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 March 31, 2012

OR

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

For the transition period from ___________________ to ___________________

Commission	Registrant; State of Incorporation;	I.R.S. Employer
File Number	Address; and Telephone Number	Identification No.
333-21011	FIRSTENERGY CORP.	34-1843785
	(An Ohio Corporation)
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
000-53742	FIRSTENERGY SOLUTIONS CORP.	31-1560186
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-2578	OHIO EDISON COMPANY	34-0437786
	(An Ohio Corporation)
	c/o FirstEnergy Corp.
	76 South Main Street
	Akron, OH 44308
	Telephone (800)736-3402
1-3141	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

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 and Jersey Central Power & Light 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 and Jersey Central Power & Light 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 and Jersey Central Power & Light 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 and Jersey Central Power & Light Company

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

	OUTSTANDING
CLASS	AS OF APRIL 30, 2012
FirstEnergy Corp., $.10 par value	418,216,437
FirstEnergy Solutions Corp., no par value	7
Ohio Edison Company, no par value	60
Jersey Central Power & Light Company, $10 par value	13,628,447

FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp., Ohio Edison Company and Jersey Central Power & Light Company common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp., FirstEnergy Solutions Corp., Ohio Edison Company and Jersey Central Power & Light 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 and Jersey Central Power & Light 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 before FERC and 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.

• The uncertainties of various cost recovery and cost allocation issues resulting from ATSI's realignment into PJM.

• Economic or weather conditions affecting future sales and margins.

• Changes in markets for energy services.

• Changing energy and commodity market prices and availability.

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

• The continued ability of our 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 CSAPR which was stayed by the courts on December 30, 2011, and the effects of the EPA's MATS rules.

• The uncertainty of the timing and amounts of the capital expenditures that may arise in connection with any litigation, including 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).

• The uncertainties associated with our plan to retire our older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments, and PJM's review of our plans for, and the timing of, those retirements.

• 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 or as a result of the incident at Japan's Fukushima Daiichi Nuclear Plant).

• Issues that could result from our continuing evaluation of the indications of cracking in the Davis-Besse Plant shield building imposed by the CAL issued by the NRC.

• Adverse legal decisions and outcomes related to ME's and PN'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.

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

• The ability to experience growth in the distribution business.

• Changing market conditions that could affect the value of assets held in our NDTs, pension trusts and other trust funds, and cause us and our subsidiaries to make additional contributions sooner, or in amounts that are larger than currently anticipated.

• The impact of changes to material accounting policies.

• The ability to access the public securities and other capital and credit markets in accordance with our financing plans, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries.

• Changes in general economic conditions affecting us and our subsidiaries.

• Interest rates and any actions taken by credit rating agencies that could negatively affect us and our subsidiaries' access to financing, increased costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.

• The state of the national and regional economy and its impact on our major industrial and commercial customers.

• Issues concerning the soundness of domestic and foreign financial institutions and counterparties with which we do business.

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

Dividends declared from time to time on FE's common stock during any annual period may in the aggregate vary from the indicated amount due to circumstances considered by FE'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 FirstEnergy's 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, except as required by law, 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	ii
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
Jersey Central Power & Light Company
Consolidated Statements of Income and Comprehensive Income	11
Consolidated Balance Sheets	12
Consolidated Statements of Cash Flows	13
Combined Notes To Consolidated Financial Statements	14
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries	53
FirstEnergy Corp. Management's Discussion of Analysis of Financial Condition and Results of Operations	53
Management’s Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	89
Ohio Edison Company	93
Jersey Central Power & Light Company	95
Item 3. Quantitative and Qualitative Disclosures About Market Risk	97
Item 4. Controls and Procedures — FirstEnergy	97
Part II. Other Information
Item 1. Legal Proceedings	97
Item 1A. Risk Factors	97
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	97
Item 3. Defaults Upon Senior Securities	97
Item 4. Mine Safety Disclosures	97
Item 5. Other Information	97
Item 6. Exhibits	98

