options granted		662,122			37.75
Converted Allegheny options		1,805,811			41.75
Options exercised		(691,304	)		31.38
Options forfeited/expired		(78,978	)		71.71
Stock options outstanding as of June 30, 2011		4,586,717		$	38.09
(3,924,595 options exercisable)

Compensation expense recognized for stock options during the six months ended June 30, 2011 was $0.3 million. No expense was recognized during the six months ended June 30, 2010. Options granted during the six months ended June 30, 2011 had a grant-date fair value of $3.3 million and an expected weighted-average vesting period of 3.79 years.

Options outstanding by exercise price as of June 30, 2011 were as follows:

			Weighted		Remaining
	Shares Under		Average		Contractual
Exercise Prices	Options		Exercise Price		Life in Years
$20.02 – $30.74		1,045,122	$	26.54		2.02
$30.89 – $40.93		3,160,440		37.30		4.17
$42.72 – $51.82		3,883		51.02		0.70
$53.06 – $62.97		54,559		56.15		3.02
$64.52 – $71.82		9,042		67.50		5.24
$73.39 – $80.47		311,003		80.17		3.81
$81.19 – $89.59		2,668		85.39		6.09
Total		4,586,717	$	38.08		3.64

Performance Shares

Performance shares will be settled in cash and are accounted for as liability awards. Compensation expense (income) recognized for performance shares during the six months ended June 30, 2011 and 2010, net of amounts capitalized, totaled $2 million and $(6) million, respectively. No performance shares under the FirstEnergy LTIP were settled during the six months ended June 30, 2011 and 2010.

(B) ESOP

During 2011, shares of FirstEnergy common stock were purchased on the open market and contributed to participants’ accounts. Total ESOP-related compensation expense for the six months ended June 30, 2011 and 2010, net of amounts capitalized and dividends on common stock, were $19 million and $10 million, respectively.

(C) EDCP

There was no material compensation expense recognized on EDCP stock units during the six months ended June 30, 2011 and 2010.

(D) DCPD

DCPD expenses recognized during the six months ended June 30, 2011 and 2010 were approximately $2 million in each period. The net liability recognized for DCPD of approximately $6 million as of June 30, 2011 is included in the caption “Retirement benefits” on the Consolidated Balance Sheets.

Of the 1.7 million stock units authorized under the EDCP and DCPD, 1,076,779 stock units were available for future awards as of June 30, 2011.

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Pension and Other Postretirement Benefits (Details 1) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
FES | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	$ 22	$ 22	$ 43	$ 44
FES | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(8)	(7)	(14)	(13)
OE | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	5	6	11	11
OE | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(5)	(6)	(12)	(12)
CEI | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	5	5	10	11
CEI | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(2)	(1)	(3)	(3)
TE | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	2	2	3	4
TE | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost			(1)	(1)
JCP&L | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	5	6	11	12
JCP&L | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(2)	(2)	(3)	(4)
Met-Ed | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	3	3	5	5
Met-Ed | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(2)	(2)	(5)	(4)
Penelec | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	4	5	9	9
Penelec | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(2)	(2)	(5)	(4)
Other FirstEnergy Subsidiaries | Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	22	15	46	29
Other FirstEnergy Subsidiaries | Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	(12)	(8)	(19)	(16)
Pension Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	68	64	138	125
Other Postretirement Benefit Cost (Credit)
Net Periodic Pension and OPEB Costs
Net periodic cost	$ (33)	$ (28)	$ (62)	$ (57)

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Supplemental Guarantor Information (Details Textuals)	Jul. 13, 2007
Supplemental Guarantor Information (Textuals) [Abstract]
Sale and leaseback transactions of undivided interest Bruce Mansfield	93.825%

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Commitments, Guarantees and Contingencies (Details) (USD $)	3 Months Ended	6 Months Ended	12 Months Ended						6 Months Ended									1 Months Ended	6 Months Ended		1 Months Ended	6 Months Ended																						6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Dec. 31, 2010	May 02, 2011	Mar. 31, 2011	Jul. 11, 2011 Additional Expense Cercla	Jul. 11, 2011 Previously Reserved Cercla	Jul. 11, 2011 Cercla	Jun. 30, 2011 Nuclear Plant Matters	Mar. 28, 2011 Nuclear Plant Matters Shortfall	Jun. 24, 2011 Nuclear Plant Matters Proposed Guarantee	Jun. 30, 2011 CEI Regulation of Waste Disposal	Jun. 30, 2011 TE Regulation of Waste Disposal	Jun. 30, 2011 JCP&L Regulation of Waste Disposal	Jun. 30, 2011 Regulation of Waste Disposal	Jun. 30, 2011 Regulation of Waste Disposal FE	Jun. 30, 2011 Regulation of Waste Disposal FGCO	Dec. 31, 2010 Monongahela River Water Quality	Jun. 30, 2011 Monongahela River Water Quality	Jun. 30, 2011 Clean Water Act	Jun. 30, 2011 Climate change Tons	Jun. 30, 2011 Climate change Tons	Jun. 30, 2011 Climate change Increase in funding	Jun. 30, 2011 Climate change 2012	Jun. 30, 2011 Climate change 2025	Jun. 30, 2011 National Ambient Air Quality Standards Tons	Jun. 30, 2011 State Air Quality Compliance	Jun. 30, 2011 Caa Compliance	Jun. 30, 2011 Class Action [Member]	Jun. 30, 2011 Twenty One Individuals [Member]	Jun. 30, 2011 FES Additional Requirements	Jun. 30, 2011 Guarantees and other Assurances	Jun. 30, 2011 Guarantees and other Assurances Parental Guarantees	Jun. 30, 2011 Guarantees and other Assurances Subsidiaries Guarantees	Jun. 30, 2011 Normal Condition	Jun. 30, 2011 Normal Condition Below Investment Grade Credit Rating	Jun. 30, 2011 Normal Condition Material Adverse Event	Jun. 30, 2011 Normal Condition Acceleration of Payment	Jun. 30, 2011 Stress Condition	Jun. 30, 2011 Energy and Energy-related Activities	Jun. 30, 2011 Surety Bonds and Lines Of Credit	May 02, 2011 MP Supply	Jun. 30, 2011 FES	Jun. 30, 2011 AE Supply	May 02, 2011 AE Supply
Commitments Guarantees and Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated																																$ 3,800,000,000	$ 800,000,000	$ 2,600,000,000						$ 200,000,000	$ 400,000,000
Surety bonds and related guarantees	136,000,000	136,000,000
Reduction in air emissions and compliance					81.00%
Required reduction in mercury by the beginning of 2010																											80.00%
Capping of SO2 Emissions Under CSAPR																										2,400,000
Damages for delay costs incurred									57,000,000
Outstanding collateral payments																																											138,000,000	2,000,000
Outstanding collateral payments additional requirement	49,000,000	49,000,000																													17,000,000												(93,000,000)
Signal Peak and Global Rail entered into a syndicated two-year senior secured term loan facility	350,000,000	350,000,000
Maximum exposure under collateral provisions																																			625,000,000	522,000,000	103,000,000	265,000,000	666,000,000
Number of complaints filed against FGCO																												3
Number of complaints seek enjoin plant		2																											1	1
Number of individuals behalf of which complaint filed		21
Number of named plaintiffs as class representatives		8
Number of days required prior to the filing of a citizen suit under notice																												60 days
JCP&L former owning in Keystone Station (In Percentage)																												16.67%
Capping of SO2 emissions (In Tons)																										2,500,000
Capping of NOx emissions under CSAPR																										1,200,000
Capping of NOx emissions (In Tons)																										1,300,000
Electricity production from renewable sources																								10.00%	25.00%
Upper threshold limit for carbon di oxide emission (Tons per Year)																					75,000	75,000
Total environmental liabilities												1,000,000	1,000,000	69,000,000	133,000,000	61,000,000	1,000,000
Parental guarantee associated with the funding of decommissioning costs										92,500,000	95,000,000
Percent confidence level																																											95.00%
Funds provided for Copenhagen Green Climate Fund																						30,000,000,000	100,000,000,000
Number of options proposed by EPA for additional regulation of coal combustion residuals															2
Emission allowance, current	38,000,000	38,000,000
Current value of emission allowance		40,000,000
Proposed Greenhouse Gas emissions reduction by Twenty Fifty																						80.00%
Environmental Liabilities Former Gas Facilities															63,000,000
Number of generation units																												22
Sulfate impairment designation for an approximately mile stretch of the river																		68
Number of companies received notice of complaint alleging GHG emissions																					87
Estimated clean up cost		59,000,000
Nuclear Plant Decommissioning Trusts									2,000,000,000
Number of electric generation facilities																												10
Additional expenses recognized for clean up cost	29,000,000
Previously reserved clean up cost			30,000,000
Loss incurred in damages for replacement coal purchased																																												80,000,000
Amount for replacement coal and interest				14,000,000
Number of days to appeal final judgement		30
Annual percentage that fish impingement should be reduced to, per CWA																				12.00%
Additional damages incurred for future shortfalls																																												150,000,000
Maximum Capital Investment Required To Install Technology To Meet Tds and Sulfate Limits																			150,000,000
Amount for which verdict entered for future damages																																										90,000,000			104,000,000
Estimated liability for expenses						$ 29,000,000	$ 30,000,000	$ 59,000,000

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Fair Value Measurements

6 Months Ended

Jun. 30, 2011

Fair Value Measurements [Abstract]

FAIR VALUE MEASUREMENTS

4. FAIR VALUE MEASUREMENTS

(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 June 30, 2011 and December 31 2010:

	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
FirstEnergy(1)	$	18,371	$	19,436	$	13,928	$	14,845
FES		4,056		4,310		4,279		4,403
OE		1,158		1,367		1,159		1,321
CEI		1,831		2,083		1,853		2,035
TE		600		690		600		653
JCP&L		1,795		2,008		1,810		1,962
Met-Ed		729		828		742		821
Penelec		1,120		1,231		1,120		1,189

⁽¹⁾ Includes debt assumed in the Allegheny merger (See Note 2) with a carrying value and a fair value as of June 30, 2011 of $4,530 million and $4,127 million, respectively.

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those obligations 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 debt with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy, FES, the Utilities and other subsidiaries.

(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 their cost basis, and the likelihood of recovery of the security’s entire amortized cost basis.

Unrealized gains applicable to the decommissioning trusts of FES, OE and TE are recognized in OCI because fluctuations in fair value will eventually impact earnings while unrealized losses are recorded to 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 because the difference between investments held in the 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 trusts’ 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 funds’ custodian or managers and their parents or subsidiaries.

Available-For-Sale Securities

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

The following table summarizes the amortized cost basis, unrealized gains and losses and fair values of investments held in NDT, nuclear fuel disposal trusts and NUG trusts as of June 30, 2011 and December 31, 2010:

	June 30, 2011(1)								December 31, 2010(2)
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt securities
FirstEnergy	$	2,015	$	48	$	—	$	2,063	$	1,699	$	31	$	—	$	1,730
FES		1,023		26		—		1,049		980		13		—		993
OE		128		3		—		131		123		1		—		124
TE		52		1		—		53		42		—		—		42
JCP&L		353		9		—		362		281		9		—		290
Met-Ed		249		5		—		254		127		4		—		131
Penelec		210		4		—		214		145		4		—		149
Equity securities
FirstEnergy	$	187	$	11	$	—	$	198	$	268	$	69	$	—	$	337
FES		90		6		—		96		—		—		—		—
TE		24		2		—		26		—		—		—		—
JCP&L		21		1		—		22		80		17		—		97
Met-Ed		32		1		—		33		125		35		—		160
Penelec		20		1		—		21		63		16		—		79

(1)	Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $130 million; FES – $39 million; OE – $3 million; JCP&L – $19 million; Met-Ed – $14 million and Penelec – $55 million.
(2)	Excludes cash investments, receivables, payables, deferred taxes and accrued income: FirstEnergy – $193 million; FES – $153 million; OE – $3 million; TE – $34 million; JCP&L – $3 million; Met-Ed – $(3) million and Penelec – $4 million.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales net of adjustments recorded to earnings and interest and dividend income for the three months and six months ended June 30, 2011 and 2010 were as follows:

Three Months Ended June 30,
								Interest and
2011	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	734	$	22	$	(16	)	$	28
FES		297		10		(7	)		17
OE		12		—		—			1
TE		15		1		(1	)		1
JCP&L		159		4		(2	)		4
Met-Ed		165		4		(3	)		3
Penelec		86		3		(3	)		2

								Interest and
2010	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,183	$	46	$	(36	)	$	16
FES		685		41		(35	)		9
OE		57		2		—			—
TE		76		2		—			—
JCP&L		91		—		—			3
Met-Ed		233		1		(1	)		2
Penelec		41		—		—			2

Six Months Ended June 30,
								Interest and
2011	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,703	$	122	$	(45	)	$	52
FES		513		22		(23	)		32
OE		20		—		—			2
TE		28		1		(2	)		1
JCP&L		376		26		(6	)		8
Met-Ed		501		48		(7	)		5
Penelec		265		25		(7	)		4

								Interest and
2010	Sales Proceeds		Realized Gains		Realized Losses			Dividend Income
	(In millions)
FirstEnergy	$	1,915	$	83	$	(86	)	$	37
FES		957		54		(58	)		22
OE		60		2		—			1
TE		107		3		—			1
JCP&L		281		9		(9	)		7
Met-Ed		377		9		(12	)		3
Penelec		134		6		(7	)		3

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities as of June 30, 2011 and December 31, 2010:

	June 30, 2011								December 31, 2010
	Cost		Unrealized		Unrealized		Fair		Cost		Unrealized		Unrealized		Fair
	Basis		Gains		Losses		Value		Basis		Gains		Losses		Value
	(In millions)
Debt Securities
FirstEnergy	$	414	$	84	$	—		498	$	476	$	91	$	—	$	567
OE		178		45		—		223		190		51		—		241
CEI		287		39		—		326		340		41		—		381

Investments in emission allowances, employee benefits and cost and equity method investments totaling $345 million as of June 30, 2011 and $259 million as of December 31, 2010, are not required to be disclosed and are excluded from the amounts reported above.

Notes Receivable

The table below provides the approximate fair value and related carrying amounts of notes receivable as of June 30, 2011 and December 31, 2010. 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 2013 to 2021.

	June 30, 2011				December 31, 2010
	Carrying		Fair		Carrying		Fair
	Value		Value		Value		Value
	(In millions)
Notes Receivable
FirstEnergy	$	6	$	7	$	7	$	8
TE		82		94		104		118

(C) RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements.

The three levels of the fair value hierarchy are as follows:

Level 1	— Quoted prices for identical instruments in active markets.
Level 2	— Quoted prices for similar instruments in active markets;
	— quoted prices for identical or similar instruments in markets that are not active; and
	— model-derived valuations for which all significant inputs are observable market data.
Level 3	— Valuation inputs are unobservable and significant to the fair value measurement.

The following tables set forth financial assets and liabilities measured at fair value on a recurring basis by level within the fair value hierarchy. There were no significant transfers between levels during the three months and six months ended June 30, 2011.

FirstEnergy Corp.

The following tables summarize assets and liabilities recorded on FirstEnergy’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	868		$	—		$	868
Derivative assets — commodity contracts		—		312			—			312
Derivative assets — FTRs		—		—			13			13
Derivative assets — interest rate swaps		—		4			—			4
Derivative assets — NUG contracts(1)		—		—			75			75
Equity securities(2)		198		—			—			198
Foreign government debt securities		—		206			—			206
U.S. government debt securities		—		673			—			673
U.S. state debt securities		—		306			—			306
Other(4)		—		146			—			146
Total assets	$	198	$	2,515		$	88		$	2,801
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(362	)	$	—		$	(362	)
Derivative liabilities — FTRs		—		—			(7	)		(7	)
Derivative liabilities — interest rate swaps		—		(5	)		—			(5	)
Derivative liabilities — NUG contracts(1)		—		—			(522	)		(522	)
Total liabilities	$	—	$	(367	)	$	(529	)	$	(896	)
Net assets (liabilities)(3)	$	198	$	2,148		$	(441	)	$	1,905

December 31, 2010	Level 1		Level 2			Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	597		$	—		$	597
Derivative assets — commodity contracts		—		250			—			250
Derivative assets — NUG contracts(1)		—		—			122			122
Equity securities(2)		338		—			—			338
Foreign government debt securities		—		149			—			149
U.S. government debt securities		—		595			—			595
U.S. state debt securities		—		379			—			379
Other(4)		—		219			—			219
Total assets	$	338	$	2,189		$	122		$	2,649
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—		$	(348	)
Derivative liabilities — NUG contracts(1)		—		—			(466	)		(466	)
Total liabilities	$	—	$	(348	)	$	(466	)	$	(814	)
Net assets (liabilities)(3)	$	338	$	1,841		$	(344	)	$	1,835

(1)	NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $6 million and $(7) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(4)	Primarily consists of cash and cash equivalents.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:

	Derivative Asset(1)			Derivative Liability(1)			Net(1)
	(In millions)
January 1, 2011 Balance	$	122		$	(466	)	$	(344	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(40	)		(203	)		(243	)
Purchases		13			(3	)		10
Issuances		—			—			—
Sales		—			—			—
Settlements		(6	)		154			148
Transfers into  Level 3		—			(12	)		(12	)
June 30, 2011 Balance	$	89		$	(530	)	$	(441	)
January 1, 2010 Balance	$	200		$	(643	)	$	(443	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(71	)		(110	)		(181	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(7	)		287			280
Transfers into  Level 3		—			—			—
December 31, 2010 Balance	$	122		$	(466	)	$	(344	)

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

FirstEnergy Solutions Corp.

The following tables summarize assets and liabilities recorded on FES’ Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2			Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	562		$	—	$	562
Derivative assets — commodity contracts		—		283			—		283
Derivative assets — FTRs		—		—			2		2
Equity securities(3)		96		—			—		96
Foreign government debt securities		—		160			—		160
U.S. government debt securities		—		316			—		316
U.S. state debt securities		—		7			—		7
Other(2)		—		42			—		42
Total assets	$	96	$	1,370		$	2	$	1,468
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(327	)	$	—	$	(327	)
Total liabilities	$	—	$	(327	)	$	—	$	(327	)
Net assets (liabilities)(1)	$	96	$	1,043		$	2	$	1,141

December 31, 2010	Level 1		Level 2			Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	528		$	—	$	528
Derivative assets — commodity contracts		—		241			—		241
Foreign government debt securities		—		147			—		147
U.S. government debt securities		—		308			—		308
U.S. state debt securities		—		6			—		6
Other(2)		—		148			—		148
Total assets	$	—	$	1,378		$	—	$	1,378
Liabilities
Derivative liabilities — commodity contracts	$	—	$	(348	)	$	—	$	(348	)
Total liabilities	$	—	$	(348	)	$	—	$	(348	)
Net assets (liabilities)(1)	$	—	$	1,030		$	—	$	1,030

(1)	Excludes $7 million as of December 31, 2010 of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)	Primarily consists of cash and cash equivalents.
(3)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy during the period ending June 30, 2011:

	Derivative Asset			Derivative Liability		Net
	FTRs			FTRs		FTRs
	(In millions)
January 1, 2011 Balance	$	—		$	—	$	—
Realized gain (loss)		—			—		—
Unrealized gain (loss)		1			—		1
Purchases		2			—		2
Issuances		—			—		—
Sales		—			—		—
Settlements		(1	)		—		(1	)
Transfers in (out) of Level 3		—			—		—
June 30, 2011 Balance	$	2		$	—	$	2

Ohio Edison Company

The following tables summarize assets and liabilities recorded on OE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	131	$	—	$	131
Other		—		2		—		2
Total assets(1)	$	—	$	133	$	—	$	133

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
U.S. government debt securities	$	—	$	124	$	—	$	124
Other		—		2		—		2
Total assets(1)	$	—	$	126	$	—	$	126

⁽¹⁾ Excludes $2 million and $1 million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

The Toledo Edison Company

The following tables summarize assets and liabilities recorded on TE’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	16	$	—	$	16
Equity securities(3)		26		—		—		26
U.S. government debt securities		—		33		—		33
U.S. state debt securities		—		1		—		1
Other(2)		—		3		—		3
Total assets(1)	$	26	$	53	$	—	$	79

December 31, 2010	Level 1		Level 2		Level 3		Total
	(In millions)
Assets
Corporate debt securities	$	—	$	7	$	—	$	7
U.S. government debt securities		—		33		—		33
U.S. state debt securities		—		1		—		1
Other(2)		—		35		—		35
Total assets(1)	$	—	$	76	$	—	$	76

(1)	Excludes $(1) million and $2 million as of June 30, 2011 and December 31, 2010, respectively of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.
(2)	Primarily consists of cash and cash equivalents.
(3)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.

Jersey Central Power & Light Company

The following tables summarize assets and liabilities recorded on JCP&L’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	81	$	—		$	81
Derivative assets — NUG contracts(1)		—		—		5			5
Equity securities(2)		21		—		—			21
Foreign government debt securities		—		13		—			13
U.S. government debt securities		—		54		—			54
U.S. state debt securities		—		215		—			215
Other		—		14		—			14
Total assets	$	21	$	377	$	5		$	403
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(240	)	$	(240	)
Total liabilities	$	—	$	—	$	(240	)	$	(240	)
Net assets (liabilities)(3)	$	21	$	377	$	(235	)	$	163

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	23	$	—		$	23
Derivative assets — commodity contracts		—		2		—			2
Derivative assets — NUG contracts(1)		—		—		6			6
Equity securities(2)		96		—		—			96
U.S. government debt securities		—		33		—			33
U.S. state debt securities		—		236		—			236
Other		—		4		—			4
Total assets	$	96	$	298	$	6		$	400
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(233	)	$	(233	)
Total liabilities	$	—	$	—	$	(233	)	$	(233	)
Net assets (liabilities)(3)	$	96	$	298	$	(227	)	$	167

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $5 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by JCP&L and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	6		$	(233	)	$	(227	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(1	)		(71	)		(72	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		—			64			64
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	5		$	(240	)	$	(235	)
January 1, 2010 Balance	$	8		$	(399	)	$	(391	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(1	)		36			35
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(1	)		130			129
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	6		$	(233	)	$	(227	)

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

Metropolitan Edison Company

The following tables summarize assets and liabilities recorded on Met-Ed’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	138	$	—		$	138
Derivative assets — NUG contracts(1)		—		—		66			66
Equity securities(2)		33		—		—			33
Foreign government debt securities		—		20		—			20
U.S. government debt securities		—		87		—			87
U.S. state debt securities		—		2		—			2
Other		—		22		—			22
Total assets	$	33	$	269	$	66		$	368
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(122	)	$	(122	)
Total liabilities	$	—	$	—	$	(122	)	$	(122	)
Net assets (liabilities)(3)	$	33	$	269	$	(56	)	$	246

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	32	$	—		$	32
Derivative assets — commodity contracts		—		5		—			5
Derivative assets — NUG contracts(1)		—		—		112			112
Equity securities(2)		160		—		—			160
Foreign government debt securities		—		1		—			1
U.S. government debt securities		—		88		—			88
U.S. state debt securities		—		2		—			2
Other		—		14		—			14
Total assets	$	160	$	142	$	112		$	414
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(116	)	$	(116	)
Total liabilities	$	—	$	—	$	(116	)	$	(116	)
Net assets (liabilities)(3)	$	160	$	142	$	(4	)	$	298

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $(1) million and $(9) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables, deferred taxes and accrued income associated with the financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts held by Met-Ed and classified as Level 3 in the fair value hierarchy during the periods ending June 30, 2011 and December 31, 2010:

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	112		$	(116	)	$	(4	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(42	)		(36	)		(78	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(4	)		30			26
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	66		$	(122	)	$	(56	)
January 1, 2010 Balance	$	176		$	(143	)	$	33
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(59	)		(38	)		(97	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(5	)		65			60
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	112		$	(116	)	$	(4	)

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

Pennsylvania Electric Company

The following tables summarize assets and liabilities recorded on Penelec’s Consolidated Balance Sheets at fair value as of June 30, 2011 and December 31, 2010:

June 30, 2011	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	69	$	—		$	69
Derivative assets — NUG contracts(1)		—		—		4			4
Equity securities(2)		20		—		—			20
Foreign government debt securities				12					12
U.S. government debt securities		—		52		—			52
U.S. state debt securities		—		81		—			81
Other		—		53		—			53
Total assets	$	20	$	267	$	4		$	291
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(160	)	$	(160	)
Total liabilities	$	—	$	—	$	(160	)	$	(160	)
Net assets (liabilities)(3)	$	20	$	267	$	(156	)	$	131

December 31, 2010	Level 1		Level 2		Level 3			Total
	(In millions)
Assets
Corporate debt securities	$	—	$	8	$	—		$	8
Derivative assets — commodity contracts		—		2		—			2
Derivative assets — NUG contracts(1)		—		—		4			4
Equity securities(2)		81		—		—			81
U.S. government debt securities		—		9		—			9
U.S. state debt securities		—		133		—			133
Other		—		5		—			5
Total assets	$	81	$	157	$	4		$	242
Liabilities
Derivative liabilities — NUG contracts(1)	$	—	$	—	$	(117	)	$	(117	)
Total liabilities	$	—	$	—	$	(117	)	$	(117	)
Net assets (liabilities)(3)	$	81	$	157	$	(113	)	$	125

(1)	NUG contracts are subject to regulatory accounting and do not impact earnings.
(2)	NDT funds hold equity portfolios the performance of which is benchmarked against the S&P 500 Index or Russell 3000 Index.
(3)	Excludes $1 million and $(3) million as of June 30, 2011 and December 31, 2010, respectively, of receivables, payables and accrued income associated with the financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG and commodity contracts held by Penelec and classified as Level 3 in the fair value hierarchy during the periods ended June 30, 2011 and December 31, 2010:

	Derivative Asset			Derivative Liability			Net
	NUG Contracts(1)			NUG Contracts(1)			NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	4		$	(117	)	$	(113	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		—			(88	)		(88	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		—			45			45
Transfers in (out) of Level 3		—			—			—
June 30, 2011 Balance	$	4		$	(160	)	$	(156	)
January 1, 2010 Balance	$	16		$	(101	)	$	(85	)
Realized gain (loss)		—			—			—
Unrealized gain (loss)		(11	)		(108	)		(119	)
Purchases		—			—			—
Issuances		—			—			—
Sales		—			—			—
Settlements		(1	)		92			91
Transfers in (out) of Level 3		—			—			—
December 31, 2010 Balance	$	4		$	(117	)	$	(113	)

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

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Impairment of Long-Lived Assets

6 Months Ended

Jun. 30, 2011

Impairment of Long-Lived Assets [Abstract]

IMPAIRMENT OF LONG-LIVED ASSETS

14. IMPAIRMENT OF LONG-LIVED ASSETS

FirstEnergy reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. The following events described in the sections below occurred during for the first six months of 2011 that indicated the carrying value of certain assets may not be recoverable.

Fremont Energy Center

On March 11, 2011, FirstEnergy and American Municipal Power, Inc., entered into an agreement for the sale of Fremont Energy Center, which 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. The execution of this agreement triggered a need to evaluate the recoverability of the carrying value of the assets associated with the Fremont Energy Center. The estimated fair value of the Fremont Energy Center was based on the purchase price outlined in the sale agreement with American Municipal Power, Inc. The result of this evaluation indicated that the carrying cost of the Fremont Energy Center was not fully recoverable. As a result of the recoverability evaluation, FirstEnergy recorded an impairment charge of $11 million to operating income during the quarter ended March 31, 2011. On July 28, 2011, FirstEnergy closed the sale of Fremont Energy Center to American Municipal Power, Inc.

Peaking Facilities

During the first six months of 2011, FirstEnergy assessed the carrying values of certain peaking facilities that will more likely than not be sold or disposed of before the end of their useful lives. The estimated fair values were based on estimated sales prices quoted in an active market. The result of this evaluation indicated that the carrying costs of the peaking facilities were not fully recoverable. FirstEnergy recorded impairment charges of $7 million and $21 million during the three months and six months ended June 30, 2011, respectively, as a result of the recoverability evaluation.

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Stock-Based Compensation Plans (Details 2) (USD $)	6 Months Ended
	Jun. 30, 2011
Summary of options outstanding by plan and range of exercise price
Shares Under Options Outstanding	4,586,717
Weighted Average Exercise Price of Option Outstanding	$ 38.08
Remaining Contractual Life of Options Outstanding	3.64
$20.02 - $30.74
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 20.02
Options outstanding, Exercise Prices, Upper limit	$ 30.74
Shares Under Options Outstanding	1,045,122
Weighted Average Exercise Price of Option Outstanding	$ 26.54
Remaining Contractual Life of Options Outstanding	2.02
$30.89 - $40.93
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 30.89
Options outstanding, Exercise Prices, Upper limit	$ 40.93
Shares Under Options Outstanding	3,160,440
Weighted Average Exercise Price of Option Outstanding	$ 37.30
Remaining Contractual Life of Options Outstanding	4.17
$42.72 - $51.82
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 42.72
Options outstanding, Exercise Prices, Upper limit	$ 51.82
Shares Under Options Outstanding	3,883
Weighted Average Exercise Price of Option Outstanding	$ 51.02
Remaining Contractual Life of Options Outstanding	0.70
$53.06 - $62.97
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 53.06
Options outstanding, Exercise Prices, Upper limit	$ 62.97
Shares Under Options Outstanding	54,559
Weighted Average Exercise Price of Option Outstanding	$ 56.15
Remaining Contractual Life of Options Outstanding	3.02
$64.52 - $71.82
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 64.52
Options outstanding, Exercise Prices, Upper limit	$ 71.82
Shares Under Options Outstanding	9,042
Weighted Average Exercise Price of Option Outstanding	$ 67.50
Remaining Contractual Life of Options Outstanding	5.24
$73.39 - $80.47
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 73.39
Options outstanding, Exercise Prices, Upper limit	$ 80.47
Shares Under Options Outstanding	311,003
Weighted Average Exercise Price of Option Outstanding	$ 80.17
Remaining Contractual Life of Options Outstanding	3.81
$81.19 - $89.59
Summary of options outstanding by plan and range of exercise price
Options outstanding, Exercise Prices, Lower limit	$ 81.19
Options outstanding, Exercise Prices, Upper limit	$ 89.59
Shares Under Options Outstanding	2,668
Weighted Average Exercise Price of Option Outstanding	$ 85.39
Remaining Contractual Life of Options Outstanding	6.09

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Stock-Based Compensation Plans (Details) (Restricted Stock and Restricted Stock Units Awards)	6 Months Ended
	Jun. 30, 2011
Restricted Stock and Restricted Stock Units Awards
Restricted Stock and Restricted Stock Units
Restricted stock and stock units outstanding, Beginning balance	1,878,022
Granted	891,881
Converted Allegheny restricted stock	645,197
Exercised	(428,686)
Forfeited	(71,775)
Restricted stock and stock units outstanding, Ending balance	2,914,639

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Merger (Details 5) (USD $) In Millions, except Per Share data	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Summary of consolidated results of operations
Revenue	$ 4,062	$ 4,401	$ 8,848	$ 9,086
Earnings available to FirstEnergy	$ 186	$ 389	$ 323	$ 644
Basic Earnings Per Share	$ 0.44	$ 0.93	$ 0.77	$ 1.54
Diluted Earnings Per Share	$ 0.44	$ 0.93	$ 0.77	$ 1.53

XML



Asset Retirement Obligations (Details) (USD $) In Millions	3 Months Ended
	Jun. 30, 2011	Mar. 31, 2011
FES
Asset Retirement Obligations [Line Items]
Increase (decrease) in asset retirement obligations in the period	$ 5	$ 40
OE
Asset Retirement Obligations [Line Items]
Increase (decrease) in asset retirement obligations in the period		$ 6

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Pension and Other Postretirement Benefits (Tables)

6 Months Ended

Jun. 30, 2011

Pension and Other Postretirement Benefits [Abstract]

Components of Net Periodic Benefit Costs

	Three Months Ended						Six Months Ended
	June 30						June 30
Pension Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	34		$	25		$	62		$	49
Interest cost		97			79			181			157
Expected return on plan assets		(115	)		(90	)		(216	)		(181	)
Amortization of prior service cost		4			3			7			6
Recognized net actuarial loss		48			47			97			94
Curtailments(1)		—			—			(2	)		—
Special termination benefits(1)		—			—			9			—
Net periodic cost	$	68		$	64		$	138		$	125

⁽¹⁾ Represents costs (credits) incurred related to change in control provision payments to certain executives who were terminated or were expected to be terminated as a result of the merger.

	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefit Cost (Credit)	2011			2010			2011			2010
	(In millions)
Service cost	$	3		$	3		$	7		$	5
Interest cost		12			11			23			22
Expected return on plan assets		(10	)		(9	)		(20	)		(18	)
Amortization of prior service cost		(52	)		(48	)		(100	)		(96	)
Recognized net actuarial loss		14			15			28			30
Net periodic cost (credit)	$	(33	)	$	(28	)	$	(62	)	$	(57	)

Components of Net Periodic Benefit Costs Allocated to subsidiaries

	Three Months Ended				Six Months Ended
	June 30				June 30
Pension Benefit Cost	2011		2010		2011		2010
	(In millions)
FES	$	22	$	22	$	43	$	44
OE		5		6		11		11
CEI		5		5		10		11
TE		2		2		3		4
JCP&L		5		6		11		12
Met-Ed		3		3		5		5
Penelec		4		5		9		9
Other FirstEnergy Subsidiaries		22		15		46		29
	$	68	$	64	$	138	$	125

	Three Months Ended						Six Months Ended
	June 30						June 30
Other Postretirement Benefit Credit	2011			2010			2011			2010
	(In millions)
FES	$	(8	)	$	(7	)	$	(14	)	$	(13	)
OE		(5	)		(6	)		(12	)		(12	)
CEI		(2	)		(1	)		(3	)		(3	)
TE		—			—			(1	)		(1	)
JCP&L		(2	)		(2	)		(3	)		(4	)
Met-Ed		(2	)		(2	)		(5	)		(4	)
Penelec		(2	)		(2	)		(5	)		(4	)
Other FirstEnergy Subsidiaries		(12	)		(8	)		(19	)		(16	)
	$	(33	)	$	(28	)	$	(62	)	$	(57	)