i

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
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary of AE
AET	Allegheny Energy Transmission, LLC, a subsidiary of AE, which is the parent of ATSI and TrAIL and has a joint venture in PATH
AGC	Allegheny Generating Company, a generation subsidiary of AE
Allegheny	Allegheny Energy, Inc., together with its consolidated subsidiaries
ATSI	American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of AET in April 2012, which owns and operates transmission facilities.
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FE	FirstEnergy Corp., a public utility holding company
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., a subsidiary of FES, which owns and operates non-nuclear generating facilities
FirstEnergy	FirstEnergy Corp., together with its consolidated subsidiaries
Global Holding	Global Mining Holding Company, LLC, a joint venture between FEV, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns Global Rail and Signal Peak
Global Rail	A joint venture between FEV, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns coal transportation operations near Roundup, Montana
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
ME	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., a subsidiary of FES, which 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 AEP
PATH-Allegheny	PATH Allegheny Transmission Company, LLC
PATH-VA	PATH Allegheny Virginia Transmission Corporation
PE	The Potomac Edison Company, a Maryland electric utility operating subsidiary of AE
PN	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	ME, PN, 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, WMB Marketing Ventures, LLC and Gunvor Group, Ltd. that owns mining operations near Roundup, Montana
TE	The Toledo Edison Company, an Ohio electric utility operating subsidiary
TrAIL	Trans-Allegheny Interstate Line Company, a subsidiary of AET, which owns and operates transmission facilities
Utilities	OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
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
Anker WV	Anker West Virginia Mining Company, Inc.
Anker Coal	Anker Coal Group, Inc.
AOCI	Accumulated Other Comprehensive Income
AEP	American Electric Power Company, Inc.
AREPA	Alternative and Renewable Energy Portfolio Act
ARR	Auction Revenue Right
ASLB	Atomic Safety and Licensing Board

ii

GLOSSARY OF TERMS, Continued
BGS	Basic Generation Service
BMP	Bruce Mansfield Plant
CAA	Clean Air Act
CAL	Confirmatory Action Letter
CAIR	Clean Air Interstate Rule
CBP	Competitive Bid Process
CCB	Coal Combustion By-products
CDWR	California Department of Water Resources
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
DCPD	Deferred Compensation Plan for Outside Directors
DCR	Delivery Capital Recovery Rider
DOE	United States Department of Energy
DOJ	United States Department of Justice
DSP	Default Service Plan
EDC	Electric Distribution Company
EDCP	Executive Deferred Compensation Plan
EE&C	Energy Efficiency and Conservation
EGS	Electric Generation Supplier
EHB	Environmental Hearing Board
ENEC	Expanded Net Energy Cost
EPA	United States Environmental Protection Agency
ERO	Electric Reliability Organization
ESP	Electric Security Plan
FERC	Federal Energy Regulatory Commission
Fitch	Fitch Ratings
FMB	First Mortgage Bond
FPA	Federal Power Act
FTR	Financial Transmission Right
GAAP	Accounting Principles Generally Accepted in the United States of America
GHG	Greenhouse Gases
HCL	Hydrochloric Acid
ICG	International Coal Group Inc.
ILP	Integrated License Application Process
IRS	Internal Revenue Service
kV	Kilovolt
KWH	Kilowatt-hour
LBR	Little Blue Run
LOC	Letter of Credit
LSE	Load Serving Entity
LTIP	Long-Term Incentive Plan
MATS	Mercury and Air Toxics Standards
MDPSC	Maryland Public Service Commission
MISO	Midwest Independent Transmission System Operator, Inc.
Moody’s	Moody’s Investors Service, Inc.
MTEP	MISO Regional Transmission Expansion Plan
MVP	Multi-value Project
MW	Megawatt
MWH	Megawatt-hour

iii

GLOSSARY OF TERMS, Continued
NCEA	NERC Compliance Enforcement Authority
NDT	Nuclear Decommissioning Trust
NEPA	National Environmental Policy Act
NERC	North American Electric Reliability Corporation
NJBPU	New Jersey Board of Public Utilities
NNSR	Non-Attainment New Source Review
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NYPSC	New York State Public Service Commission
NYSEG	New York State Electric and Gas
OCI	Other Comprehensive Income
OPEB	Other Post-Employment Benefits
OTTI	Other Than Temporary Impairments
OVEC	Ohio Valley Electric Corporation
PA DEP	Pennsylvania Department of Environmental Protection
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection LLC
PM	Particulate Matter
POLR	Provider of Last Resort
PPUC	Pennsylvania Public Utility Commission
PSA	Power Supply Agreement
PSD	Prevention of Significant Deterioration
PUCO	Public Utilities Commission of Ohio
PURPA	Public Utility Regulatory Policies Act of 1978
REC	Renewable Energy Credit
RFC	ReliabilityFirst
RFP	Request for Proposal
RGGI	Regional Greenhouse Gas Initiative
ROE	Return on Equity
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill 221
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
SIP	State Implementation Plan(s) Under the Clean Air Act
SMIP	Smart Meter Implementation Plan
SO2	Sulfur Dioxide
SOS	Standard Offer Service
SREC	Solar Renewable Energy Credit
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

iv

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended March 31
(In millions, except per share amounts)	2012			2011
REVENUES:
Electric utilities	$	2,554		$	2,332
Unregulated businesses	1,524			1,244
Total revenues*	4,078			3,576
OPERATING EXPENSES:
Fuel	541			453
Purchased power	1,347			1,186
Other operating expenses	812			993
Provision for depreciation	285			225
Amortization of regulatory assets, net	75			132
General taxes	272			237
Total operating expenses	3,332			3,226
OPERATING INCOME	746			350
OTHER INCOME (EXPENSE):
Investment income	11			21
Interest expense	(246		)	(231		)
Capitalized interest	17			18
Total other expense	(218		)	(192		)
INCOME BEFORE INCOME TAXES	528			158
INCOME TAXES	222			111
NET INCOME	306			47
Loss attributable to noncontrolling interest	—			(5		)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	306		$	52
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$	0.73		$	0.15
Diluted	$	0.73		$	0.15
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	418			342
Diluted	420			343
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.55		$	0.55