XML



Consolidated Balance Sheets (Unaudited) (USD $)	Jun. 30, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 476,000,000	$ 1,019,000,000
Receivables-
Customers, net of allowance for uncollectible accounts	1,578,000,000	1,392,000,000
Other, net of allowance for uncollectible accounts	256,000,000	176,000,000
Materials and supplies, at average cost	866,000,000	638,000,000
Prepaid taxes	474,000,000	199,000,000
Derivatives	265,000,000	182,000,000
Other	203,000,000	92,000,000
Total current assets	4,118,000,000	3,698,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	39,568,000,000	29,451,000,000
Less - Accumulated provision for depreciation	11,593,000,000	11,180,000,000
Total in service, accumulated provision for depreciation	27,975,000,000	18,271,000,000
Construction work in progress	1,465,000,000	1,517,000,000
Property, plant and equipment held for sale, net	502,000,000	0
Net plant in service	29,942,000,000	19,788,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	2,051,000,000	1,973,000,000
Investments in lease obligation bonds	414,000,000	476,000,000
Nuclear fuel disposal trust	212,000,000	208,000,000
Other	479,000,000	345,000,000
Total investments	3,156,000,000	3,002,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,456,000,000	5,575,000,000
Regulatory assets	2,182,000,000	1,826,000,000
Intangible assets	973,000,000	256,000,000
Other	769,000,000	660,000,000
Total deferred charges and other assets	10,380,000,000	8,317,000,000
Total assets	47,596,000,000	34,805,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	2,058,000,000	1,486,000,000
Short-term borrowings-
Short-term borrowings	656,000,000	700,000,000
Accounts payable-
Other	1,122,000,000	872,000,000
Accrued taxes	399,000,000	326,000,000
Accrued compensation and benefits	331,000,000	315,000,000
Derivatives	287,000,000	266,000,000
Other	691,000,000	733,000,000
Total current liabilities	5,544,000,000	4,698,000,000
Common stockholders' equity-
Common stock	42,000,000	31,000,000
Other paid-in capital	9,782,000,000	5,444,000,000
Accumulated other comprehensive loss	(1,433,000,000)	(1,539,000,000)
Retained earnings	4,607,000,000	4,609,000,000
Total common stockholders' equity	12,998,000,000	8,545,000,000
Noncontrolling interest	(48,000,000)	(32,000,000)
Total equity	12,950,000,000	8,513,000,000
Long-term debt and other long-term obligations	16,491,000,000	12,579,000,000
Total capitalization	29,441,000,000	21,092,000,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	5,219,000,000	2,879,000,000
Retirement benefits	2,134,000,000	1,868,000,000
Asset retirement obligations	1,459,000,000	1,407,000,000
Deferred gain on sale and leaseback transaction	942,000,000	959,000,000
Adverse power contract liability	649,000,000	466,000,000
Other	2,208,000,000	1,436,000,000
Total noncurrent liabilities	12,611,000,000	9,015,000,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	47,596,000,000	34,805,000,000
FES
CURRENT ASSETS:
Cash and cash equivalents	6,000,000	9,000,000
Receivables-
Customers, net of allowance for uncollectible accounts	450,000,000	366,000,000
Associated companies	490,000,000	478,000,000
Other, net of allowance for uncollectible accounts	51,000,000	90,000,000
Materials and supplies, at average cost	499,000,000	545,000,000
Notes receivable from associated companies	490,000,000	397,000,000
Derivatives	221,000,000	182,000,000
Other	49,000,000	59,000,000
Total current assets	2,256,000,000	2,126,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	11,455,000,000	11,321,000,000
Less - Accumulated provision for depreciation	4,206,000,000	4,024,000,000
Total in service, accumulated provision for depreciation	7,249,000,000	7,297,000,000
Construction work in progress	694,000,000	1,063,000,000
Property, plant and equipment held for sale, net	487,000,000	0
Net plant in service	8,430,000,000	8,360,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	1,184,000,000	1,146,000,000
Other	10,000,000	12,000,000
Total investments	1,194,000,000	1,158,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	129,000,000	134,000,000
Goodwill	24,000,000	24,000,000
Property taxes	41,000,000	41,000,000
Unamortized sale and leaseback costs	76,000,000	73,000,000
Derivatives	135,000,000	98,000,000
Other	75,000,000	48,000,000
Total deferred charges and other assets	480,000,000	418,000,000
Total assets	12,360,000,000	12,062,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	1,088,000,000	1,132,000,000
Short-term borrowings-
Associated companies	541,000,000	12,000,000
Short-term borrowings	1,000,000	0
Accounts payable-
Associated companies	393,000,000	467,000,000
Other	191,000,000	241,000,000
Derivatives	242,000,000	266,000,000
Other	262,000,000	322,000,000
Total current liabilities	2,718,000,000	2,440,000,000
Common stockholders' equity-
Common stock	1,488,000,000	1,490,000,000
Accumulated other comprehensive loss	(105,000,000)	(120,000,000)
Retained earnings	2,474,000,000	2,418,000,000
Total common stockholders' equity	3,857,000,000	3,788,000,000
Long-term debt and other long-term obligations	3,000,000,000	3,181,000,000
Total capitalization	6,857,000,000	6,969,000,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	216,000,000	58,000,000
Retirement benefits	295,000,000	285,000,000
Asset retirement obligations	875,000,000	892,000,000
Deferred gain on sale and leaseback transaction	942,000,000	959,000,000
Lease market valuation liability	194,000,000	217,000,000
Derivatives	85,000,000	81,000,000
Other	178,000,000	161,000,000
Total noncurrent liabilities	2,785,000,000	2,653,000,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	12,360,000,000	12,062,000,000
OE
CURRENT ASSETS:
Cash and cash equivalents	176,000	420,489,000
Receivables-
Customers, net of allowance for uncollectible accounts	159,393,000	176,591,000
Associated companies	68,709,000	118,135,000
Other, net of allowance for uncollectible accounts	32,798,000	12,232,000
Notes receivable from associated companies	95,884,000	16,957,000
Other	35,339,000	6,393,000
Total current assets	392,299,000	750,797,000
PROPERTY, PLANT AND EQUIPMENT:
In service	3,176,455,000	3,136,623,000
Less - Accumulated provision for depreciation	1,230,570,000	1,207,745,000
Total in service, accumulated provision for depreciation	1,945,885,000	1,928,878,000
Construction work in progress	66,656,000	45,103,000
Net plant in service	2,012,541,000	1,973,981,000
INVESTMENTS:
Nuclear plant decommissioning trusts	133,354,000	127,017,000
Investments in lease obligation bonds	177,835,000	190,420,000
Other	92,440,000	95,563,000
Total investments	403,629,000	413,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	392,580,000	400,322,000
Pension assets	62,612,000	28,596,000
Property taxes	71,331,000	71,331,000
Unamortized sale and leaseback costs	27,628,000	30,126,000
Other	19,041,000	17,634,000
Total deferred charges and other assets	573,192,000	548,009,000
Total assets	3,381,661,000	3,685,787,000
CURRENT LIABILITIES:
Currently payable long-term debt	1,429,000	1,419,000
Short-term borrowings-
Associated companies	0	142,116,000
Short-term borrowings	166,000	320,000
Accounts payable-
Associated companies	94,821,000	99,421,000
Other	41,417,000	29,639,000
Accrued taxes	69,364,000	78,707,000
Accrued interest	25,374,000	25,382,000
Other	79,795,000	74,947,000
Total current liabilities	312,366,000	451,951,000
Common stockholders' equity-
Common stock	783,871,000	951,866,000
Accumulated other comprehensive loss	(174,936,000)	(179,076,000)
Retained earnings	110,156,000	141,621,000
Total common stockholders' equity	719,091,000	914,411,000
Noncontrolling interest	5,313,000	5,680,000
Total equity	724,404,000	920,091,000
Long-term debt and other long-term obligations	1,151,720,000	1,152,134,000
Total capitalization	1,876,124,000	2,072,225,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	749,687,000	696,410,000
Retirement benefits	183,345,000	183,712,000
Asset retirement obligations	69,164,000	74,456,000
Accumulated deferred investment tax credits	9,439,000	10,159,000
Other	181,536,000	196,874,000
Total noncurrent liabilities	1,193,171,000	1,161,611,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	3,381,661,000	3,685,787,000
CEI
CURRENT ASSETS:
Cash and cash equivalents	244,000	238,000
Receivables-
Customers, net of allowance for uncollectible accounts	97,997,000	183,744,000
Associated companies	32,348,000	77,047,000
Other, net of allowance for uncollectible accounts	13,476,000	11,544,000
Materials and supplies, at average cost	13,784,000	398,000
Notes receivable from associated companies	71,911,000	23,236,000
Other	6,431,000	3,258,000
Total current assets	236,191,000	299,465,000
PROPERTY, PLANT AND EQUIPMENT:
In service	2,417,031,000	2,396,893,000
Less - Accumulated provision for depreciation	944,379,000	932,246,000
Total in service, accumulated provision for depreciation	1,472,652,000	1,464,647,000
Construction work in progress	59,281,000	38,610,000
Net plant in service	1,531,933,000	1,503,257,000
INVESTMENTS:
Investment in lessor notes	286,745,000	340,029,000
Other	10,048,000	10,074,000
Total investments	296,793,000	350,103,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	1,688,521,000	1,688,521,000
Regulatory assets	320,337,000	370,403,000
Pension assets	14,652,000	0
Property taxes	80,614,000	80,614,000
Other	12,884,000	11,486,000
Total deferred charges and other assets	2,117,008,000	2,151,024,000
Total assets	4,181,925,000	4,303,849,000
CURRENT LIABILITIES:
Currently payable long-term debt	188,000	161,000
Short-term borrowings-
Associated companies	2,303,000	105,996,000
Accounts payable-
Associated companies	51,001,000	32,020,000
Other	18,700,000	14,947,000
Accrued taxes	83,265,000	84,668,000
Accrued interest	18,551,000	18,555,000
Other	38,685,000	44,569,000
Total current liabilities	233,693,000	300,916,000
Common stockholders' equity-
Common stock	887,053,000	887,087,000
Accumulated other comprehensive loss	(147,643,000)	(153,187,000)
Retained earnings	539,280,000	568,906,000
Total common stockholders' equity	1,278,690,000	1,302,806,000
Noncontrolling interest	15,195,000	18,017,000
Total equity	1,293,885,000	1,320,823,000
Long-term debt and other long-term obligations	1,831,023,000	1,852,530,000
Total capitalization	3,124,908,000	3,173,353,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	640,059,000	622,771,000
Retirement benefits	76,010,000	95,654,000
Accumulated deferred investment tax credits	10,574,000	10,994,000
Other	96,681,000	100,161,000
Total noncurrent liabilities	823,324,000	829,580,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	4,181,925,000	4,303,849,000
TE
CURRENT ASSETS:
Cash and cash equivalents	12,000	149,262,000
Receivables-
Customers, net of allowance for uncollectible accounts	45,931,000	29,000
Associated companies	48,340,000	31,777,000
Other, net of allowance for uncollectible accounts	5,272,000	18,464,000
Notes receivable from associated companies	128,815,000	96,765,000
Other	12,052,000	2,306,000
Total current assets	240,422,000	298,603,000
PROPERTY, PLANT AND EQUIPMENT:
In service	955,002,000	947,203,000
Less - Accumulated provision for depreciation	453,517,000	446,401,000
Total in service, accumulated provision for depreciation	501,485,000	500,802,000
Construction work in progress	17,386,000	12,604,000
Net plant in service	518,871,000	513,406,000
INVESTMENTS:
Investment in lessor notes	82,153,000	103,872,000
Nuclear plant decommissioning trusts	79,018,000	75,558,000
Other	1,448,000	1,492,000
Total investments	162,619,000	180,922,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	500,576,000	500,576,000
Regulatory assets	89,112,000	72,059,000
Pension assets	24,603,000	0
Property taxes	24,990,000	24,990,000
Other	42,341,000	23,750,000
Total deferred charges and other assets	681,622,000	621,375,000
Total assets	1,603,534,000	1,614,306,000
CURRENT LIABILITIES:
Currently payable long-term debt	188,000	199,000
Accounts payable-
Associated companies	22,144,000	17,168,000
Other	12,524,000	7,351,000
Accrued taxes	23,699,000	24,401,000
Accrued interest	5,933,000	5,931,000
Lease market valuation liability	36,900,000	36,900,000
Other	18,060,000	23,145,000
Total current liabilities	119,448,000	115,095,000
Common stockholders' equity-
Common stock	147,010,000	147,010,000
Other paid-in capital	178,157,000	178,182,000
Accumulated other comprehensive loss	(46,642,000)	(49,183,000)
Retained earnings	100,937,000	117,534,000
Total common stockholders' equity	379,462,000	393,543,000
Noncontrolling interest	2,593,000	2,589,000
Total equity	382,055,000	396,132,000
Long-term debt and other long-term obligations	600,524,000	600,493,000
Total capitalization	982,579,000	996,625,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	168,429,000	132,019,000
Retirement benefits	51,764,000	71,486,000
Asset retirement obligations	29,737,000	28,762,000
Accumulated deferred investment tax credits	5,715,000	5,930,000
Lease market valuation liability	180,850,000	199,300,000
Other	65,012,000	65,089,000
Total noncurrent liabilities	501,507,000	502,586,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	1,603,534,000	1,614,306,000
JCP&L
CURRENT ASSETS:
Cash and cash equivalents	42,000	4,000
Receivables-
Customers, net of allowance for uncollectible accounts	259,313,000	323,044,000
Associated companies	66,069,000	53,780,000
Other, net of allowance for uncollectible accounts	25,580,000	26,119,000
Notes receivable from associated companies	16,288,000	177,228,000
Prepaid taxes	135,679,000	10,889,000
Other	15,421,000	12,654,000
Total current assets	518,392,000	603,718,000
PROPERTY, PLANT AND EQUIPMENT:
In service	4,589,369,000	4,562,781,000
Less - Accumulated provision for depreciation	1,682,577,000	1,656,939,000
Total in service, accumulated provision for depreciation	2,906,792,000	2,905,842,000
Construction work in progress	112,573,000	63,535,000
Net plant in service	3,019,365,000	2,969,377,000
INVESTMENTS:
Nuclear plant decommissioning trusts	190,422,000	181,851,000
Nuclear fuel disposal trust	212,419,000	207,561,000
Other	2,118,000	2,104,000
Total investments	404,959,000	391,516,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	1,810,936,000	1,810,936,000
Regulatory assets	469,490,000	513,395,000
Other	34,028,000	27,938,000
Total deferred charges and other assets	2,314,454,000	2,352,269,000
Total assets	6,257,170,000	6,316,880,000
CURRENT LIABILITIES:
Currently payable long-term debt	33,315,000	32,402,000
Short-term borrowings-
Associated companies	360,917,000	0
Short-term borrowings	50,000,000	0
Accounts payable-
Associated companies	56,544,000	28,571,000
Other	159,720,000	158,442,000
Accrued taxes	1,346,000	2,509,000
Customer deposits	23,684,000	23,385,000
Accrued interest	18,059,000	18,111,000
Accrued compensation and benefits	35,578,000	35,232,000
Other	13,487,000	22,263,000
Total current liabilities	752,650,000	320,915,000
Common stockholders' equity-
Common stock	136,284,000	136,284,000
Other paid-in capital	2,008,847,000	2,508,874,000
Accumulated other comprehensive loss	(248,095,000)	(253,542,000)
Retained earnings	288,484,000	227,170,000
Total common stockholders' equity	2,185,520,000	2,618,786,000
Long-term debt and other long-term obligations	1,754,582,000	1,769,849,000
Total capitalization	3,940,102,000	4,388,635,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	761,844,000	715,527,000
Retirement benefits	71,711,000	182,364,000
Asset retirement obligations	111,831,000	108,297,000
Power purchase contract liability	239,943,000	233,492,000
Nuclear fuel disposal costs	196,868,000	196,768,000
Other	182,221,000	170,882,000
Total noncurrent liabilities	1,564,418,000	1,607,330,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	6,257,170,000	6,316,880,000
Met-Ed
CURRENT ASSETS:
Cash and cash equivalents	157,000	243,220,000
Receivables-
Customers, net of allowance for uncollectible accounts	143,820,000	178,522,000
Associated companies	12,849,000	24,920,000
Other, net of allowance for uncollectible accounts	16,437,000	13,007,000
Notes receivable from associated companies	10,432,000	11,028,000
Prepaid taxes	27,083,000	343,000
Other	1,443,000	2,289,000
Total current assets	212,221,000	473,329,000
PROPERTY, PLANT AND EQUIPMENT:
In service	2,266,437,000	2,247,853,000
Less - Accumulated provision for depreciation	859,055,000	846,003,000
Total in service, accumulated provision for depreciation	1,407,382,000	1,401,850,000
Construction work in progress	42,604,000	23,663,000
Net plant in service	1,449,986,000	1,425,513,000
INVESTMENTS:
Nuclear plant decommissioning trusts	301,188,000	289,328,000
Other	840,000	884,000
Total investments	302,028,000	290,212,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	416,499,000	416,499,000
Regulatory assets	341,488,000	295,856,000
Power purchase contract asset	65,861,000	111,562,000
Other	54,587,000	31,699,000
Total deferred charges and other assets	878,435,000	855,616,000
Total assets	2,842,670,000	3,044,670,000
CURRENT LIABILITIES:
Currently payable long-term debt	28,760,000	28,760,000
Short-term borrowings-
Associated companies	238,399,000	124,079,000
Short-term borrowings	50,000,000	0
Accounts payable-
Associated companies	24,377,000	33,942,000
Other	48,262,000	29,862,000
Accrued taxes	12,844,000	60,856,000
Accrued interest	16,011,000	16,114,000
Other	29,605,000	29,278,000
Total current liabilities	448,258,000	322,891,000
Common stockholders' equity-
Common stock	842,023,000	1,197,076,000
Accumulated other comprehensive loss	(139,657,000)	(142,383,000)
Retained earnings	46,772,000	32,406,000
Total common stockholders' equity	749,138,000	1,087,099,000
Long-term debt and other long-term obligations	704,486,000	718,860,000
Total capitalization	1,453,624,000	1,805,959,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	494,716,000	473,009,000
Retirement benefits	22,276,000	29,121,000
Asset retirement obligations	199,162,000	192,659,000
Accumulated deferred investment tax credits	6,656,000	6,866,000
Power purchase contract liability	121,924,000	116,027,000
Nuclear fuel disposal costs	44,471,000	44,449,000
Other	51,583,000	53,689,000
Total noncurrent liabilities	940,788,000	915,820,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	2,842,670,000	3,044,670,000
Penelec
CURRENT ASSETS:
Cash and cash equivalents	2,000	5,000
Receivables-
Customers, net of allowance for uncollectible accounts	121,511,000	148,864,000
Associated companies	65,989,000	54,052,000
Other, net of allowance for uncollectible accounts	11,420,000	11,314,000
Notes receivable from associated companies	13,498,000	14,404,000
Prepaid taxes	26,372,000	14,026,000
Other	1,423,000	1,592,000
Total current assets	240,215,000	244,257,000
PROPERTY, PLANT AND EQUIPMENT:
In service	2,552,303,000	2,532,629,000
Less - Accumulated provision for depreciation	947,315,000	935,259,000
Total in service, accumulated provision for depreciation	1,604,988,000	1,597,370,000
Construction work in progress	62,592,000	30,505,000
Net plant in service	1,667,580,000	1,627,875,000
INVESTMENTS:
Nuclear plant decommissioning trusts	162,154,000	152,928,000
Non-utility generation trusts	126,786,000	80,244,000
Other	292,000	297,000
Total investments	289,232,000	233,469,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	768,628,000	768,628,000
Regulatory assets	222,804,000	163,407,000
Power purchase contract asset	4,000,000	5,746,000
Other	15,272,000	19,287,000
Total deferred charges and other assets	1,010,704,000	957,068,000
Total assets	3,207,731,000	3,062,669,000
CURRENT LIABILITIES:
Currently payable long-term debt	45,000,000	45,000,000
Short-term borrowings-
Associated companies	159,902,000	101,338,000
Accounts payable-
Associated companies	77,121,000	35,626,000
Other	29,217,000	41,420,000
Accrued taxes	3,397,000	5,075,000
Accrued interest	17,454,000	17,378,000
Other	23,280,000	22,541,000
Total current liabilities	355,371,000	268,378,000
Common stockholders' equity-
Common stock	88,552,000	88,552,000
Other paid-in capital	913,486,000	913,519,000
Accumulated other comprehensive loss	(161,251,000)	(163,526,000)
Retained earnings	23,017,000	60,993,000
Total common stockholders' equity	863,804,000	899,538,000
Long-term debt and other long-term obligations	1,072,417,000	1,072,262,000
Total capitalization	1,936,221,000	1,971,800,000
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	415,899,000	371,877,000
Retirement benefits	188,407,000	187,621,000
Asset retirement obligations	101,441,000	98,132,000
Power purchase contract liability	160,130,000	116,972,000
Other	50,262,000	47,889,000
Total noncurrent liabilities	916,139,000	822,491,000
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	$ 3,207,731,000	$ 3,062,669,000

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2011

Asset Retirement Obligations [Abstract]

ASSET RETIREMENT OBLIGATIONS

15. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost for nuclear power plant decommissioning, reclamation of sludge disposal ponds and closure of coal ash disposal sites. In addition, FirstEnergy has recognized conditional asset retirement obligations (primarily for asbestos remediation).

The ARO liabilities for FES, OE and TE primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities (OE for its leasehold interest in Beaver Valley Unit 2 and Perry and TE for its leasehold interest in Beaver Valley Unit 2). The ARO liabilities for JCP&L, Met-Ed and Penelec primarily relate to the decommissioning of the TMI-2 nuclear generating facility. FES, OE, JCP&L, Met-Ed and Penelec use an expected cash flow approach to measure the fair value of their nuclear decommissioning ARO.

During the first quarter of 2011, studies were completed to update the estimated cost of decommissioning the Perry nuclear generating facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and OE and reduced the liability for each subsidiary in the amounts of $40 million and $6 million, respectively.

During the second quarter of 2011, studies were completed to update the estimated cost of decommissioning the Davis-Besse nuclear facility. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and reduced the liability for FES in the amount of $5 million.

The revisions to the estimated cash flows had no significant impact on accretion of the obligation during the three months and six months ended June 30, 2011 when compared to the same periods of 2010.

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Fair Value Measurements (Details 2) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	$ 734	$ 1,183	$ 1,703	$ 1,915
Realized gains	22	46	122	83
Realized losses	(16)	(36)	(45)	(86)
Investment income	28	16	52	37
FES
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	297	685	513	957
Realized gains	10	41	22	54
Realized losses	(7)	(35)	(23)	(58)
Investment income	17	9	32	22
OE
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	12	57	20	60
Realized gains		2		2
Investment income	1		2	1
TE
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	15	76	28	107
Realized gains	1	2	1	3
Realized losses	(1)		(2)
Investment income	1		1	1
JCP&L
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	159	91	376	281
Realized gains	4		26	9
Realized losses	(2)		(6)	(9)
Investment income	4	3	8	7
Met-Ed
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	165	233	501	377
Realized gains	4	1	48	9
Realized losses	(3)	(1)	(7)	(12)
Investment income	3	2	5	3
Penelec
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sales Proceeds	86	41	265	134
Realized gains	3		25	6
Realized losses	(3)		(7)	(7)
Investment income	$ 2	$ 2	$ 4	$ 3

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New Accounting Standards and Interpretations (Policies)

6 Months Ended

Jun. 30, 2011

New Accounting Standards and Interpretations [Abstract]

Fair value measurement

In May 2011, the FASB amended authoritative accounting guidance regarding fair value measurement. The amendment prohibits the application of block discounts for all fair value measurements, permits the fair value of certain financial instruments to be measured on the basis of the net risk exposure and allows the application of premiums or discounts to the extent consistent with the applicable unit of account. The amendment clarifies that the highest-and-best use and valuation-premise concepts are not relevant to financial instruments. Expanded disclosures are required under the amendment, including quantitative information about significant unobservable inputs used for Level 3 measurements, a qualitative discussion about the sensitivity of recurring Level 3 measurements to changes in unobservable inputs disclosed, a discussion of the Level 3 valuation processes, any transfers between Levels 1 and 2 and the classification of items whose fair value is not recorded but is disclosed in the notes. The amendment is effective for FirstEnergy in the first quarter of 2012. FirstEnergy does not expect this amendment to have a material effect on its financial statements.