* Includes excise tax collections of $121 million and $119 million in the three months ended March 31, 2012 and 2011, respectively.

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

1

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
NET INCOME	$	306		$	47
OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(53		)	(44		)
Amortized losses on derivative hedges	(2		)	(6		)
Change in unrealized gain on available-for-sale securities	10			9
Other comprehensive loss	(45		)	(41		)
Income tax benefits on other comprehensive loss	(24		)	(19		)
Other comprehensive loss, net of tax	(21		)	(22		)
COMPREHENSIVE INCOME	285			25
Comprehensive loss attributable to noncontrolling interest	—			(5		)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	285		$	30

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

2

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	March 31, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	74	$	202
Receivables-
Customers, net of allowance for uncollectible accounts of $35 in 2012 and $37 in 2011	1,449		1,525
Other, net of allowance for uncollectible accounts of $8 in 2012 and $3 in 2011	286		269
Materials and supplies	927		811
Prepaid taxes	213		191
Derivatives	346		235
Other	182		122
	3,477		3,355
PROPERTY, PLANT AND EQUIPMENT:
In service	40,587		40,122
Less — Accumulated provision for depreciation	12,086		11,839
	28,501		28,283
Construction work in progress	2,065		2,054
	30,566		30,337
INVESTMENTS:
Nuclear plant decommissioning trusts	2,135		2,112
Investments in lease obligation bonds	336		402
Other	1,011		1,008
	3,482		3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444		6,441
Regulatory assets	2,006		2,030
Other	1,716		1,641
	10,166		10,112
	$	47,691	$	47,326
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,772	$	1,621
Short-term borrowings	1,075		—
Accounts payable	918		1,174
Accrued taxes	442		558
Accrued compensation and benefits	258		384
Derivatives	299		218
Other	1,009		900
	5,773		4,855
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 418,216,437 shares outstanding	42		42
Other paid-in capital	9,754		9,765
Accumulated other comprehensive income	405		426
Retained earnings	3,122		3,047
Total common stockholders’ equity	13,323		13,280
Noncontrolling interest	16		19
Total equity	13,339		13,299
Long-term debt and other long-term obligations	15,527		15,716
	28,866		29,015
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	5,904		5,670
Retirement benefits	2,240		2,823
Asset retirement obligations	1,522		1,497
Deferred gain on sale and leaseback transaction	917		925
Adverse power contract liability	458		469
Other	2,011		2,072
	13,052		13,456
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	47,691	$	47,326

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

3

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	306		$	47
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	285			225
Amortization of regulatory assets, net	75			132
Nuclear fuel and lease amortization	58			47
Deferred purchased power and other costs	(107		)	(58		)
Deferred income taxes and investment tax credits, net	265			204
Deferred rents and lease market valuation liability	(23		)	(15		)
Stock based compensation	(29		)	(9		)
Accrued compensation and retirement benefits	(162		)	(53		)
Commodity derivative transactions, net	(64		)	(25		)
Pension trust contributions	(600		)	(157		)
Asset impairments	4			31
Cash collateral, net	(28		)	(28		)
Decrease (increase) in operating assets-
Receivables	59			164
Materials and supplies	(118		)	40
Prepayments and other current assets	(19		)	118
Increase (decrease) in operating liabilities-
Accounts payable	(256		)	(90		)
Accrued taxes	(116		)	(182		)
Accrued interest	70			76
Other	(13		)	24
Net cash provided from (used for) operating activities	(413		)	491
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			217
Short-term borrowings, net	1,075			—
Redemptions and Repayments-
Long-term debt	(16		)	(359		)
Short-term borrowings, net	—			(214		)
Common stock dividend payments	(230		)	(190		)
Other	(10		)	(4		)
Net cash provided from (used for) financing activities	819			(550		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(589		)	(449		)
Sales of investment securities held in trusts	251			969
Purchases of investment securities held in trusts	(266		)	(993		)
Cash investments	78			47
Cash received in Allegheny merger	—			590
Other	(8		)	(23		)
Net cash provided from (used for) investing activities	(534		)	141
Net change in cash and cash equivalents	(128		)	82
Cash and cash equivalents at beginning of period	202			1,019
Cash and cash equivalents at end of period	$	74		$	1,101
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: merger with Allegheny, common stock issued	$	—		$	4,354