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Supplemental Guarantor Information (Details 1) (USD $)	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2010	Dec. 31, 2009
CURRENT ASSETS:
Cash and cash equivalents	$ 476,000,000	$ 1,019,000,000	$ 281,000,000	$ 874,000,000
Receivables-
Customers	1,578,000,000	1,392,000,000
Other	256,000,000	176,000,000
Materials and supplies	866,000,000	638,000,000
Derivatives	265,000,000	182,000,000
Prepayments and other	203,000,000	92,000,000
Total current assets	4,118,000,000	3,698,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	39,568,000,000	29,451,000,000
Less - Accumulated provision for depreciation	11,593,000,000	11,180,000,000
Total in service, accumulated provision for depreciation	27,975,000,000	18,271,000,000
Construction work in progress	1,465,000,000	1,517,000,000
Property, plant and equipment held for sale, net	502,000,000	0
Net plant in service	29,942,000,000	19,788,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	2,051,000,000	1,973,000,000
Other	479,000,000	345,000,000
Total investments	3,156,000,000	3,002,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,456,000,000	5,575,000,000	5,575,000,000
Other	769,000,000	660,000,000
Total deferred charges and other assets	10,380,000,000	8,317,000,000
Total assets	47,596,000,000	34,805,000,000	34,466,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	2,058,000,000	1,486,000,000
Short-term borrowings-
Other	656,000,000	700,000,000
Accounts payable-
Other	1,122,000,000	872,000,000
Derivatives	287,000,000	266,000,000
Other	691,000,000	733,000,000
Total current liabilities	5,544,000,000	4,698,000,000
CAPITALIZATION:
Common stockholder's equity	12,998,000,000	8,545,000,000
Long-term debt and other long-term obligations	16,491,000,000	12,579,000,000
Total capitalization	29,441,000,000	21,092,000,000
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback	942,000,000	959,000,000
Accumulated deferred income taxes	5,219,000,000	2,879,000,000
Asset retirement obligations	1,459,000,000	1,407,000,000
Retirement benefits	2,134,000,000	1,868,000,000
Other	2,208,000,000	1,436,000,000
Total noncurrent liabilities	12,611,000,000	9,015,000,000
Total liabilities and capitalization	47,596,000,000	34,805,000,000
FES Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	450,000,000	366,000,000
Associated companies	481,000,000	333,000,000
Other	24,000,000	21,000,000
Notes receivable from associated companies	6,000,000	34,000,000
Materials and supplies	54,000,000	41,000,000
Derivatives	221,000,000	182,000,000
Prepayments and other	34,000,000	48,000,000
Total current assets	1,270,000,000	1,025,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	101,000,000	96,000,000
Less - Accumulated provision for depreciation	19,000,000	17,000,000
Total in service, accumulated provision for depreciation	82,000,000	79,000,000
Construction work in progress	10,000,000	9,000,000
Property, plant and equipment held for sale, net	0
Net plant in service	92,000,000	88,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in associated companies	5,302,000,000	4,942,000,000
Other	1,000,000	0
Total investments	5,303,000,000	4,942,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes	18,000,000	43,000,000
Customer intangibles	129,000,000	134,000,000
Goodwill	24,000,000	24,000,000
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	135,000,000	98,000,000
Other	39,000,000	21,000,000
Total deferred charges and other assets	345,000,000	320,000,000
Total assets	7,010,000,000	6,375,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	1,000,000	101,000,000
Short-term borrowings-
Associated companies	453,000,000	0
Other	0
Accounts payable-
Associated companies	665,000,000	351,000,000
Other	80,000,000	139,000,000
Derivatives	242,000,000	266,000,000
Other	69,000,000	56,000,000
Total current liabilities	1,510,000,000	913,000,000
CAPITALIZATION:
Common stockholder's equity	3,858,000,000	3,788,000,000
Long-term debt and other long-term obligations	1,483,000,000	1,519,000,000
Total capitalization	5,341,000,000	5,307,000,000
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	0	0
Retirement benefits	50,000,000	48,000,000
Lease market valuation liability	0	0
Derivatives	85,000,000	81,000,000
Other	24,000,000	26,000,000
Total noncurrent liabilities	159,000,000	155,000,000
Total liabilities and capitalization	7,010,000,000	6,375,000,000
FGCO
CURRENT ASSETS:
Cash and cash equivalents	6,000,000	9,000,000	0	0
Receivables-
Customers	0	0
Associated companies	425,000,000	357,000,000
Other	23,000,000	56,000,000
Notes receivable from associated companies	410,000,000	189,000,000
Materials and supplies	253,000,000	276,000,000
Derivatives	0	0
Prepayments and other	14,000,000	10,000,000
Total current assets	1,131,000,000	897,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	6,105,000,000	6,198,000,000
Less - Accumulated provision for depreciation	2,067,000,000	2,020,000,000
Total in service, accumulated provision for depreciation	4,038,000,000	4,178,000,000
Construction work in progress	198,000,000	520,000,000
Property, plant and equipment held for sale, net	487,000,000
Net plant in service	4,723,000,000	4,698,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in associated companies	0	0
Other	9,000,000	12,000,000
Total investments	9,000,000	12,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes	344,000,000	412,000,000
Customer intangibles	0	0
Goodwill	0	0
Property taxes	16,000,000	16,000,000
Unamortized sale and leaseback costs	6,000,000	10,000,000
Derivatives	0	0
Other	97,000,000	71,000,000
Total deferred charges and other assets	463,000,000	509,000,000
Total assets	6,326,000,000	6,116,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	436,000,000	419,000,000
Short-term borrowings-
Associated companies	88,000,000	12,000,000
Other	1,000,000
Accounts payable-
Associated companies	231,000,000	213,000,000
Other	111,000,000	102,000,000
Derivatives	0	0
Other	137,000,000	183,000,000
Total current liabilities	1,004,000,000	929,000,000
CAPITALIZATION:
Common stockholder's equity	2,728,000,000	2,515,000,000
Long-term debt and other long-term obligations	2,050,000,000	2,119,000,000
Total capitalization	4,778,000,000	4,634,000,000
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	28,000,000	27,000,000
Retirement benefits	245,000,000	237,000,000
Lease market valuation liability	194,000,000	217,000,000
Derivatives	0	0
Other	77,000,000	72,000,000
Total noncurrent liabilities	544,000,000	553,000,000
Total liabilities and capitalization	6,326,000,000	6,116,000,000
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Associated companies	263,000,000	126,000,000
Other	4,000,000	13,000,000
Notes receivable from associated companies	74,000,000	174,000,000
Materials and supplies	192,000,000	228,000,000
Derivatives	0	0
Prepayments and other	1,000,000	1,000,000
Total current assets	534,000,000	542,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	5,634,000,000	5,412,000,000
Less - Accumulated provision for depreciation	2,298,000,000	2,162,000,000
Total in service, accumulated provision for depreciation	3,336,000,000	3,250,000,000
Construction work in progress	486,000,000	534,000,000
Property, plant and equipment held for sale, net	0
Net plant in service	3,822,000,000	3,784,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	1,184,000,000	1,146,000,000
Investment in associated companies	0	0
Other	0	0
Total investments	1,184,000,000	1,146,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	25,000,000	25,000,000
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	7,000,000	14,000,000
Total deferred charges and other assets	32,000,000	39,000,000
Total assets	5,572,000,000	5,511,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	671,000,000	632,000,000
Short-term borrowings-
Associated companies	0	0
Other	0
Accounts payable-
Associated companies	165,000,000	250,000,000
Other	0	0
Derivatives	0	0
Other	46,000,000	46,000,000
Total current liabilities	882,000,000	928,000,000
CAPITALIZATION:
Common stockholder's equity	2,556,000,000	2,414,000,000
Long-term debt and other long-term obligations	706,000,000	793,000,000
Total capitalization	3,262,000,000	3,207,000,000
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback	0	0
Accumulated deferred income taxes	504,000,000	448,000,000
Asset retirement obligations	847,000,000	865,000,000
Retirement benefits	0	0
Lease market valuation liability	0	0
Derivatives	0	0
Other	77,000,000	63,000,000
Total noncurrent liabilities	1,428,000,000	1,376,000,000
Total liabilities and capitalization	5,572,000,000	5,511,000,000
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Associated companies	(679,000,000)	(338,000,000)
Other	0	0
Notes receivable from associated companies	0	0
Materials and supplies	0	0
Derivatives	0	0
Prepayments and other	0	0
Total current assets	(679,000,000)	(338,000,000)
PROPERTY, PLANT AND EQUIPMENT:
In service	(385,000,000)	(385,000,000)
Less - Accumulated provision for depreciation	(178,000,000)	(175,000,000)
Total in service, accumulated provision for depreciation	(207,000,000)	(210,000,000)
Construction work in progress	0	0
Property, plant and equipment held for sale, net	0
Net plant in service	(207,000,000)	(210,000,000)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in associated companies	(5,302,000,000)	(4,942,000,000)
Other	0	0
Total investments	(5,302,000,000)	(4,942,000,000)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes	(362,000,000)	(455,000,000)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	70,000,000	63,000,000
Derivatives	0	0
Other	(68,000,000)	(58,000,000)
Total deferred charges and other assets	(360,000,000)	(450,000,000)
Total assets	(6,548,000,000)	(5,940,000,000)
CURRENT LIABILITIES:
Currently payable long-term debt	(20,000,000)	(20,000,000)
Short-term borrowings-
Associated companies	0	0
Other	0
Accounts payable-
Associated companies	(668,000,000)	(347,000,000)
Other	0	0
Derivatives	0	0
Other	10,000,000	37,000,000
Total current liabilities	(678,000,000)	(330,000,000)
CAPITALIZATION:
Common stockholder's equity	(5,285,000,000)	(4,929,000,000)
Long-term debt and other long-term obligations	(1,239,000,000)	(1,250,000,000)
Total capitalization	(6,524,000,000)	(6,179,000,000)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback	942,000,000	959,000,000
Accumulated deferred income taxes	(288,000,000)	(390,000,000)
Asset retirement obligations	0	0
Retirement benefits	0	0
Lease market valuation liability	0	0
Derivatives	0	0
Other	0	0
Total noncurrent liabilities	654,000,000	569,000,000
Total liabilities and capitalization	(6,548,000,000)	(5,940,000,000)
FES
CURRENT ASSETS:
Cash and cash equivalents	6,000,000	9,000,000	0	0
Receivables-
Customers	450,000,000	366,000,000
Associated companies	490,000,000	478,000,000
Other	51,000,000	90,000,000
Notes receivable from associated companies	490,000,000	397,000,000
Materials and supplies	499,000,000	545,000,000
Derivatives	221,000,000	182,000,000
Prepayments and other	49,000,000	59,000,000
Total current assets	2,256,000,000	2,126,000,000
PROPERTY, PLANT AND EQUIPMENT:
In service	11,455,000,000	11,321,000,000
Less - Accumulated provision for depreciation	4,206,000,000	4,024,000,000
Total in service, accumulated provision for depreciation	7,249,000,000	7,297,000,000
Construction work in progress	694,000,000	1,063,000,000
Property, plant and equipment held for sale, net	487,000,000	0
Net plant in service	8,430,000,000	8,360,000,000
INVESTMENTS:
Nuclear plant decommissioning trusts	1,184,000,000	1,146,000,000
Investment in associated companies	0	0
Other	10,000,000	12,000,000
Total investments	1,194,000,000	1,158,000,000
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income taxes	0	0
Customer intangibles	129,000,000	134,000,000
Goodwill	24,000,000	24,000,000
Property taxes	41,000,000	41,000,000
Unamortized sale and leaseback costs	76,000,000	73,000,000
Derivatives	135,000,000	98,000,000
Other	75,000,000	48,000,000
Total deferred charges and other assets	480,000,000	418,000,000
Total assets	12,360,000,000	12,062,000,000
CURRENT LIABILITIES:
Currently payable long-term debt	1,088,000,000	1,132,000,000
Short-term borrowings-
Associated companies	541,000,000	12,000,000
Other	1,000,000	0
Accounts payable-
Associated companies	393,000,000	467,000,000
Other	191,000,000	241,000,000
Derivatives	242,000,000	266,000,000
Other	262,000,000	322,000,000
Total current liabilities	2,718,000,000	2,440,000,000
CAPITALIZATION:
Common stockholder's equity	3,857,000,000	3,788,000,000
Long-term debt and other long-term obligations	3,000,000,000	3,181,000,000
Total capitalization	6,857,000,000	6,969,000,000
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback	942,000,000	959,000,000
Accumulated deferred income taxes	216,000,000	58,000,000
Asset retirement obligations	875,000,000	892,000,000
Retirement benefits	295,000,000	285,000,000
Lease market valuation liability	194,000,000	217,000,000
Derivatives	85,000,000	81,000,000
Other	178,000,000	161,000,000
Total noncurrent liabilities	2,785,000,000	2,653,000,000
Total liabilities and capitalization	$ 12,360,000,000	$ 12,062,000,000

XML



Segment Information (Details Textuals)	6 Months Ended
	Jun. 30, 2011
Segment Information (Textuals) [Abstract]
Number of existing utility operating companies	10
Previous [Member]
Segment Reporting Information [Line Items]
Reportable Operating Segments	3
Current [Member]
Segment Reporting Information [Line Items]
Reportable Operating Segments	2
Regulated Distribution
Segment Reporting Information [Line Items]
Number of customers served by utility operating companies	6,000,000
Number of square miles in service area	67,000
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	20,000
Number of generation facilities from which the company purchases entire output	18
Number of facilities of which the company owns, operates and controls electric generation capacity	18
Equity ownership percentage by parent	59.00%
Generation capacity of the facility from which all the company's revenue generated	1,109
Competitive Energy Services | AGC
Segment Reporting Information [Line Items]
Ownership interest	40.00%
Competitive Energy Services | MP
Segment Reporting Information [Line Items]
Ownership interest	41.00%