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

4

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
STATEMENTS OF INCOME
REVENUES:
Electric sales to non-affiliates	$	1,332		$	1,044
Electric sales to affiliates	121			261
Other	63			86
Total revenues	1,516			1,391
OPERATING EXPENSES:
Fuel	295			343
Purchased power from affiliates	117			69
Purchased power from non-affiliates	487			297
Other operating expenses	295			465
Provision for depreciation	63			69
General taxes	37			29
Impairment of long-lived assets	—			14
Total operating expenses	1,294			1,286
OPERATING INCOME	222			105
OTHER INCOME (EXPENSE):
Investment income	6			6
Miscellaneous income	4			4
Interest expense — affiliates	(2		)	(1		)
Interest expense — other	(41		)	(53		)
Capitalized interest	9			10
Total other income (expense)	(24		)	(34		)
INCOME BEFORE INCOME TAXES	198			71
INCOME TAXES	76			26
NET INCOME	$	122		$	45
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	122		$	45
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(10		)
Amortized losses on derivative hedges	(5		)	(9		)
Change in unrealized gain on available-for-sale securities	10			8
Other comprehensive loss	—			(11		)
Income taxes (benefits) on other comprehensive income (loss)	2			(6		)
Other comprehensive loss, net of tax	(2		)	(5		)
COMPREHENSIVE INCOME	$	120		$	40

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

5

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	March 31, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	7	$	7
Receivables-
Customers, net of allowance for uncollectible accounts of $16 in 2012 and 2011	395		424
Affiliated companies	541		600
Other, net of allowance for uncollectible accounts of $3 in 2012 and 2011	122		61
Notes receivable from affiliated companies	12		383
Materials and supplies	551		492
Derivatives	322		219
Prepayments and other	24		38
	1,974		2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	11,002		10,983
Less — Accumulated provision for depreciation	4,214		4,110
	6,788		6,873
Construction work in progress	1,173		1,014
	7,961		7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	1,240		1,223
Other	7		7
	1,247		1,230
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	120		123
Goodwill	24		24
Property taxes	43		43
Unamortized sale and leaseback costs	120		80
Derivatives	117		79
Other	171		129
	595		478
	$	11,777	$	11,819
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	905	$	905
Accounts payable-
Affiliated companies	483		436
Other	190		220
Accrued Taxes	75		227
Derivatives	281		189
Other	245		261
	2,179		2,238
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding	1,568		1,570
Accumulated other comprehensive income	74		76
Retained earnings	2,053		1,931
Total common stockholder's equity	3,695		3,577
Long-term debt and other long-term obligations	2,797		2,799
	6,492		6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	917		925
Accumulated deferred income taxes	365		286
Asset retirement obligations	919		904
Retirement benefits	151		356
Lease market valuation liability	160		171
Other	594		563
	3,106		3,205
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	11,777	$	11,819

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

6

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	122		$	45
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	63			69
Nuclear fuel and lease amortization	57			47
Deferred rents and lease market valuation liability	(47		)	(39		)
Deferred income taxes and investment tax credits, net	83			67
Asset impairments	3			19
Accrued compensation and retirement benefits	(10		)	(16		)
Pension trust contribution	(209		)	—
Commodity derivative transactions, net	(52		)	(35		)
Cash collateral, net	(25		)	(27		)
Decrease (increase) in operating assets-
Receivables	28			(76		)
Materials and supplies	(59		)	61
Prepayments and other current assets	14			8
Increase (decrease) in operating liabilities-
Accounts payable	17			(18		)
Accrued taxes	(155		)	(3		)
Other	(8		)	(8		)
Net cash provided from (used for) operating activities	(178		)	94
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	—			150
Short-term borrowings, net	—			350
Redemptions and repayments-
Long-term debt	—			(332		)
Other	(3		)	(1		)
Net cash provided from (used for) financing activities	(3		)	167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(181		)	(159		)
Sales of investment securities held in trusts	83			216
Purchases of investment securities held in trusts	(90		)	(231		)
Loans from (to) affiliated companies, net	371			(82		)
Other	(2		)	(7		)
Net cash provided from (used for) investing activities	181			(263		)
Net change in cash and cash equivalents	—			(2		)
Cash and cash equivalents at beginning of period	7			9
Cash and cash equivalents at end of period	$	7		$	7

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

7

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	359		$	364
Excise and gross receipts tax collections	27			28
Total revenues	386			392
OPERATING EXPENSES:
Purchased power from affiliates	52			93
Purchased power from non-affiliates	70			60
Other operating expenses	121			96
Provision for depreciation	24			23
Amortization of regulatory assets, net	—			1
General taxes	50			50
Total operating expenses	317			323
OPERATING INCOME	69			69
OTHER INCOME (EXPENSE):
Investment income	4			5
Interest expense	(22		)	(22		)
Capitalized interest	1			—
Total other expense	(17		)	(17		)
INCOME BEFORE INCOME TAXES	52			52
INCOME TAXES	21			20
NET INCOME	$	31		$	32
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	31		$	32
OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(10		)	(7		)
Other comprehensive loss	(10		)	(7		)
Income tax benefits on other comprehensive loss	(5		)	(4		)
Other comprehensive loss, net of tax	(5		)	(3		)
COMPREHENSIVE INCOME	$	26		$	29

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

8

OHIO EDISON COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	March 31, 2012			December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—		$	26
Receivables-
Customers, net of allowance for uncollectible accounts of $4 in 2012 and 2011	154			163
Affiliated companies	72			86
Other	37			41
Notes receivable from affiliated companies	259			181
Prepayments and other	11			17
	533			514
UTILITY PLANT:
In service	3,405			3,358
Less — Accumulated provision for depreciation	1,280			1,267
	2,125			2,091
Construction work in progress	85			91
	2,210			2,182
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds	162			163
Nuclear plant decommissioning trusts	137			137
Other	92			90
	391			390
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	362			363
Pension assets	6			5
Property taxes	80			81
Unamortized sale and leaseback costs	24			25
Other	16			14
	488			488
	$	3,622		$	3,574
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	3		$	2
Accounts payable-
Affiliated companies	110			119
Other	34			35
Accrued taxes	88			88
Accrued interest	25			25
Other	102			79
	362			348
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding	747			747
Accumulated other comprehensive income	49			54
Accumulated deficit	(53		)	(84		)
Total common stockholder's equity	743			717
Noncontrolling interest	5			5
Total equity	748			722
Long-term debt and other long-term obligations	1,156			1,155
	1,904			1,877
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	791			787
Accumulated deferred investment tax credits	8			9
Retirement benefits	213			213
Asset retirement obligations	73			71
Other	271			269
	1,356			1,349
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	3,622		$	3,574

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

9

OHIO EDISON COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	31		$	32
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	24			23
Amortization of regulatory assets, net	—			1
Amortization of lease costs	33			33
Deferred income taxes and investment tax credits, net	11			29
Accrued compensation and retirement benefits	(17		)	(13		)
Cash collateral, net	(2		)	—
Pension trust contributions	—			(27		)
Decrease (increase) in operating assets-
Receivables	27			82
Prepayments and other current assets	7			(23		)
Increase (decrease) in operating liabilities-
Accounts payable	(10		)	(20		)
Accrued taxes	1			(10		)
Other	(5		)	(3		)
Net cash provided from operating activities	100			104
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Short-term borrowings, net	—			(39		)
Common stock dividend payments	—			(100		)
Other	(1		)	—
Net cash used for financing activities	(1		)	(139		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(43		)	(37		)
Sales of investment securities held in trusts	37			8
Purchases of investment securities held in trusts	(38		)	(9		)
Loans to affiliated companies, net	(78		)	—
Other	(3		)	(2		)
Net cash used for investing activities	(125		)	(40		)
Net change in cash and cash equivalents	(26		)	(75		)
Cash and cash equivalents at beginning of period	26			420
Cash and cash equivalents at end of period	$	—		$	345

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

10

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	478		$	634
Excise tax collections	10			13
Total revenues	488			647
OPERATING EXPENSES:
Purchased power	264			370
Other operating expenses	81			80
Provision for depreciation	30			26
Amortization of regulatory assets, net	20			82
General taxes	15			18
Total operating expenses	410			576
OPERATING INCOME	78			71
OTHER INCOME (EXPENSE):
Miscellaneous income	1			2
Interest expense	(31		)	(30		)
Total other expense	(30		)	(28		)
INCOME BEFORE INCOME TAXES	48			43
INCOME TAXES	22			20
NET INCOME	$	26		$	23
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	26		$	23
OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(6		)	(6		)
Other comprehensive loss	(6		)	(6		)
Income tax benefits on other comprehensive loss	(4		)	(3		)
Other comprehensive loss, net of tax	(2		)	(3		)
COMPREHENSIVE INCOME	$	24		$	20