XML



Consolidated Statements of Cash Flows (Unaudited) (USD $)	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 216,000,000	$ 405,000,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	502,000,000	383,000,000
Amortization of regulatory assets, net	222,000,000	373,000,000
Nuclear fuel and lease amortization	92,000,000	76,000,000
Deferred purchased power and other costs	(168,000,000)	(146,000,000)
Deferred income taxes and investment tax credits, net	552,000,000	159,000,000
Deferred rents and lease market valuation liability	(61,000,000)	(62,000,000)
Accrued compensation and retirement benefits	49,000,000	(27,000,000)
Commodity derivative transactions, net	(21,000,000)	(29,000,000)
Pension trust contribution	(262,000,000)
Asset impairments	41,000,000	21,000,000
Cash from (to) suppliers, net	(31,000,000)	(63,000,000)
Interest rate swap transactions		43,000,000
Decrease (increase) in operating assets-
Receivables	199,000,000	(156,000,000)
Materials and supplies	24,000,000	(17,000,000)
Prepayments and other current assets	(268,000,000)	(81,000,000)
Increase (decrease) in operating liabilities-
Accounts payable	(28,000,000)	18,000,000
Accrued taxes	(66,000,000)	(58,000,000)
Accrued interest	(4,000,000)	10,000,000
Other	43,000,000	9,000,000
Net cash provided from operating activities	1,031,000,000	858,000,000
New Financing-
Long-term debt	503,000,000
Short-term borrowings, net		281,000,000
Redemptions and Repayments-
Long-term debt	(1,002,000,000)	(407,000,000)
Short-term borrowings, net	(44,000,000)
Common stock dividend payments	(420,000,000)	(335,000,000)
Other	(76,000,000)	(23,000,000)
Net cash used for financing activities	(1,039,000,000)	(484,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,018,000,000)	(997,000,000)
Proceeds from asset sales		116,000,000
Sales of investment securities held in trusts	1,703,000,000	1,915,000,000
Purchases of investment securities held in trusts	(1,807,000,000)	(1,934,000,000)
Customer acquisition costs	(2,000,000)	(105,000,000)
Cash investments	50,000,000	59,000,000
Cash received in Allegheny merger	590,000,000
Other	(51,000,000)	(21,000,000)
Net cash provided from (used for) investing activities	(535,000,000)	(967,000,000)
Net change in cash and cash equivalents	(543,000,000)	(593,000,000)
Cash and cash equivalents at beginning of period	1,019,000,000	874,000,000
Cash and cash equivalents at end of period	476,000,000	281,000,000
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: merger with Allegheny, common stock issued	4,354,000,000
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	56,000,000	214,000,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	136,000,000	126,000,000
Nuclear fuel and lease amortization	92,000,000	78,000,000
Deferred income taxes and investment tax credits, net	126,000,000	114,000,000
Deferred rents and lease market valuation liability	(58,000,000)	(59,000,000)
Accrued compensation and retirement benefits	8,000,000	7,000,000
Commodity derivative transactions, net	(60,000,000)	(29,000,000)
Asset impairments	28,000,000	21,000,000
Cash from (to) suppliers, net	(40,000,000)	(38,000,000)
Decrease (increase) in operating assets-
Receivables	(36,000,000)	(193,000,000)
Materials and supplies	50,000,000	(29,000,000)
Prepayments and other current assets	12,000,000	25,000,000
Increase (decrease) in operating liabilities-
Accounts payable	(124,000,000)	(32,000,000)
Accrued taxes	(29,000,000)	(8,000,000)
Other	21,000,000	21,000,000
Net cash provided from operating activities	182,000,000	218,000,000
New Financing-
Long-term debt	247,000,000
Short-term borrowings, net	530,000,000	76,000,000
Redemptions and Repayments-
Long-term debt	(472,000,000)	(295,000,000)
Other	(11,000,000)	(1,000,000)
Net cash used for financing activities	294,000,000	(220,000,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(334,000,000)	(566,000,000)
Proceeds from asset sales		116,000,000
Sales of investment securities held in trusts	513,000,000	957,000,000
Purchases of investment securities held in trusts	(545,000,000)	(979,000,000)
Customer acquisition costs	(2,000,000)	(105,000,000)
Leasehold improvement payments to (from) associated companies		(51,000,000)
Loans to associated companies, net	(93,000,000)	631,000,000
Other	(18,000,000)	(1,000,000)
Net cash provided from (used for) investing activities	(479,000,000)	2,000,000
Net change in cash and cash equivalents	(3,000,000)	0
Cash and cash equivalents at beginning of period	9,000,000	0
Cash and cash equivalents at end of period	6,000,000	0
OE
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	68,765,000	73,484,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	44,346,000	43,894,000
Amortization of regulatory assets, net	3,179,000	38,769,000
Deferred income taxes and investment tax credits, net	62,216,000	4,964,000
Accrued compensation and retirement benefits	(8,328,000)	(16,154,000)
Purchased power cost recovery reconciliation	(8,584,000)	(1,514,000)
Amortization of lease costs	(4,696,000)	(4,619,000)
Accrued regulatory obligations	(3,309,000)	(2,309,000)
Pension trust contribution	(27,000,000)
Cash from (to) suppliers, net	(850,000)	1,215,000
Decrease (increase) in operating assets-
Receivables	80,968,000	49,250,000
Prepayments and other current assets	(28,947,000)	5,072,000
Increase (decrease) in operating liabilities-
Accounts payable	(22,253,000)	(57,208,000)
Accrued taxes	(9,360,000)	(25,685,000)
Other	4,261,000	(114,000)
Net cash provided from operating activities	150,408,000	109,045,000
Redemptions and Repayments-
Long-term debt	(707,000)	(2,957,000)
Short-term borrowings, net	(142,270,000)	(93,017,000)
Common stock dividend payments	(268,000,000)	(250,000,000)
Other	(2,340,000)	(881,000)
Net cash used for financing activities	(413,317,000)	(346,855,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(78,894,000)	(71,698,000)
Sales of investment securities held in trusts	19,595,000	59,804,000
Purchases of investment securities held in trusts	(25,547,000)	(64,063,000)
Leasehold improvement payments to (from) associated companies		18,375,000
Cash investments	11,962,000	11,774,000
Loans to associated companies, net	(78,927,000)	12,420,000
Other	(5,593,000)	(1,298,000)
Net cash provided from (used for) investing activities	(157,404,000)	(34,686,000)
Net change in cash and cash equivalents	(420,313,000)	(272,496,000)
Cash and cash equivalents at beginning of period	420,489,000	324,175,000
Cash and cash equivalents at end of period	176,000	51,679,000
CEI
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	35,050,000	35,918,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	36,914,000	36,447,000
Amortization of regulatory assets, net	41,536,000	75,946,000
Deferred income taxes and investment tax credits, net	17,221,000	(18,083,000)
Accrued compensation and retirement benefits	5,421,000	5,421,000
Accrued regulatory obligations	(2,001,000)	(444,000)
Pension trust contribution	(35,000,000)
Cash from (to) suppliers, net		685,000
Decrease (increase) in operating assets-
Receivables	140,455,000	51,757,000
Prepayments and other current assets	(17,469,000)	5,392,000
Increase (decrease) in operating liabilities-
Accounts payable	10,135,000	(34,488,000)
Accrued taxes	(346,000)	(11,317,000)
Other	(4,436,000)	2,023,000
Net cash provided from operating activities	227,480,000	149,257,000
Redemptions and Repayments-
Long-term debt	(74,000)	(54,000)
Short-term borrowings, net	(104,228,000)	(136,013,000)
Common stock dividend payments	(64,000,000)	(100,000,000)
Other	(5,239,000)	(3,367,000)
Net cash used for financing activities	(173,541,000)	(239,434,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(52,743,000)	(44,373,000)
Redemptions of lessor notes	53,283,000	48,608,000
Loans to associated companies, net	(48,676,000)	2,322,000
Other	(5,797,000)	(2,365,000)
Net cash provided from (used for) investing activities	(53,933,000)	4,192,000
Net change in cash and cash equivalents	6,000	(85,985,000)
Cash and cash equivalents at beginning of period	238,000	86,230,000
Cash and cash equivalents at end of period	244,000	245,000
TE
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	17,408,000	14,725,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	15,890,000	15,963,000
Amortization of regulatory assets, net	(18,532,000)	(10,299,000)
Deferred income taxes and investment tax credits, net	41,457,000	16,503,000
Deferred rents and lease market valuation liability	(43,851,000)	(42,264,000)
Accrued compensation and retirement benefits	1,085,000	2,600,000
Accrued regulatory obligations	(1,193,000)	(632,000)
Pension trust contribution	(45,000,000)
Cash from (to) suppliers, net	(14,000)	343,000
Decrease (increase) in operating assets-
Receivables	(48,807,000)	52,754,000
Prepayments and other current assets	(9,758,000)	3,608,000
Increase (decrease) in operating liabilities-
Accounts payable	3,661,000	(61,195,000)
Accrued taxes	(701,000)	(4,007,000)
Other	5,771,000	(8,960,000)
Net cash provided from operating activities	(82,584,000)	(20,861,000)
Redemptions and Repayments-
Long-term debt	(105,000)	(111,000)
Short-term borrowings, net		(225,975,000)
Common stock dividend payments	(34,000,000)	(130,000,000)
Other	(1,742,000)	(112,000)
Net cash used for financing activities	(35,847,000)	(356,198,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(17,386,000)	(20,237,000)
Sales of investment securities held in trusts	28,401,000	106,814,000
Redemptions of lessor notes	21,739,000	20,485,000
Purchases of investment securities held in trusts	(30,050,000)	(107,978,000)
Leasehold improvement payments from associated companies		32,829,000
Loans to associated companies, net	(32,050,000)	(10,818,000)
Other	(1,473,000)	(2,905,000)
Net cash provided from (used for) investing activities	(30,819,000)	18,190,000
Net change in cash and cash equivalents	(149,250,000)	(358,869,000)
Cash and cash equivalents at beginning of period	149,262,000	436,712,000
Cash and cash equivalents at end of period	12,000	77,843,000
JCP&L
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	61,314,000	79,119,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	52,087,000	55,064,000
Amortization of regulatory assets, net	121,633,000	150,774,000
Deferred purchased power and other costs	(70,998,000)	(67,664,000)
Deferred income taxes and investment tax credits, net	51,222,000	(1,425,000)
Accrued compensation and retirement benefits	1,319,000	2,608,000
Pension trust contribution	(105,000,000)
Cash from (to) suppliers, net	(235,000)	(23,400,000)
Decrease (increase) in operating assets-
Receivables	58,466,000	(46,788,000)
Prepayments and other current assets	(124,790,000)	(111,968,000)
Increase (decrease) in operating liabilities-
Accounts payable	13,856,000	11,924,000
Accrued taxes	(1,167,000)	10,368,000
Other	612,000	(6,446,000)
Net cash provided from operating activities	58,319,000	52,166,000
New Financing-
Short-term borrowings, net	410,917,000	57,850,000
Redemptions and Repayments-
Long-term debt	(14,671,000)	(13,830,000)
Common stock dividend payments		(90,000,000)
Equity payment to parent	(500,000,000)
Other	(1,452,000)
Net cash used for financing activities	(105,206,000)	(45,980,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(98,153,000)	(80,727,000)
Sales of investment securities held in trusts	375,885,000	281,242,000
Purchases of investment securities held in trusts	(385,448,000)	(289,454,000)
Loans to associated companies, net	160,940,000	85,049,000
Other	(6,299,000)	(2,224,000)
Net cash provided from (used for) investing activities	46,925,000	(6,114,000)
Net change in cash and cash equivalents	38,000	72,000
Cash and cash equivalents at beginning of period	4,000	27,000
Cash and cash equivalents at end of period	42,000	99,000
Met-Ed
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	39,365,000	29,424,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	25,189,000	26,198,000
Amortization of regulatory assets, net	54,261,000	97,389,000
Deferred costs recoverable as regulatory assets	(41,699,000)	(38,358,000)
Deferred income taxes and investment tax credits, net	11,972,000	(12,079,000)
Accrued compensation and retirement benefits	(510,000)	(1,573,000)
Pension trust contribution	(35,000,000)
Cash from (to) suppliers, net	174,000	50,000
Decrease (increase) in operating assets-
Receivables	46,240,000	(29,439,000)
Prepayments and other current assets	(26,740,000)	(31,246,000)
Increase (decrease) in operating liabilities-
Accounts payable	5,148,000	733,000
Accrued taxes	(47,676,000)	9,519,000
Accrued interest	(103,000)	(1,277,000)
Other	10,903,000	7,553,000
Net cash provided from operating activities	41,524,000	56,894,000
New Financing-
Short-term borrowings, net	164,320,000	17,898,000
Redemptions and Repayments-
Common stock	(150,000,000)
Long-term debt	(14,784,000)	(100,000,000)
Common stock dividend payments	(80,000,000)
Equity payment to parent	(150,000,000)
Net cash used for financing activities	(230,464,000)	(82,102,000)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(46,647,000)	(54,405,000)
Sales of investment securities held in trusts	501,260,000	376,610,000
Purchases of investment securities held in trusts	(506,220,000)	(381,219,000)
Loans to associated companies, net	596,000	85,943,000
Other	(3,112,000)	(1,715,000)
Net cash provided from (used for) investing activities	(54,123,000)	25,214,000
Net change in cash and cash equivalents	(243,063,000)	6,000
Cash and cash equivalents at beginning of period	243,220,000	120,000
Cash and cash equivalents at end of period	157,000	126,000
Penelec
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	32,024,000	30,273,000
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	30,343,000	31,287,000
Amortization of regulatory assets, net	25,615,000	(20,488,000)
Deferred costs recoverable as regulatory assets	(38,291,000)	(38,955,000)
Deferred income taxes and investment tax credits, net	46,687,000	42,943,000
Accrued compensation and retirement benefits	4,733,000	4,216,000
Cash from (to) suppliers, net	(1,276,000)	(3,613,000)
Decrease (increase) in operating assets-
Receivables	19,561,000	3,266,000
Prepayments and other current assets	(12,346,000)	(37,504,000)
Increase (decrease) in operating liabilities-
Accounts payable	23,449,000	(4,603,000)
Accrued taxes	(12,373,000)	(1,339,000)
Other	13,153,000	10,227,000
Net cash provided from operating activities	131,279,000	15,710,000
New Financing-
Long-term debt	25,000,000
Short-term borrowings, net	58,564,000	25,313,000
Redemptions and Repayments-
Long-term debt	(25,000,000)
Common stock dividend payments	(70,000,000)
Other	(1,353,000)	5,000
Net cash used for financing activities	(12,789,000)	25,318,000
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(64,177,000)	(58,293,000)
Sales of investment securities held in trusts	265,223,000	133,934,000
Purchases of investment securities held in trusts	(314,738,000)	(113,067,000)
Loans to associated companies, net	906,000	498,000
Other	(5,707,000)	(4,104,000)
Net cash provided from (used for) investing activities	(118,493,000)	(41,032,000)
Net change in cash and cash equivalents	(3,000)	(4,000)
Cash and cash equivalents at beginning of period	5,000	14,000
Cash and cash equivalents at end of period	$ 2,000	$ 10,000

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Commitments, Guarantees and Contingencies

6 Months Ended

Jun. 30, 2011

Commitments, Guarantees and Contingencies [Abstract]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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 June 30, 2011, outstanding guarantees and other assurances aggregated approximately $3.8 billion, consisting of parental guarantees ($0.8 billion), subsidiaries’ guarantees ($2.6 billion), and surety bonds and LOCs ($0.4 billion).

FirstEnergy guarantees energy and energy-related payments of its subsidiaries involved in energy commodity activities principally to facilitate or hedge normal physical transactions involving electricity, gas, emission allowances and coal. FirstEnergy also provides guarantees to various providers of credit support for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements legally obligate FirstEnergy to fulfill the obligations of those subsidiaries directly involved in energy and energy-related transactions or financing where the law might otherwise limit the counterparties’ claims. If demands of a counterparty were to exceed the ability of a subsidiary to satisfy existing obligations, FirstEnergy’s guarantee enables the counterparty’s legal claim to be satisfied by other FirstEnergy assets. FirstEnergy believes the likelihood is remote that such parental guarantees of $0.2 billion (included in the $0.8 billion discussed above) as of June 30, 2011 would increase amounts otherwise payable by FirstEnergy to meet its obligations incurred in connection with financings and ongoing energy and energy-related activities.

While these types of guarantees are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a credit rating downgrade or “material adverse event,” the immediate posting of cash collateral, provision of an LOC or accelerated payments may be required of the subsidiary. As of June 30, 2011, FirstEnergy’s maximum exposure under these collateral provisions was $625 million, consisting of $522 million due to a below investment grade credit rating (of which $265 million is due to an acceleration of payment or funding obligation) and $103 million due to “material adverse event” contractual clauses. 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 $666 million.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $136 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, contracts entered into by the Competitive Energy Services segment, including power contracts with affiliates awarded through competitive bidding processes, typically contain margining provisions that require the posting of cash or LOCs in amounts determined by future power price movements. Based on FES’ and AE Supply’s power portfolios as of June 30, 2011 and forward prices as of that date, FES and AE Supply have posted collateral of $138 million and $2 million, respectively. Under a hypothetical adverse change in forward prices (95% confidence level change in forward prices over a one-year time horizon), FES would be required to post an additional $17 million of collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required to be posted.

FES’ debt obligations are generally guaranteed by its subsidiaries, FGCO and NGC, and FES guarantees the debt obligations of each of FGCO and NGC. Accordingly, present and future holders of indebtedness of FES, FGCO and NGC would have claims against each of FES, FGCO and NGC, regardless of whether their primary obligor is FES, FGCO or NGC.

Signal Peak and Global Rail are borrowers under a $350 million syndicated two-year senior secured term loan facility due in October 2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that share ownership in the borrowers with FEV, have provided a guaranty of the borrowers’ obligations under the facility. In addition, FEV and the other entities that directly own the equity interest in the borrowers have pledged those interests to the lenders under the term loan facility as collateral for the facility.

(B) ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Compliance with environmental regulations could have a material adverse effect on FirstEnergy’s earnings and competitive position to the extent that FirstEnergy 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.

CAA Compliance

FirstEnergy is required to meet federally-approved SO₂ and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂ and NOx reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, combustion controls and post-combustion controls, generating more electricity from lower-emitting plants and/or using emission allowances. Violations can result in the shutdown of the generating unit involved and/or civil or criminal penalties.

In July 2008, three complaints were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on coal-fired Bruce Mansfield Plant air emissions. Two of these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner,” one being a complaint filed on behalf of twenty-one individuals and the other being a class action complaint seeking certification as a class action with the eight named plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these three complaints.

The states of New Jersey and Connecticut filed CAA citizen suits in 2007 alleging NSR violations at the Portland Generation Station against GenOn Energy, Inc. (formerly RRI Energy, Inc. and the current owner and operator), Sithe Energy (the purchaser of the Portland Station from Met-Ed in 1999) and Met-Ed. Specifically, these suits allege that “modifications” at Portland Units 1 and 2 occurred between 1980 and 2005 without preconstruction NSR permitting in violation of the CAA’s PSD program, and seek injunctive relief, penalties, attorney fees and mitigation of the harm caused by excess emissions. In September 2009, 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. The parties dispute the scope of Met-Ed’s indemnity obligation to and from Sithe Energy, and Met-Ed is unable to predict the outcome of this matter.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the Portland coal-fired plant based on “modifications” dating back to 1986. On March 31, 2011, the EPA proposed emissions limits and compliance schedules to reduce SO2 air emissions by approximately 81% at the Portland Plant based on an interstate pollution transport petition submitted by New Jersey under Section 126 of the CAA. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. Met-Ed, JCP&L, as the former owner of 16.67% of Keystone, and Penelec, as former owner and operator of Shawville, are unable to predict the outcome of this matter.

In June 2008, the EPA issued a Notice and Finding of Violation to Mission Energy Westside, Inc. (Mission) alleging that “modifications” at the coal-fired Homer City Plant occurred from 1988 to the present without preconstruction NSR permitting in violation of the CAA’s PSD program. In May 2010, the EPA issued a second NOV to Mission, Penelec, New York State Electric & Gas Corporation and others that have had an ownership interest in Homer City containing in all material respects allegations identical to those included in the June 2008 NOV. In January 2011, the DOJ filed a complaint against Penelec in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against Penelec based on alleged “modifications” at Homer City between 1991 to 1994 without preconstruction NSR permitting in violation of the CAA’s PSD and Title V permitting programs. The complaint was also filed against the former co-owner, New York State Electric and Gas Corporation, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. In January 2011, another complaint was filed against Penelec and the other entities described above in the U.S. District Court for the Western District of Pennsylvania seeking damages based on Homer City’s air emissions as well as certification as a class action and to enjoin Homer City from operating except in a “safe, responsible, prudent and proper manner.” Penelec believes the claims are without merit and intends to defend itself against the allegations made in the complaint, but, at this time, is unable to predict the outcome of this matter. In addition, the Commonwealth of Pennsylvania and the States of New Jersey and New York intervened and have filed separate complaints regarding Homer City seeking injunctive relief and civil penalties. Mission is seeking indemnification from Penelec, the co-owner and operator of Homer City prior to its sale in 1999. On April 21, 2011, Penelec and all other defendants filed Motions to Dismiss all of the federal claims and the various state claims. Responsive and Reply briefs were filed on May 26, 2011 and June 17, 2011, respectively. The scope of Penelec’s indemnity obligation to and from Mission is under dispute and Penelec is unable to predict the outcome of this matter.

In August 2009, the EPA issued a Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, including the PSD, NNSR and Title V regulations at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired 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. FGCO received a request for certain operating and maintenance information and planning information for these same generating plants and notification that the EPA is evaluating whether certain maintenance at the Eastlake Plant may constitute a major modification under the NSR provision of the CAA. Later in 2009, FGCO also received another information request regarding emission projections for Eastlake Plant. In June 2011, EPA issued another Finding of Violation and NOV alleging violations of the CAA and Ohio regulations, specifically opacity limitations and requirements to continuously operate opacity monitoring systems at the Eastlake, Lakeshore, Bay Shore and Ashtabula coal-fired plants. Also, in June 2011, FirstEnergy received an information request pursuant to section 114(a) of the CAA for certain operating maintenance and planning information, among other information regarding these plants. FGCO intends to comply with the CAA, including the EPA’s information requests but, at this time, is unable to predict the outcome of this matter.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA letter from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the following ten coal-fired plants, which collectively include 22 electric generation units Albright, Armstrong, Fort Martin, Harrison, Hatfield’s Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the CAA and related requirements, including potential application of the NSR standards under the CAA, which can require the installation of additional air emission control equipment when the major modification of an existing facility results in an increase in emissions. AE has provided responsive information to this and a subsequent request but is unable to predict the outcome of this matter.

In May 2004, AE, AE Supply, MP and WP received a Notice of Intent to Sue Pursuant to CAA §7604 from the Attorneys General of New York, New Jersey and Connecticut and from the PA DEP, alleging that Allegheny performed major modifications in violation of the PSD provisions of the CAA at the following West Virginia coal-fired plants: Albright Unit 3; Fort Martin Units 1 and 2; Harrison Units 1, 2 and 3; Pleasants Units 1 and 2 and Willow Island Unit 2. The Notice also alleged PSD violations at the Armstrong, Hatfield’s Ferry and Mitchell coal-fired plants in Pennsylvania and identifies PA DEP as the lead agency regarding those facilities. In September 2004, AE, AE Supply, MP and WP received a separate Notice of Intent to Sue from the Maryland Attorney General that essentially mirrored the previous Notice.