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

11

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)		March 31, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Receivables-
Customers, net of allowance for uncollectible accounts of $3 in 2012 and $4 in 2011		$	202	$	235
Affiliated companies		35		—
Other		16		17
Prepaid taxes		39		33
Other		24		19
		316		304
UTILITY PLANT:
In service		5,022		4,872
Less — Accumulated provision for depreciation		1,759		1,743
		3,263		3,129
Construction work in progress		119		227
		3,382		3,356
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust		225		219
Nuclear plant decommissioning trusts		195		193
Other		2		2
		422		414
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill		1,811		1,811
Regulatory assets		384		408
Other		32		32
		2,227		2,251
		$	6,347	$	6,325
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt		$	34	$	34
Short-term borrowings-
Affiliated companies		300		259
Accounts payable-
Affiliated companies		3		19
Other		94		101
Accrued compensation and benefits		33		41
Customer deposits		24		24
Accrued interest		30		18
Other		41		36
		559		532
CAPITALIZATION:
Common stockholder's equity-
Common stock, $10 par value, authorized 16,000,000 shares, 13,628,447 shares outstanding		136		136
Other paid-in capital		2,011		2,011
Accumulated other comprehensive income		36		39
Retained earnings		146		121
Total common stockholder's equity		2,329		2,307
Long-term debt and other long-term obligations		1,729		1,736
		4,058		4,043
NONCURRENT LIABILITIES:
Accumulated deferred income taxes		908		859
Power purchase contract liability		136		147
Nuclear fuel disposal costs		197		197
Retirement benefits		163		170
Asset retirement obligations		117		115
Other		209		262
		1,730		1,750
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)	1
		$	6,347	$	6,325

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

12

JERSEY CENTRAL POWER & LIGHT COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	26		$	23
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	30			26
Amortization of regulatory assets, net	20			82
Deferred purchased power and other costs	(69		)	(27		)
Deferred income taxes and investment tax credits, net	52			28
Accrued compensation and retirement benefits	(22		)	(11		)
Cash collateral, net	6			—
Decrease (increase) in operating assets-
Receivables	(2		)	86
Prepaid taxes	(6		)	(2		)
Increase (decrease) in operating liabilities-
Accounts payable	(22		)	(62		)
Accrued taxes	(5		)	13
Accrued interest	12			12
Other	9			14
Net cash provided from operating activities	29			182
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	40			—
Redemptions and Repayments-
Long-term debt	(8		)	(7		)
Net cash provided from (used for) financing activities	32			(7		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(56		)	(47		)
Loans to affiliated companies, net	—			(121		)
Sales of investment securities held in trusts	95			217
Purchases of investment securities held in trusts	(99		)	(222		)
Other	(1		)	(2		)
Net cash used for investing activities	(61		)	(175		)
Net change in cash and cash equivalents	—			—
Cash and cash equivalents at beginning of period	—			—
Cash and cash equivalents at end of period	$	—		$	—

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

13

FIRSTENERGY CORP. AND SUBSIDIARIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note Number		Page Number
1	Organization and Basis of Presentation	15
2	Earnings Per Share	15
3	Pensions and Other Postemployment Benefits	16
4	Income Taxes	16
5	Variable Interest Entities	17
6	Fair Value Measurements	18
7	Derivative Instruments	25
8	Regulatory Matters	29
9	Commitments, Guarantees and Contingencies	37
10	Supplemental Guarantor Information	43
11	Segment Information	51

14

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. ORGANIZATION AND BASIS OF PRESENTATION

Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.

FE is a diversified energy holding 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), JCP&L, ME, PN, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and AET), FES and its principal 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. Accordingly, consolidated results of operations for the three months ended March 31, 2011, include just one month of Allegheny results.

The consolidated financial statements of FE, FES, OE and JCP&L include the accounts of entities in which a controlling financial interest is held, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or the result of an analysis that identifies FE or one of its subsidiaries as the primary beneficiary of a VIE. Investments in which a controlling financial interest is not held are accounted for under the equity or cost method of accounting.

These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These 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, 2011.

The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair presentation of the 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.

As described in its Annual Report on Form 10-K for the year ended December 31, 2011, FE's consolidated financial statements for the three months ended March 31, 2011, were revised to reflect a purchase accounting measurement adjustment identified during the fourth quarter of 2011 that decreased goodwill and increased income tax expense by approximately $20 million.

As described in its Annual Report on Form 10-K for the year ended December 31, 2011, during the fourth quarter of 2011, FE elected to change its method of accounting relating to its defined benefit pension and OPEB plans to recognize the change in fair value of plan assets and net actuarial gains and losses immediately, and applied this change retrospectively. Generally, these gains and losses are measured annually as of December 31, and accordingly, will be recorded during the fourth quarter.

Certain prior year amounts have been reclassified to conform to the current year presentation.

New Accounting Pronouncements

New accounting pronouncements not yet effective are not expected to have a material effect on the financial statements of FE or its subsidiaries.

2. EARNINGS PER SHARE

Basic earnings per share of common stock are computed using the weighted average number of 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 could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

15

	Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2012		2011
	(In millions, except per share amounts)
Weighted average number of basic shares outstanding	418		342
Assumed exercise of dilutive stock options and awards(1)	2		1
Weighted average number of diluted shares outstanding	420		343
Earnings Available to FirstEnergy Corp.	$	306	$	52
Basic earnings per share of common stock	$	0.73	$	0.15
Diluted earnings per share of common stock	$	0.73	$	0.15

⁽¹⁾  The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months endedMarch 31, 2012 and 2011.

3. PENSIONS AND OTHER POSTEMPLOYMENT 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. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pensions and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. 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 endedMarch 31, 2012, FirstEnergy made pre-tax contributions to its qualified pension plan of $600 million.

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2012			2011			2012			2011
	(In millions)
Service cost	$	40		$	29		$	3		$	3
Interest cost	97			84			12			11
Expected return on plan assets	(121		)	(102		)	(9		)	(10		)
Amortization of prior service cost	3			4			(51		)	(48		)
Other adjustments (settlements, curtailments, etc)	—			7			—			—
Net periodic costs (credits)	$	19		$	22		$	(45	)	$	(44	)

Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and its subsidiaries were as follows:

Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	13		$	20		$	(30	)	$	(32	)
FES	10			7			(8		)	(7		)
OE	(1		)	(2		)	(5		)	(6		)
JCP&L	(1		)	(2		)	(2		)	(3		)

4. 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. During the first quarter of 2012, the federal government issued further guidance

16

related to the tax accounting of costs to repair and maintain fixed assets. This guidance provided a safe harbor method of tax accounting for AE companies and allowed these companies to reduce their amount of unrecognized tax benefits by $21 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item, with no resulting impact to FirstEnergy's effective tax rate in the first quarter of 2012. There were no other material changes to FirstEnergy's unrecognized income tax benefits during the first quarter of 2012 or 2011.

As of March 31, 2012, it is reasonably possible that approximately $45 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $10 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. During the first quarter of 2012 and 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest from the merger with AE in the first quarter of 2011. The net amount of interest accrued as of March 31, 2012 was $12 million, compared with $11 million as of December 31, 2011.

As a result of the non-deductible portion of merger transaction costs, FirstEnergy's effective tax rate was unfavorably impacted by $30 million in the first three months of 2011.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2008-2010, and additionally 2005-2007 for New Jersey. The IRS completed its audits of tax year 2008 in July 2010 and tax year 2009 in April 2011, with both tax years having one open item. Tax years 2010-2011 are under review by the IRS. Allegheny is currently under audit by the IRS for tax years 2007 and 2008. Allegheny has filed its 2009 and 2010 federal returns and such filings are subject to review. State tax returns for tax years 2008 through 2010 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. 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, results of operations, cash flow or liquidity.

5. VARIABLE INTEREST ENTITIES

FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary

VIEs included in FirstEnergy’s consolidated financial statements for the first quarter of 2012 are: the PNBV and Shippingport capital trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; 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 and JCP&L's supply of BGS, of which $270 million was outstanding as of March 31, 2012; and special purpose limited liabilities companies of MP and PE created to issue environmental control bonds that were used to construct environmental control facilities, of which $504 million was outstanding as of March 31, 2012.

The caption noncontrolling interest within the consolidated financial statements is used to reflect the portion of the VIE that FirstEnergy consolidates, but does not wholly own. The change in noncontrolling interest within the Consolidated Balance Sheets during the three months endedMarch 31, 2012, was primarily due to a $3 million distribution to owners.

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.

Mining Operations

On October 18, 2011, a subsidiary of Gunvor Group, Ltd. purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. FEV retained a 33-1/3% equity ownership in the joint venture. Prior to the sale, FirstEnergy consolidated this joint venture since FEV was determined to be the primary beneficiary of the VIE. As a result of the sale, FEV was no longer determined to be the primary beneficiary and its retained 33-1/3% interest is subsequently accounted for using the equity method of accounting.

PATH-WV

PATH 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

17

Putnam County, West Virginia, and the construction of new substations in Hardy County, West Virginia and Frederick County, Maryland as directed by PJM. PATH 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 (PATH-Allegheny) 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 $30 million as of March 31, 2012.

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 applicable utilities if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, ME, PN, PE, WP and MP, maintains 22 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 three 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 three entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. One of JCP&L's NUG contracts, to which the scope exception was applied, expired during 2011.