In June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply, MP, PE and WP in the United States District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the CAA and the Pennsylvania Air Pollution Control Act at the Hatfield’s Ferry, Armstrong and Mitchell Plants in Pennsylvania. On January 17, 2006, the PA DEP and the Attorneys General filed an amended complaint. A non-jury trial on liability only was held in September 2010. Plaintiffs filed their proposed findings of fact and conclusions of law in December 2010, Allegheny made its related filings in February 2011 and plaintiffs filed their responses in April 2011. The parties are awaiting a decision from the District Court, but there is no deadline for that decision.

In September 2007, Allegheny also received a NOV from the EPA alleging NSR and PSD violations under the CAA, as well as Pennsylvania and West Virginia state laws at the Hatfield’s Ferry and Armstrong Plants in Pennsylvania and the Fort Martin and Willow Island coal-fired plants in West Virginia.

FirstEnergy intends to vigorously defend against the CAA matters described above but cannot predict their outcomes.

State Air Quality Compliance

In early 2006, Maryland passed the Healthy Air Act, which imposes state-wide emission caps on SO₂ and NO_X, requires mercury emission reductions and mandates that Maryland join the RGGI and participate in that coalition’s regional efforts to reduce CO₂ emissions. On April 20, 2007, Maryland became the 10th state to join the RGGI. The Healthy Air Act provides a conditional exemption for the R. Paul Smith coal-fired plant for NO_X, SO₂ and mercury, based on a PJM declaration that the plant is vital to reliability in the Baltimore/Washington DC metropolitan area, which PJM determined in 2006. Pursuant to the legislation, the Maryland Department of the Environment (MDE) passed alternate NO_X and SO₂ limits for R. Paul Smith, which became effective in April 2009. However, R. Paul Smith is still required to meet the Healthy Air Act mercury reductions of 80% beginning in 2010. The statutory exemption does not extend to R. Paul Smith’s CO₂ emissions. Maryland issued final regulations to implement RGGI requirements in February 2008. Ten RGGI auctions have been held through the end of calendar year 2010. RGGI allowances are also readily available in the allowance markets, affording another mechanism by which to secure necessary allowances. On March 14, 2011, MDE requested PJM perform an analysis to determine if termination of operation at R. Paul Smith would adversely impact the reliability of electrical service in the PJM region under current system conditions. FirstEnergy is unable to predict the outcome of this matter.

In January 2010, the WVDEP issued a NOV for opacity emissions at Allegheny’s Pleasants coal-fired plant. FirstEnergy is discussing with WVDEP steps to resolve the NOV including installing a reagent injection system to reduce opacity.

National Ambient Air Quality Standards

The EPA’s CAIR requires reductions of NOx and SO₂ emissions in two phases (2009/2010 and 2015), ultimately capping SO2 emissions in affected states to 2.5 million tons annually and NOx emissions to 1.3 million tons annually. In 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated CAIR “in its entirety” and directed the EPA to “redo its analysis from the ground up.” In December 2008, the Court reconsidered its prior ruling and allowed CAIR to remain in effect to “temporarily preserve its environmental values” until the EPA replaces CAIR with a new rule consistent with the Court’s opinion. The Court 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. In July 2011, the EPA finalized the Cross-State Air Pollution Rule (CSAPR) to replace CAIR, which remains in effect until CSAPR becomes effective (60 days after publication in the Federal Register). CSAPR requires reductions of NOx and SO2 emissions in two phases (2012 and 2014), ultimately capping SO2 emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. FGCO’s future cost of compliance may be substantial and changes to FirstEnergy’s operations may result. Management is currently assessing the impact of CSAPR, other environmental proposals and other factors on FirstEnergy’s competitive fossil generating facilities, including but not limited to, the impact on value of our emissions allowances (currently reflected at $38 million on our Consolidated Balance Sheet as of June 30, 2011) and the operations of its coal-fired plants.

Hazardous Air Pollutant Emissions

On March 16, 2011, the EPA released its MACT proposal to establish emission standards for mercury, hydrochloric acid and various metals for electric generating units. Depending on the action taken by the EPA and how any future regulations are ultimately implemented, FirstEnergy’s future cost of compliance with MACT regulations may be substantial and changes to FirstEnergy’s operations may result.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the federal, state and international level. 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, in June 2009. The Senate continues to consider a number of measures to regulate GHG emissions. President Obama has announced his Administration’s “New Energy for America Plan” that includes, among other provisions, proposals to ensure that 10% of electricity used in the United States comes from renewable sources by 2012, to increase to 25% by 2025, to implement an economy-wide cap-and-trade program to reduce GHG emissions by 80% by 2050. Certain states, primarily the northeastern states participating in the RGGI and western states, led by California, have coordinated efforts to develop regional strategies to control emissions of certain GHGs.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required FirstEnergy to measure GHG emissions commencing in 2010 and will require it to submit reports commencing in 2011. In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act.” The EPA’s finding concludes that concentrations of several key GHGs increase the threat of climate change and may be regulated as “air pollutants” under the CAA. In April 2010, the EPA finalized new GHG standards for model years 2012 to 2016 passenger cars, light-duty trucks and medium-duty passenger vehicles and clarified that GHG regulation under the CAA would not be triggered for electric generating plants and other stationary sources until January 2, 2011, at the earliest. In May 2010, the EPA finalized new thresholds for GHG emissions that define when permits under the CAA’s NSR program would be required. The EPA established an emissions applicability threshold of 75,000 tons per year (tpy) of carbon dioxide equivalents (CO2) effective January 2, 2011 for existing facilities under the CAA’s PSD program. Until July 1, 2011, this emissions applicability threshold will only apply if PSD is triggered by non-CO₂ pollutants.

At the international level, the Kyoto Protocol, signed by the U.S. in 1998 but never submitted for ratification by the U.S. Senate, was intended to address global warming by reducing the amount of man-made GHG, including CO₂, emitted by developed countries by 2012. A December 2009 U.N. Climate Change Conference in Copenhagen did not reach a consensus on a successor treaty to the Kyoto Protocol, but did take note of the Copenhagen Accord, a non-binding political agreement that recognized the scientific view that the increase in global temperature should be below two degrees Celsius; includes a commitment by developed countries to provide funds, approaching $30 billion over the next three years with a goal of increasing to $100 billion by 2020; and establishes the “Copenhagen Green Climate Fund” to support mitigation, adaptation, and other climate-related activities in developing countries. To the extent that they have become a party to the Copenhagen Accord, developed economies, such as the European Union, Japan, Russia and the United States, would commit to quantified economy-wide emissions targets from 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.

In 2009, the U.S. Court of Appeals for the Second Circuit and 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. However, a subsequent ruling from the U.S. Court of Appeals for the Fifth Circuit reinstated the lower court dismissal of a complaint alleging damage from GHG emissions. These cases involve common law tort claims, including public and private nuisance, alleging that GHG emissions contribute to global warming and result in property damages. The U.S. Supreme Court granted a writ of certiorari to review the decision of the Second Circuit. On June 20, 2011, the U. S. Supreme Court reversed the Second Circuit. The Court remanded to the Second Circuit the issue of whether the CAA preempted state common law nuisance actions. The Court’s ruling also failed to answer the question of the extent to which actions for damages may remain viable. While FirstEnergy is not a party to this litigation, in June 2011, FirstEnergy received notice of a complaint alleging that the GHG emissions of 87 companies, including FirstEnergy, render them liable for damages to certain residents of Mississippi stemming from Hurricane Katrina. On July 27, 2011, the plaintiff voluntarily dismissed FirstEnergy from this complaint.

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 of its 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, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy’s operations.

In 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 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). In 2007, the Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position 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. In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit’s opinion and decided that Section 316(b) of the Clean Water Act authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures. On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the Clean Water Act generally requiring fish impingement to be reduced to a 12% annual average and studies to be conducted at the majority of our existing generating facilities to assist permitting authorities to determine whether and what site-specific controls, if any, would be required to reduce entrainment of aquatic life. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by 30 days but stated its schedule for issuing a final rule remains July 27, 2012. FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant’s water intake channel to divert fish away from the plant’s water intake system. In November 2010, the Ohio EPA issued a permit for the coal-fired Bay Shore Plant requiring installation of reverse louvers in its entire water intake channel by December 31, 2014. Depending on the results of such studies and the EPA’s further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

In April 2011, the U.S. Attorney’s Office in Cleveland, Ohio advised FGCO that it is no longer 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. This matter has been referred back to EPA for civil enforcement and FGCO is unable to predict the outcome of this matter.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash disposal site at the Albright coal-fired plant seeking unspecified civil penalties and injunctive relief. MP is currently seeking relief from the arsenic limits through WVDEP agency review. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served another 60-Day Notice of Intent required prior to filing a citizen suit under the Clean Water Act for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Station.

FirstEnergy intends to vigorously defend against the CWA matters described above but cannot predict their outcomes.

Monongahela River Water Quality

In late 2008, the PA DEP imposed water quality criteria for certain effluents, including TDS and sulfate concentrations in the Monongahela River, on new and modified sources, including the scrubber project at the Hatfield’s Ferry coal-fired plant. These criteria are reflected in the current PA DEP water discharge permit for that project. AE Supply appealed the PA DEP’s permitting decision, which would require it to incur significant costs or negatively affect its ability to operate the scrubbers as designed. Preliminary studies indicate an initial capital investment in excess of $150 million in order to install technology to meet the TDS and sulfate limits in the permit. The permit has been independently appealed by Environmental Integrity Project and Citizens Coal Council, which seeks to impose more stringent technology-based effluent limitations. Those same parties have intervened in the appeal filed by AE Supply, and both appeals have been consolidated for discovery purposes. An order has been entered that stays the permit limits that AE Supply has challenged while the appeal is pending. The hearing is scheduled to begin in September 2011, however the Court stayed all prehearing deadlines on July 15, 2011 to allow the parties additional time to work out a settlement. AE Supply intends to vigorously pursue these issues, but cannot predict the outcome of these appeals.

In a parallel rulemaking, the PA DEP recommended, and in August 2010, the Pennsylvania Environmental Quality Board issued, a final rule imposing end-of-pipe TDS effluent limitations. FirstEnergy could incur significant costs for additional control equipment to meet the requirements of this rule, although its provisions do not apply to electric generating units until the end of 2018, and then only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its Clean Water Act 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately 68 mile stretch of the Monongahela River north of the West Virginia border. In May 2011, the EPA agreed with PA DEP’s recommended sulfate impairment designation. PA DEP’s goal is to submit a final water quality standards regulation, incorporating the sulfate impairment designation for EPA approval by May, 2013. PA DEP will then need to develop a TMDL limit for the river, a process that will take approximately five years. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from its Hatfield’s Ferry and Mitchell facilities in Pennsylvania and its Fort Martin facility in West Virginia.

In October 2009, the WVDEP issued the water discharge permit for the Fort Martin generation facility. Similar to the Hatfield’s Ferry water discharge permit issued for the scrubber project, the Fort Martin permit imposes effluent limitations for TDS and sulfate concentrations. The permit also imposes temperature limitations and other effluent limits for heavy metals that are not contained in the Hatfield’s Ferry water permit. Concurrent with the issuance of the Fort Martin permit, WVDEP also issued an administrative order that sets deadlines for MP to meet certain of the effluent limits that are effective immediately under the terms of the permit. MP appealed the Fort Martin permit and the administrative order. The appeal included a request to stay certain of the conditions of the permit and order while the appeal is pending, which was granted pending a final decision on appeal and subject to WVDEP moving to dissolve the stay. The appeals have been consolidated. MP moved to dismiss certain of the permit conditions for the failure of the WVDEP to submit those conditions for public review and comment during the permitting process. An agreed-upon order that suspends further action on this appeal, pending WVDEP’s release for public review and comment on those conditions, was entered on August 11, 2010. The stay remains in effect during that process. The current terms of the Fort Martin permit would require MP to incur significant costs or negatively affect operations at Fort Martin. Preliminary information indicates an initial capital investment in excess of the capital investment that may be needed at Hatfield’s Ferry in order to install technology to meet the TDS and sulfate limits in the Fort Martin permit, which technology may also meet certain of the other effluent limits in the permit. Additional technology may be needed to meet certain other limits in the permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals.

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act of 1976. Certain fossil-fuel combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation. In February 2009, the EPA requested comments from the states on options for regulating coal combustion residuals, including whether they should be regulated as hazardous or non-hazardous waste.

In December 2009, in an advanced notice of public rulemaking, the EPA asserted that the large volumes of coal combustion residuals produced by electric utilities pose significant financial risk to the industry. In May 2010, the EPA proposed two options for additional regulation of coal combustion residuals, including the option of regulation as a special waste under the EPA’s hazardous waste management program which could have a significant impact on the management, beneficial use and disposal of coal combustion residuals. FirstEnergy’s future cost of compliance with any coal combustion residuals regulations that may be promulgated could be substantial and would depend, in part, on the regulatory action taken by the EPA and implementation by the EPA or the states.

The Little Blue Run (LBR) Coal Combustion By-products (CCB) impoundment is expected to run out of disposal capacity for disposal of CCBs from the Bruce Mansfield Plant between 2016 and 2018. In July 2011, BMP submitted a Phase I permit application to PA DEP for construction of a new dry CCB disposal facility adjacent to LBR. BMP anticipates submitting zoning applications for approval to allow construction of a new dry CCB disposal facility prior to commencing construction.

The Utility Registrants 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 June 30, 2011, based on estimates of the total costs of cleanup, the Utility Registrants’ proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $133 million (JCP&L — $69 million, TE — $1 million, CEI — $1 million, FGCO — $1 million and FirstEnergy — $61 million) have been accrued through June 30, 2011. Included in the total are accrued liabilities of approximately $63 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. On July 11, 2011, FirstEnergy was found to be a potentially responsible party under CERCLA indirectly liable for a portion of past and future clean-up costs at certain legacy MGP sites, estimated to total approximately $59 million. FirstEnergy recognized additional expense of $29 million during the second quarter of 2011; $30 million had previously been reserved prior to 2011.

(C) OTHER LEGAL PROCEEDINGS

Power Outages and Related Litigation

In July 1999, the Mid-Atlantic States experienced a severe heat wave, which resulted in power outages throughout the service territories of many electric utilities, including JCP&L. 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. On July 29, 2010, the Appellate Division upheld the trial court’s decision decertifying the class. Plaintiffs have filed, and JCP&L has opposed, a motion for leave to appeal to the New Jersey Supreme Court. In November 2010, the Supreme Court issued an order denying Plaintiffs’ motion. The Court’s order effectively ends the class action attempt, and leaves only nine (9) plaintiffs to pursue their respective individual claims. The remaining individual plaintiffs have yet to take any affirmative steps to pursue their individual claims.

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities. As of June 30, 2011, FirstEnergy had approximately $2 billion invested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2. As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantee, as appropriate. The values of FirstEnergy’s NDT fluctuate based on market conditions. If the value of the trusts decline by a material amount, FirstEnergy’s obligation to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDT. The NRC issued guidance anticipating an increase in low-level radioactive waste disposal costs associated with the decommissioning of nuclear facilities. On March 28, 2011, FENOC submitted its biennial report on nuclear decommissioning funding to the NRC. This submittal identified a total shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry of approximately $92.5 million. On June 24, 2011, FENOC submitted a $95 million parental guarantee to the NRC for its approval.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse Nuclear Power Station operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC Atomic Safety and Licensing Board (ASLB) granted a hearing on the Davis-Besse license renewal application to a group of petitioners. By this order, the ASLB also admitted two contentions challenging whether FENOC’s Environmental Report adequately evaluated (1) a combination of renewable energy sources as alternatives to the renewal of Davis-Besse’s operating license, and (2) severe accident mitigation alternatives at Davis-Besse. On May 6, 2011, FENOC filed an appeal with the NRC Commissioners from the order granting a hearing on the Davis-Besse license renewal application.

On April 14, 2011, a group of environmental organizations petitioned the NRC Commissioners to suspend certain pending nuclear licensing proceedings, including the Davis-Besse license renewal proceeding, to ensure that any safety and environmental implications of the accident at the Fukushima Daiichi Nuclear Power Station in Japan are considered. By May 2, 2011, the NRC Staff, FENOC and much of the nuclear industry filed responses opposing the petition. On May 6, 2011, petitioners filed a supplemental reply.

In January 2004, subsidiaries of FirstEnergy filed a lawsuit in the U.S. Court of Federal Claims seeking damages in connection with costs incurred at the Beaver Valley, Davis-Besse and Perry Nuclear facilities as a result of the DOE failure to begin accepting spent nuclear fuel on January 31, 1998. DOE was required to so commence accepting spent nuclear fuel by the Nuclear Waste Policy Act (42 USC 10101 et seq) and the contracts entered into by the DOE and the owners and operators of these facilities pursuant to the Act. On January 18, 2011, the parties, FirstEnergy and DOJ, filed a joint status report that established a schedule for the litigation of these claims. FirstEnergy filed damages schedules and disclosures with the DOJ on February 11, 2011, seeking approximately $57 million in damages for delay costs incurred through September 30, 2010. The damage claim is subject to review and audit by DOE.

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against International Coal Group, Inc. (ICG), Anker West Virginia Mining Company, Inc. (Anker WV), and Anker Coal Group, Inc. (Anker Coal). Anker WV entered into a long term Coal Sales Agreement with AE Supply and MP for the supply of coal to the Harrison generating facility. Prior to the time of trial, ICG was dismissed as a defendant by the Court, which issue can be the subject of a future appeal. As a result of defendants’ past and continued failure to supply the contracted coal, AE Supply and MP have incurred and will continue to incur significant additional costs for purchasing replacement coal. A non-jury trial was held from January 10, 2011 through February 1, 2011. At trial, AE Supply and MP presented evidence that they have incurred in excess of $80 million in damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of $150 million for future shortfalls. Defendants primarily claim that their performance is excused under a force majeure clause in the coal sales agreement and presented evidence at trial that they will continue to not provide the contracted yearly tonnage amounts. On May 2, 2011, the court entered a verdict in favor of AE Supply and MP for $104 million ($90 million in future damages and $14 million for replacement coal / interest). Post-trial filings occurred in May 2011, with Oral Argument on June 28, 2011. The parties expect a ruling sometime in the third quarter, at which time the judgment will be final. The parties have 30 days to appeal the final judgment. AE Supply and MP intend to vigorously pursue this matter through appeal if necessary but cannot predict its outcome.

Other Legal Matters

In February 2010, a class action lawsuit was filed in Geauga County Court of Common Pleas against FirstEnergy, CEI and OE seeking declaratory judgment and injunctive relief, as well as compensatory, incidental and consequential damages, on behalf of a class of customers related to the reduction of a discount that had previously been in place for residential customers with electric heating, electric water heating, or load management systems. The reduction in the discount was approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction of the court of common pleas. The court granted the motion to dismiss on September 7, 2010. The plaintiffs appealed the decision to the Court of Appeals of Ohio, which has not yet rendered an opinion.

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.

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.

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Pension and Other Postretirement Benefits (Details) (USD $) In Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Pension Benefit Cost (Credit)
Components of Net Periodic Benefit Costs
Service cost	$ 34	$ 25	$ 62	$ 49
Interest cost	97	79	181	157
Expected return on plan assets	(115)	(90)	(216)	(181)
Amortization of prior service cost	4	3	7	6
Recognized net actuarial loss	48	47	97	94
Curtailments			(2)
Special Termination Benefits			9
Net periodic cost	68	64	138	125
Other Postretirement Benefit Cost (Credit)
Components of Net Periodic Benefit Costs
Service cost	3	3	7	5
Interest cost	12	11	23	22
Expected return on plan assets	(10)	(9)	(20)	(18)
Amortization of prior service cost	(52)	(48)	(100)	(96)
Recognized net actuarial loss	14	15	28	30
Net periodic cost	$ (33)	$ (28)	$ (62)	$ (57)

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Variable Interest Entities (Details Textuals) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Jun. 30, 2011	Jun. 30, 2010
Variable Interest Entity [Line Items]
Purchased power	$ 1,220,000,000	$ 1,063,000,000	$ 2,406,000,000	$ 2,301,000,000
Number of contracts that may contain variable interest	4
Variable Interest Entities (Textuals) [Abstract]
Income (loss) attributable to noncontrolling interest	(10,000,000)	(9,000,000)	(15,000,000)	(15,000,000)
Distributions to owners			(4,000,000)
Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments			1,600,000,000
Equity or debt invested in variable interest entities	0		0
JCP&L | Power Purchase Agreements
Variable Interest Entity [Line Items]
Purchased power	55,000,000	53,000,000	120,000,000	117,000,000
Power Purchase Agreements
Variable Interest Entity [Line Items]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities			23
Power Purchase Agreements | PE
Variable Interest Entity [Line Items]
Purchased power	47,000,000		58,000,000
Power Purchase Agreements | WP
Variable Interest Entity [Line Items]
Purchased power	21,000,000		26,000,000
Reserve for adverse purchase power commitment	59,000,000		59,000,000
Current liability included in adverse purchase power commitment	11,000,000		11,000,000
Oyster Creek Nuclear Generating Station
Variable Interest Entity [Line Items]
Bondable stranded costs	295,000,000		295,000,000
Allegheny | PATH-WV
Variable Interest Entity [Line Items]
Maximum Exposure	27,000,000		27,000,000
PATH-WV
Variable Interest Entity [Line Items]
Percentage of high-voltage transmission line project owned by subsidiary of AE on the Allegheny Series	100.00%		100.00%
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series	50.00%		50.00%
JCP&L
Variable Interest Entity [Line Items]
Purchased power	$ 328,463,000	$ 410,470,000	$ 698,631,000	$ 824,486,000
Number of contracts that may contain variable interest			2

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Impairment of Long-Lived Assets (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended		3 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2010	Mar. 31, 2011 Fremont Energy Center	Mar. 11, 2011 Fremont Energy Center MWH	Jun. 30, 2011 Peaking Facilities	Jun. 30, 2011 Peaking Facilities
Impairment of Long-Lived Assets (Textuals) [Abstract]
Number of gas combined cycle combustion turbines sold				2
Number of steam turbine sold				1
Load following capacity				544
Peaking capacity				163
Asset impairments	$ 41	$ 21	$ 11		$ 7	$ 21

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Merger (Details) (USD $) In Millions, except Share data	Feb. 25, 2011	Feb. 24, 2011
Purchase price calculation
Shares of Allegheny common stock outstanding		170,000,000
Exchange ratio	0.667
Number of shares of FirstEnergy common stock issued	113,000,000
Closing price of FirstEnergy common stock		$ 38.16
Fair value of shares issued by FirstEnergy	$ 4,327
Fair value of replacement share-based compensation awards relating to pre-merger service	27
Total consideration transferred	4,354
Fair values of assets and liabilities acquired and related goodwill
Current assets	1,494
Property, plant and equipment	9,656
Investments	138
Goodwill	881
Other noncurrent assets	1,347
Current liabilities	(716)
Noncurrent liabilities	(3,452)
Long-term debt and other long-term obligations	(4,994)
Assets Acquired (Liabilities Assumed), Net, Total	$ 4,354

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Segment Information

6 Months Ended

Jun. 30, 2011

Segment Information [Abstract]

SEGMENT INFORMATION

13. SEGMENT INFORMATION

With the completion of the Allegheny merger in the first quarter of 2011, FirstEnergy reorganized its management structure, which resulted in changes to its operating segments to be consistent with the manner in which management views the business. The new structure supports the combined company’s primary operations — distribution, transmission, generation and the marketing and sale of its products. The external segment reporting is consistent with the internal financial reporting used by FirstEnergy’s chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. FirstEnergy now has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Prior to the change in composition of business segments, FirstEnergy’s business was comprised of two reportable operating segments. The Energy Delivery Services segment was comprised of FirstEnergy’s then eight existing utility operating companies that transmit and distribute electricity to customers and purchase power to serve their POLR and default service requirements. The Competitive Energy Services segment was comprised of FES, which supplies electric power to end-use customers through retail and wholesale arrangements. The “Other/Corporate” segment consisted of corporate items and other businesses that were below the quantifiable threshold for separate disclosure. Disclosures for FirstEnergy’s operating segments for 2010 have been reclassified to conform to the current presentation.

The changes in FirstEnergy’s reportable segments during 2011 consisted primarily of the following:

• Energy Delivery Services was renamed Regulated Distribution and the operations of MP, PE and WP, which were acquired as part of the merger with Allegheny, and certain regulatory asset recovery mechanisms formerly included in the “Other” segment, were placed into this segment.

• A new Regulated Independent Transmission segment was created consisting of ATSI, and the operations of TrAIL Company and FirstEnergy’s interest in PATH; TrAIL and PATH were acquired as part of the merger with Allegheny. The transmission assets and operations of JCP&L, Met-Ed, Penelec, MP, PE and WP remain within the Regulated Distribution segment.

• AE Supply, an operator of generation facilities that was acquired as part of the merger with Allegheny, was placed into the Competitive Energy Services segment.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately 6 million customers within 67,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also includes the transmission operations of JCP&L, Met-Ed, Penelec, WP, MP and PE and the regulated electric generation facilities in West Virginia and New Jersey which MP and JCP&L, respectively, own or contractually control.

The Regulated Distribution segment’s revenues are primarily derived from the delivery of electricity within FirstEnergy’s service areas, cost recovery of regulatory assets and the sale of electric generation service to retail customers who have not selected an alternative supplier (POLR, SOS or default service) in its Maryland, New Jersey, Ohio and Pennsylvania franchise areas. Its results reflect the commodity costs of securing electric generation from FES and AE Supply and from non-affiliated power suppliers and the deferral and amortization of certain fuel costs.

The Regulated Independent Transmission segment transmits electricity through transmission lines and its revenues are primarily derived from the formula rate recovery of costs and a return on investment for capital expenditures in connection with TrAIL, PATH and other projects and revenues from providing transmission services to electric energy providers, power marketers and receiving transmission-related revenues from operation of a portion of the FirstEnergy transmission system. Its results reflect the net PJM and MISO transmission expenses related to the delivery of the respective generation loads. On June 1, 2011, the ATSI transmission assets previously dedicated to MISO were integrated into the PJM market. All of FirstEnergy’s assets now reside in one RTO.

The Competitive Energy Services segment, through FES, supplies electric power to end-use customers through retail and wholesale arrangements, including associated company power sales to meet a portion of the POLR and default service requirements of FirstEnergy’s Ohio and Pennsylvania utility subsidiaries and competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Maryland, Michigan and New Jersey. FES purchases the entire output of the 18 generating facilities which it owns and operates through its FGCO subsidiary (fossil and hydroelectric generating facilities) and owns, through its NGC subsidiary, FirstEnergy’s nuclear generating facilities. FENOC, a separate subsidiary of FirstEnergy, operates and maintains NGC’s nuclear generating facilities as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements with non-affiliates, pursuant to full output, cost-of-service PSAs.

The Competitive Energy Services segment also includes Allegheny’s unregulated electric generation operations, including AE Supply and AE Supply’s interest in AGC. AE Supply owns, operates and controls the electric generation capacity of its 18 facilities. AGC owns and sells generation capacity to AE Supply and MP, which own approximately 59% and 41% of AGC, respectively. AGC’s sole asset is a 40% undivided interest in the Bath County, Virginia pumped-storage hydroelectric generation facility and its connecting transmission facilities. All of AGC’s revenues are derived from sales of its 1,109 MW share of generation capacity from the Bath County generation facility to AE Supply and MP.

This business segment controls approximately 20,000 MWs of capacity and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from affiliated and non-affiliated electric generation sales less the related costs of electricity generation, including purchased power and net transmission (including congestion) and ancillary costs charged by PJM and MISO (prior to June 1, 2011) to deliver energy to the segment’s customers.

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

Financial information for each of FirstEnergy’s reportable segments is presented in the table below, which includes financial results for Allegheny beginning February 25, 2011. FES and the Utilities do not have separate reportable operating segments.

Segment Financial Information

			Competitive		Regulated
	Regulated		Energy		Independent		Other/			Reconciling
Three Months Ended	Distribution		Services		Transmission		Corporate			Adjustments			Consolidated
	(In millions)
June 30, 2011
External revenues	$	2,485	$	1,495	$	105	$	(30	)	$	(7	)	$	4,048
Internal revenues		—		318		—		—			(306	)		12
Total revenues		2,485		1,813		105		(30	)		(313	)		4,060
Depreciation and amortization		240		107		18		7			—			372
Investment income (loss), net		27		15		—		1			(12	)		31
Net interest charges		145		67		11		21			1			245
Income taxes		108		7		18		(30	)		(2	)		101
Net income (loss)		184		12		31		(51	)		(5	)		171
Total assets		26,932		17,146		2,339		1,179			—			47,596
Total goodwill		5,551		905		—		—			—			6,456
Property additions		302		197		45		25			—			569
June 30, 2010
External revenues	$	2,314	$	795	$	59	$	(21	)	$	(8	)	$	3,139
Internal revenues		19		539		—		—			(558	)		—
Total revenues		2,333		1,334		59		(21	)		(566	)		3,139
Depreciation and amortization		264		71		13		3			—			351
Investment income (loss), net		28		13		—		—			(10	)		31
Net interest charges		124		33		5		9			(4	)		167
Income taxes		81		75		7		(12	)		(17	)		134
Net income (loss)		132		121		11		(20	)		12			256
Total assets		21,457		11,102		993		914			—			34,466
Total goodwill		5,551		24		—		—			—			5,575
Property additions		157		290		15		27			—			489
Six Months Ended
June 30, 2011
External revenues	$	4,753	$	2,736	$	172	$	(53	)	$	(16	)	$	7,592
Internal revenues		—		661		—		—			(617	)		44
Total revenues		4,753		3,397		172		(53	)		(633	)		7,636
Depreciation and amortization		485		195		31		13			—			724
Investment income (loss), net		52		21		—		1			(22	)		52
Net interest charges		276		122		20		40			—			458
Income taxes		164		10		25		(50	)		30			179
Net income (loss)		280		17		44		(86	)		(39	)		216
Total assets		26,932		17,146		2,339		1,179			—			47,596
Total goodwill		5,551		905		—		—			—			6,456
Property additions		479		411		72		56			—			1,018
June 30, 2010
External revenues	$	4,798	$	1,514	$	116	$	(43	)	$	(14	)	$	6,371
Internal revenues		19		1,213		—		—			(1,165	)		67
Total revenues		4,817		2,727		116		(43	)		(1,179	)		6,438
Depreciation and amortization		577		148		25		6			—			756
Investment income (loss), net		54		14		—		1			(22	)		47
Net interest charges		248		66		10		22			(7	)		339
Income taxes		143		117		14		(24	)		(5	)		245
Net income (loss)		235		190		23		(39	)		(4	)		405
Total assets		21,457		11,102		993		914			—			34,466
Total goodwill		5,551		24		—		—			—			5,575
Property additions		309		619		29		40			—			997

Reconciling adjustments primarily consist of elimination of intersegment transactions.

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Consolidated Statements of Income (Unaudited) (USD $) Share data in Millions, except Per Share data	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010
REVENUES:
Electric utilities	$ 2,590,000,000		$ 2,373,000,000		$ 4,925,000,000		$ 4,916,000,000
Unregulated businesses	1,470,000,000		766,000,000		2,711,000,000		1,522,000,000
Total revenues	4,060,000,000	[1]	3,139,000,000	[1]	7,636,000,000	[1]	6,438,000,000	[1]
EXPENSES:
Fuel	635,000,000		350,000,000		1,088,000,000		684,000,000
Purchased power	1,220,000,000		1,063,000,000		2,406,000,000		2,301,000,000
Other operating expenses	1,105,000,000		673,000,000		2,138,000,000		1,374,000,000
Provision for depreciation	282,000,000		190,000,000		502,000,000		383,000,000
Amortization of regulatory assets, net	90,000,000		161,000,000		222,000,000		373,000,000
General taxes	242,000,000		176,000,000		479,000,000		381,000,000
Total expenses	3,574,000,000		2,613,000,000		6,835,000,000		5,496,000,000
OPERATING INCOME	486,000,000		526,000,000		801,000,000		942,000,000
OTHER INCOME (EXPENSE):
Investment income	31,000,000		31,000,000		52,000,000		47,000,000
Interest expense	(265,000,000)		(207,000,000)		(496,000,000)		(420,000,000)
Capitalized interest	20,000,000		40,000,000		38,000,000		81,000,000
Total other expense	(214,000,000)		(136,000,000)		(406,000,000)		(292,000,000)
INCOME BEFORE INCOME TAXES	272,000,000		390,000,000		395,000,000		650,000,000
INCOME TAXES	101,000,000		134,000,000		179,000,000		245,000,000
NET INCOME	171,000,000		256,000,000		216,000,000		405,000,000
Income (loss) attributable to noncontrolling interest	(10,000,000)		(9,000,000)		(15,000,000)		(15,000,000)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	181,000,000		265,000,000		231,000,000		420,000,000
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$ 0.43		$ 0.87		$ 0.61		$ 1.38
Diluted	$ 0.43		$ 0.87		$ 0.61		$ 1.37
AVERAGE SHARES OUTSTANDING:
Basic	418		304		380		304
Diluted	420		305		382		305
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$ 0		$ 0		$ 0.55		$ 0.55
FES
REVENUES:
Other	70,000,000		58,000,000		156,000,000		171,000,000
Total revenues	1,292,000,000		1,326,000,000		2,684,000,000		2,714,000,000
EXPENSES:
Fuel	316,000,000		343,000,000		659,000,000		671,000,000
Other operating expenses	429,000,000		304,000,000		910,000,000		608,000,000
Provision for depreciation	68,000,000		63,000,000		136,000,000		126,000,000
General taxes	30,000,000		22,000,000		60,000,000		49,000,000
Impairment of long-lived assets	7,000,000				20,000,000		2,000,000
Total expenses	1,244,000,000		1,111,000,000		2,545,000,000		2,346,000,000
OPERATING INCOME	48,000,000		215,000,000		139,000,000		368,000,000
OTHER INCOME (EXPENSE):
Investment income	16,000,000		13,000,000		22,000,000		14,000,000
Miscellaneous income (expense)	4,000,000		4,000,000		8,000,000		7,000,000
Interest expense	(52,000,000)		(51,000,000)		(105,000,000)		(101,000,000)
Capitalized interest	10,000,000		24,000,000		20,000,000		44,000,000
Total other expense	(24,000,000)		(12,000,000)		(58,000,000)		(41,000,000)
INCOME BEFORE INCOME TAXES	24,000,000		203,000,000		81,000,000		327,000,000
INCOME TAXES	4,000,000		69,000,000		25,000,000		113,000,000
NET INCOME	20,000,000		134,000,000		56,000,000		214,000,000
FES | Affiliates
REVENUES:
Unregulated businesses	170,000,000		539,000,000		431,000,000		1,146,000,000
EXPENSES:
Purchased power	65,000,000		69,000,000		134,000,000		130,000,000
OTHER INCOME (EXPENSE):
Interest expense	(2,000,000)		(2,000,000)		(3,000,000)		(5,000,000)
FES | Non-Affiliates
REVENUES:
Unregulated businesses	1,052,000,000		729,000,000		2,097,000,000		1,397,000,000
EXPENSES:
Purchased power	329,000,000		310,000,000		626,000,000		760,000,000
OE
REVENUES:
Electric utilities	360,203,000		415,437,000		724,034,000		895,362,000
Excise and (gross receipts) tax collections	24,941,000		23,949,000		53,136,000		52,424,000
Total revenues	385,144,000		439,386,000		777,170,000		947,786,000
EXPENSES:
Purchased power	62,667,000		78,826,000		123,046,000		173,057,000
Other operating expenses	110,778,000		88,275,000		212,240,000		177,130,000
Provision for depreciation	22,470,000		22,014,000		44,346,000		43,894,000
Amortization of regulatory assets, net	2,405,000		9,424,000		3,179,000		38,769,000
General taxes	45,592,000		43,362,000		95,018,000		90,854,000
Total expenses	313,046,000		375,951,000		640,225,000		811,431,000
OPERATING INCOME	72,098,000		63,435,000		136,945,000		136,355,000
OTHER INCOME (EXPENSE):
Investment income	5,043,000		6,309,000		9,351,000		11,553,000
Miscellaneous income (expense)	(477,000)		1,295,000		(187,000)		1,003,000
Interest expense	(22,011,000)		(22,155,000)		(44,156,000)		(44,465,000)
Capitalized interest	510,000		295,000		841,000		503,000
Total other expense	(16,935,000)		(14,256,000)		(34,151,000)		(31,406,000)
INCOME BEFORE INCOME TAXES	55,163,000		49,179,000		102,794,000		104,949,000
INCOME TAXES	16,538,000		11,856,000		34,029,000		31,465,000
NET INCOME	38,625,000		37,323,000		68,765,000		73,484,000
Income (loss) attributable to noncontrolling interest	114,000		130,000		230,000		262,000
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	38,511,000		37,193,000		68,535,000		73,222,000
OE | Affiliates
EXPENSES:
Purchased power	69,134,000		134,050,000		162,396,000		287,727,000
CEI
REVENUES:
Electric utilities	202,148,000		280,180,000		408,890,000		592,677,000
Excise and (gross receipts) tax collections	15,706,000		15,495,000		33,851,000		33,068,000
Total revenues	217,854,000		295,675,000		442,741,000		625,745,000
EXPENSES:
Other operating expenses	31,625,000		28,937,000		66,661,000		60,172,000
Provision for depreciation	18,488,000		18,336,000		36,914,000		36,447,000
Amortization of regulatory assets, net	18,166,000		30,807,000		41,536,000		75,946,000
General taxes	36,954,000		28,840,000		77,166,000		67,329,000
Total expenses	164,372,000		238,993,000		345,804,000		518,758,000
OPERATING INCOME	53,482,000		56,682,000		96,937,000		106,987,000
OTHER INCOME (EXPENSE):
Investment income	5,637,000		6,605,000		12,234,000		14,152,000
Miscellaneous income (expense)	1,038,000		675,000		1,674,000		1,257,000
Interest expense	(32,135,000)		(33,262,000)		(65,213,000)		(66,883,000)
Capitalized interest	36,000		7,000		63,000		33,000
Total other expense	(25,424,000)		(25,975,000)		(51,242,000)		(51,441,000)
INCOME BEFORE INCOME TAXES	28,058,000		30,707,000		45,695,000		55,546,000
INCOME TAXES	6,209,000		8,785,000		10,645,000		19,628,000
NET INCOME	21,849,000		21,922,000		35,050,000		35,918,000
Income (loss) attributable to noncontrolling interest	309,000		366,000		675,000		785,000
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	21,540,000		21,556,000		34,375,000		35,133,000
CEI | Affiliates
EXPENSES:
Purchased power	36,040,000		99,422,000		82,208,000		208,815,000
CEI | Non-Affiliates
EXPENSES:
Purchased power	23,099,000		32,651,000		41,319,000		70,049,000
TE
REVENUES:
Electric utilities	93,048,000		114,691,000		199,373,000		240,122,000
Excise and (gross receipts) tax collections	6,270,000		6,059,000		13,572,000		13,100,000
Total revenues	99,318,000		120,750,000		212,945,000		253,222,000
EXPENSES:
Other operating expenses	32,549,000		25,499,000		69,136,000		51,044,000
Provision for depreciation	7,959,000		8,013,000		15,890,000		15,963,000
Amortization of regulatory assets, net	(7,054,000)		(1,800,000)		(18,532,000)		(10,299,000)
General taxes	12,438,000		12,282,000		26,890,000		25,743,000
Total expenses	79,043,000		106,323,000		176,040,000		217,889,000
OPERATING INCOME	20,275,000		14,427,000		36,905,000		35,333,000
OTHER INCOME (EXPENSE):
Investment income	2,599,000		5,057,000		5,521,000		8,857,000
Miscellaneous income (expense)	396,000		(945,000)		(1,233,000)		(2,351,000)
Interest expense	(10,415,000)		(10,455,000)		(20,858,000)		(20,942,000)
Capitalized interest	135,000		80,000		237,000		158,000
Total other expense	(7,285,000)		(6,263,000)		(16,333,000)		(14,278,000)
INCOME BEFORE INCOME TAXES	12,990,000		8,164,000		20,572,000		21,055,000
INCOME TAXES	1,429,000		948,000		3,164,000		6,330,000
NET INCOME	11,561,000		7,216,000		17,408,000		14,725,000
Income (loss) attributable to noncontrolling interest	2,000		2,000		4,000		5,000
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	11,559,000		7,214,000		17,404,000		14,720,000
TE | Affiliates
EXPENSES:
Purchased power	17,037,000		47,106,000		52,554,000		101,725,000
TE | Non-Affiliates
EXPENSES:
Purchased power	16,114,000		15,223,000		30,102,000		33,713,000
JCP&L
REVENUES:
Electric utilities	576,977,000		709,606,000		1,211,000,000		1,400,998,000
Excise and (gross receipts) tax collections	11,120,000		11,012,000		23,607,000		23,364,000
Total revenues	588,097,000		720,618,000		1,234,607,000		1,424,362,000
EXPENSES:
Purchased power	328,463,000		410,470,000		698,631,000		824,486,000
Other operating expenses	78,603,000		75,177,000		164,682,000		170,837,000
Provision for depreciation	26,773,000		27,093,000		52,087,000		55,064,000
Amortization of regulatory assets, net	40,046,000		81,326,000		121,633,000		150,774,000
General taxes	15,115,000		14,902,000		32,526,000		31,338,000
Total expenses	489,000,000		608,968,000		1,069,559,000		1,232,499,000
OPERATING INCOME	99,097,000		111,650,000		165,048,000		191,863,000
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)	3,554,000		1,649,000		5,464,000		3,482,000
Interest expense	(31,125,000)		(30,041,000)		(61,782,000)		(59,464,000)
Capitalized interest	618,000		156,000		1,045,000		289,000
Total other expense	(26,953,000)		(28,236,000)		(55,273,000)		(55,693,000)
INCOME BEFORE INCOME TAXES	72,144,000		83,414,000		109,775,000		136,170,000
INCOME TAXES	30,383,000		33,521,000		48,461,000		57,051,000
NET INCOME	41,761,000		49,893,000		61,314,000		79,119,000
Met-Ed
REVENUES:
Electric utilities	265,363,000		422,030,000		603,779,000		873,590,000
Excise and (gross receipts) tax collections	14,601,000		20,629,000		33,401,000		42,196,000
Total revenues	279,964,000		442,659,000		637,180,000		915,786,000
EXPENSES:
Other operating expenses	50,075,000		90,151,000		97,307,000		192,134,000
Provision for depreciation	12,766,000		13,440,000		25,189,000		26,198,000
Amortization of regulatory assets, net	22,167,000		48,589,000		54,261,000		97,389,000
General taxes	17,152,000		19,894,000		39,302,000		41,634,000
Total expenses	237,931,000		406,350,000		554,762,000		844,639,000
OPERATING INCOME	42,033,000		36,309,000		82,418,000		71,147,000
OTHER INCOME (EXPENSE):
Interest income	13,000		880,000		106,000		2,097,000
Miscellaneous income (expense)	915,000		1,381,000		1,885,000		3,554,000
Interest expense	(13,130,000)		(13,002,000)		(26,187,000)		(26,775,000)
Capitalized interest	228,000		159,000		375,000		285,000
Total other expense	(11,974,000)		(10,582,000)		(23,821,000)		(20,839,000)
INCOME BEFORE INCOME TAXES	30,059,000		25,727,000		58,597,000		50,308,000
INCOME TAXES	13,281,000		8,618,000		19,232,000		20,884,000
NET INCOME	16,778,000		17,109,000		39,365,000		29,424,000
Met-Ed | Affiliates
EXPENSES:
Purchased power	34,935,000		149,000,000		84,824,000		310,080,000
Met-Ed | Non-Affiliates
EXPENSES:
Purchased power	100,836,000		85,276,000		253,879,000		177,204,000
Penelec
REVENUES:
Electric utilities	238,942,000		350,335,000		547,258,000		736,271,000
Excise and (gross receipts) tax collections	12,727,000		16,162,000		29,256,000		33,686,000
Total revenues	251,669,000		366,497,000		576,514,000		769,957,000
EXPENSES:
Other operating expenses	44,570,000		67,070,000		85,898,000		139,464,000
Provision for depreciation	15,770,000		16,605,000		30,343,000		31,287,000
Amortization of regulatory assets, net	12,608,000		(10,522,000)		25,615,000		(20,488,000)
General taxes	14,665,000		18,647,000		35,401,000		35,181,000
Total expenses	206,707,000		331,574,000		485,271,000		685,041,000
OPERATING INCOME	44,962,000		34,923,000		91,243,000		84,916,000
OTHER INCOME (EXPENSE):
Miscellaneous income (expense)	644,000		1,310,000		669,000		2,923,000
Interest expense	(17,361,000)		(17,630,000)		(34,595,000)		(34,920,000)
Capitalized interest	41,000		183,000		63,000		323,000
Total other expense	(16,676,000)		(16,137,000)		(33,863,000)		(31,674,000)
INCOME BEFORE INCOME TAXES	28,286,000		18,786,000		57,380,000		53,242,000
INCOME TAXES	13,568,000		5,812,000		25,356,000		22,969,000
NET INCOME	14,718,000		12,974,000		32,024,000		30,273,000
Penelec | Affiliates
EXPENSES:
Purchased power	54,635,000		152,945,000		102,119,000		321,345,000
Penelec | Non-Affiliates
EXPENSES:
Purchased power	$ 64,459,000		$ 86,829,000		$ 205,895,000		$ 178,252,000

[1] *Includes excise tax collections of $116 million and $99 million in the three months ended June 30,2011 and 2010, respectively, and $235 million and $208 million in the six months ended June 30, 2011 and 2010, respectively.

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Merger (Details 2) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2011
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	$ 568
Above Market Contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	829
Above Market Contracts | Energy contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	189
Amortization period of intangible assets and liabilities (in years)	10
Above Market Contracts | NUG contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	124
Amortization period of intangible assets and liabilities (in years)	25
Above Market Contracts | Coal supply contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	516
Amortization period of intangible assets and liabilities (in years)	8
Below Market Contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	261
Below Market Contracts | NUG contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	143
Amortization period of intangible assets and liabilities (in years)	13
Below Market Contracts | Coal supply contracts
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	83
Amortization period of intangible assets and liabilities (in years)	7
Below Market Contracts | Transportation contract
The preliminary valuation of the additional intangible assets and liabilities recorded as result of the merger
Valuation of intangible assets and liabilities	$ 35
Amortization period of intangible assets and liabilities (in years)	8

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Fair Value Measurements (Details Textuals) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities	$ 130	$ 193
Investment excludes Receivables, Payables and Accrued income	6	(7)
Fair Value of Financial Instruments (Textuals) [Abstract]
Investments not required to be disclosed	345	259
Debt assumed-carrying value	4,530
Debt assumed- Fair value	4,127
FES
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities	39	153
Investment excludes Receivables, Payables and Accrued income		7
OE
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities	3	3
Investment excludes Receivables, Payables and Accrued income	2	1
TE
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities		34
Investment excludes Receivables, Payables and Accrued income	(1)	2
JCP&L
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities	19	3
Investment excludes Receivables, Payables and Accrued income	5	(3)
Met-Ed
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities	14	(3)
Investment excludes Receivables, Payables and Accrued income	(1)	(9)
Penelec
Fair Value of Financial Instruments [Line Items]
Cash balance excluded from available for sale securities	55	4
Investment excludes Receivables, Payables and Accrued income	$ 1	$ (3)

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Pension and Other Postretirement Benefits (Details Textuals) (USD $) In Millions, unless otherwise specified	6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2011 Allegheny Pension Benefit Cost (Credit)	Feb. 25, 2011 Allegheny Pension Benefit Cost (Credit)	Jun. 30, 2011 Pension Benefit Cost (Credit)	Jun. 30, 2011 Pension Benefit Cost (Credit)	Jun. 30, 2011 Allegheny Other Postretirement Benefit Cost (Credit)	Feb. 25, 2011 Allegheny Other Postretirement Benefit Cost (Credit)	Jun. 30, 2011 Other Postretirement Benefit Cost (Credit)
Defined Benefit Plan Disclosure [Line Items]
Discount rate used to measure funded status	5.50%				5.25%
Expected returns on plan assets used to calculate net period costs	8.25%				5.00%
Fair value of plan assets		$ 954				$ 75
Actuarially determined benefit obligations		1,341				272
Employer Contribution for qualified Plans			105	262
Expected Additional Employer Contribution in Next Fiscal Year			$ 116	$ 116			$ 2

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Segment Information (Details) (USD $)	3 Months Ended				6 Months Ended
	Jun. 30, 2011		Jun. 30, 2010		Jun. 30, 2011		Jun. 30, 2010		Dec. 31, 2010
Segment Financial Information
External revenues	$ 4,048,000,000		$ 3,139,000,000		$ 7,592,000,000		$ 6,371,000,000
Internal revenues	12,000,000				44,000,000		67,000,000
Total revenues	4,060,000,000	[1]	3,139,000,000	[1]	7,636,000,000	[1]	6,438,000,000	[1]
Depreciation and amortization	372,000,000		351,000,000		724,000,000		756,000,000
Investment income (loss), net	31,000,000		31,000,000		52,000,000		47,000,000
Net interest charges	245,000,000		167,000,000		458,000,000		339,000,000
Income taxes	101,000,000		134,000,000		179,000,000		245,000,000
Net income (loss)	171,000,000		256,000,000		216,000,000		405,000,000
Total assets	47,596,000,000		34,466,000,000		47,596,000,000		34,466,000,000		34,805,000,000
Total goodwill	6,456,000,000		5,575,000,000		6,456,000,000		5,575,000,000		5,575,000,000
Property additions	569,000,000		489,000,000		1,018,000,000		997,000,000
Regulated Distribution
Segment Financial Information
External revenues	2,485,000,000		2,314,000,000		4,753,000,000		4,798,000,000
Internal revenues			19,000,000				19,000,000
Total revenues	2,485,000,000		2,333,000,000		4,753,000,000		4,817,000,000
Depreciation and amortization	240,000,000		264,000,000		485,000,000		577,000,000
Investment income (loss), net	27,000,000		28,000,000		52,000,000		54,000,000
Net interest charges	145,000,000		124,000,000		276,000,000		248,000,000
Income taxes	108,000,000		81,000,000		164,000,000		143,000,000
Net income (loss)	184,000,000		132,000,000		280,000,000		235,000,000
Total assets	26,932,000,000		21,457,000,000		26,932,000,000		21,457,000,000
Total goodwill	5,551,000,000		5,551,000,000		5,551,000,000		5,551,000,000		5,551,000,000
Property additions	302,000,000		157,000,000		479,000,000		309,000,000
Competitive Energy Services
Segment Financial Information
External revenues	1,495,000,000		795,000,000		2,736,000,000		1,514,000,000
Internal revenues	318,000,000		539,000,000		661,000,000		1,213,000,000
Total revenues	1,813,000,000		1,334,000,000		3,397,000,000		2,727,000,000
Depreciation and amortization	107,000,000		71,000,000		195,000,000		148,000,000
Investment income (loss), net	15,000,000		13,000,000		21,000,000		14,000,000
Net interest charges	67,000,000		33,000,000		122,000,000		66,000,000
Income taxes	7,000,000		75,000,000		10,000,000		117,000,000
Net income (loss)	12,000,000		121,000,000		17,000,000		190,000,000
Total assets	17,146,000,000		11,102,000,000		17,146,000,000		11,102,000,000
Total goodwill	905,000,000		24,000,000		905,000,000		24,000,000		24,000,000
Property additions	197,000,000		290,000,000		411,000,000		619,000,000
Regulated Independent Transmission
Segment Financial Information
External revenues	105,000,000		59,000,000		172,000,000		116,000,000
Total revenues	105,000,000		59,000,000		172,000,000		116,000,000
Depreciation and amortization	18,000,000		13,000,000		31,000,000		25,000,000
Net interest charges	11,000,000		5,000,000		20,000,000		10,000,000
Income taxes	18,000,000		7,000,000		25,000,000		14,000,000
Net income (loss)	31,000,000		11,000,000		44,000,000		23,000,000
Total assets	2,339,000,000		993,000,000		2,339,000,000		993,000,000
Total goodwill	0				0				0
Property additions	45,000,000		15,000,000		72,000,000		29,000,000
Other/Corporate
Segment Financial Information
External revenues	(30,000,000)		(21,000,000)		(53,000,000)		(43,000,000)
Total revenues	(30,000,000)		(21,000,000)		(53,000,000)		(43,000,000)
Depreciation and amortization	7,000,000		3,000,000		13,000,000		6,000,000
Investment income (loss), net	1,000,000				1,000,000		1,000,000
Net interest charges	21,000,000		9,000,000		40,000,000		22,000,000
Income taxes	(30,000,000)		(12,000,000)		(50,000,000)		(24,000,000)
Net income (loss)	(51,000,000)		(20,000,000)		(86,000,000)		(39,000,000)
Total assets	1,179,000,000		914,000,000		1,179,000,000		914,000,000
Total goodwill	0				0				0
Property additions	25,000,000		27,000,000		56,000,000		40,000,000
Reconciling Adjustments
Segment Financial Information
External revenues	(7,000,000)		(8,000,000)		(16,000,000)		(14,000,000)
Internal revenues	(306,000,000)		(558,000,000)		(617,000,000)		(1,165,000,000)
Total revenues	(313,000,000)		(566,000,000)		(633,000,000)		(1,179,000,000)
Investment income (loss), net	(12,000,000)		(10,000,000)		(22,000,000)		(22,000,000)
Net interest charges	1,000,000		(4,000,000)				(7,000,000)
Income taxes	(2,000,000)		(17,000,000)		30,000,000		(5,000,000)
Net income (loss)	$ (5,000,000)		$ 12,000,000		$ (39,000,000)		$ (4,000,000)

[1] *Includes excise tax collections of $116 million and $99 million in the three months ended June 30,2011 and 2010, respectively, and $235 million and $208 million in the six months ended June 30, 2011 and 2010, respectively.

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Fair Value Measurements (Details 3) (Debt Securities, USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 414	$ 476
Unrealized Gains	84	91
Unrealized Losses	0	0
Fair Value	498	567
OE
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	178	190
Unrealized Gains	45	51
Unrealized Losses	0	0
Fair Value	223	241
CEI
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	287	340
Unrealized Gains	39	41
Unrealized Losses	0	0
Fair Value	$ 326	$ 381

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Fair Value Measurements (Details 4) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
TE | Carrying Value
Approximate fair value and related carrying amounts of notes receivable
Notes receivable	$ 82	$ 104
TE | Fair Value
Approximate fair value and related carrying amounts of notes receivable
Notes receivable	94	118
Carrying Value
Approximate fair value and related carrying amounts of notes receivable
Notes receivable	6	7
Fair Value
Approximate fair value and related carrying amounts of notes receivable
Notes receivable	$ 7	$ 8

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Derivative Instruments (Details Textuals) (USD $)	3 Months Ended	6 Months Ended			3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Dec. 31, 2010	Jun. 30, 2010	Jun. 30, 2011 Cash Flow Hedges	Jun. 30, 2010 Cash Flow Hedges	Jun. 30, 2011 Cash Flow Hedges	Jun. 30, 2010 Cash Flow Hedges	Jun. 30, 2011 Fair Value Hedging	Jun. 30, 2010 Fair Value Hedging	Jun. 30, 2011 Fair Value Hedging	Jun. 30, 2010 Fair Value Hedging	Jun. 30, 2011 Interest Rate Swap	Jun. 30, 2011 Allegheny
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months	$ 3,000,000	$ 3,000,000			$ 10,000,000		$ 10,000,000		$ 22,000,000		$ 22,000,000
Reclassifications from accumulated other comprehensive loss					3,000,000	3,000,000	6,000,000	6,000,000
Notional Amount of Interest Rate Fair Value Hedge Derivatives													200,000,000
FirstEnergy posted of collateral related to net liability positions	81,000,000	81,000,000												2,000,000
Reclassifications from long-term debt									6,000,000	2,000,000	11,000,000	3,000,000
Derivative Instruments (Textuals) [Abstract]
Expected adverse change in quoted market prices of derivative instruments				10.00%
Decrease net income due to adverse change in commodity prices		31,000,000
Decrease net income due to adverse change in commodity prices, net of tax		20,000,000
Cash Flow Hedges Derivative assets			104,000,000
Cash Flow Hedges Derivative liabilities			101,000,000
Unamortized gains or losses associated with designated cash flow hedges	8,000,000	8,000,000
Unamortized gains or losses associated with prior interest rate hedges	84,000,000	84,000,000
Unamortized gains or losses associated with prior interest rate hedges net of tax	55,000,000	55,000,000
Reclassifications from AOCL into other operating expense	14,000,000	19,000,000
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	113,000,000	113,000,000
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements, net of tax	73,000,000	73,000,000
Net liability position under commodity derivative contracts	45,000,000	45,000,000
Additional collateral related to commodity derivatives	$ 49,000,000	$ 49,000,000
Number of Interest Rate Swap Agreements		2

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Merger (Details 3) (USD $) In Millions	Jun. 30, 2011	Dec. 31, 2010
Total intangible assets recorded
Intangible assets	$ 973	$ 256
NUG | Purchase contract assets
Total intangible assets recorded
Intangible assets	198
Purchase contract assets
Total intangible assets recorded
Intangible assets	252
Purchase contract assets | OVEC
Total intangible assets recorded
Intangible assets	54
Energy contracts | Intangible Assets
Total intangible assets recorded
Intangible assets	105
Coal contracts | Intangible Assets
Total intangible assets recorded
Intangible assets	487
Intangible Assets
Total intangible assets recorded
Intangible assets	721
Intangible Assets | FES customer intangible assets
Total intangible assets recorded
Intangible assets	$ 129