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 three contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months endedMarch 31, 2012, were $12 million, $32 million and $16 million for JCP&L, PE and WP, respectively. Purchased power costs related to the four contracts that may contain a variable interest that were held by JCP&L, PE and WP, respectively, during the three months endedMarch 31, 2011 were $65 million, $11 million, and $5 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 wherein WP may hold a variable interest, for which WP has taken the scope exception. As of March 31, 2012, WP’s reserve for this adverse purchase power commitment was $51 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, OE and other FE subsidiaries 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 March 31, 2012:

	Maximum Exposure	Discounted Lease Payments, net(1)	Net Exposure
	(In millions)
FES	1,384	1,179	205
OE	583	426	157
Other FE Subsidiaries	643	383	260

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

6. FAIR VALUE MEASUREMENTS

RECURRING AND NONRECURRING FAIR VALUE MEASUREMENTS

On January 1, 2012, FirstEnergy adopted an amendment to the authoritative accounting guidance regarding fair value measurements. The amendment was applied prospectively and expanded disclosure requirements for fair value measurements, particularly for Level 3 measurements, among other changes.

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This

18

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 and a description of the valuation techniques for Level 2 and Level 3 are as follows:

Level 1	-	Quoted prices for identical instruments in active market
Level 2	-	Quoted prices for similar instruments in active market
	-	Quoted prices for identical or similar instruments in markets that are not active
	-	Model-derived valuations for which all significant inputs are observable market data

Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3 - Valuation inputs are unobservable and significant to the fair value measurement

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by the Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs are as follows.

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are subsequently adjusted to fair value using a mark-to-model methodology on a monthly basis, which approximates market. The primary inputs into the model, that are generally less observable from objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 7, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.

NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value using a mark-to-model methodology on a monthly basis, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Monthly pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on IntercontinentalExchange quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2012 and December 31, 2011. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

Transfers between levels are recognized at the end of the reporting period. There were no significant transfers between levels during the 2012 and 2011 periods. The following tables set forth the recurring and nonrecurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy.

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FE CONSOLIDATED
Recurring Fair Value Measurements	March 31, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,561		$	—		1,561			$	—	$	1,544		$	—		$	1,544
Derivative assets - commodity contracts	1			415			—			416			—		264			—			264
Derivative assets - FTRs	—			—			1			1			—		—			1			1
Derivative assets - NUG contracts(1)	—			—			42			42			—		—			56			56
Equity securities(2)	289			—			—			289			259		—			—			259
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			138			—			138			—		148			—			148
U.S. state debt securities	—			313			—			313			—		314			—			314
Other(3)	54			167			—			221			49		225			—			274
Total assets	344			2,594			43			2,981			308		2,498			57			2,863
Liabilities
Derivative liabilities - commodity contracts	(2		)	(347		)	—			(349		)	—		(247		)	—			(247		)
Derivative liabilities - FTRs	—			—			(15		)	(15		)	—		—			(23		)	(23		)
Derivative liabilities - NUG contracts(1)	—			—			(342		)	(342		)	—		—			(349		)	(349		)
Total liabilities	(2		)	(347		)	(357		)	(706		)	—		(247		)	(372		)	(619		)
Net assets (liabilities)(4)	$	342		$	2,247		$	(314	)	$	2,275		$	308	$	2,251		$	(315	)	$	2,244

⁽¹⁾  NUG contracts are generally subject to regulatory accounting and do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

⁽³⁾  Primarily consists of short-term cash investments.

⁽⁴⁾  Excludes $2 million and $(52) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with 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 the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2012 and December 31, 2011:

	NUG Contracts									FTRs
	Derivative Assets(1)			Derivative Liabilities(1)			Net(1)			Derivative Assets(1)			Derivative Liabilities(1)			Net(1)
										(In millions)
January 1, 2011 Balance	$	122		$	(466	)	$	(344	)	$	—		$	—		$	—
Realized gain (loss)	—			—			—			—			—			—
Unrealized gain (loss)	(58		)	(144		)	(202		)	2			(27		)	(25		)
Purchases	—			—			—			13			(4		)	9
Issuances	—			—			—			—			—			—
Sales	—			—			—			—			—			—
Settlements	(7		)	261			254			(14		)	20			6
Transfers in (out) of Level 3	—			—			—						(12		)	(12		)
December 31, 2011 Balance	$	57		$	(349	)	$	(292	)	$	1		$	(23	)	$	(22	)
Realized gain (loss)	—			—			—			—			—			—
Unrealized gain (loss)	(14		)	(65		)	(79		)	—			(3		)	(3		)
Purchases	—			—			—			—			—			—
Issuances	—			—			—			—			—			—
Sales	—			—			—			—			—			—
Settlements	(1		)	72			71			—			11			11
Transfers in (out) of Level 3	—			—			—			—			—			—
March 31, 2012 Balance	$	42		$	(342	)	$	(300	)	$	1		$	(15	)	$	(14	)

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

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Level 3 Quantitative Information

The following table provides quantitative information for NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	(14	)	Model	RTO auction clearing prices	($4.18) to $9.81	$	1.51	Dollars/MWH
NUG Contracts	$	(300	)	Model	Generation Power regional prices	500 to 6,809,000 $58.71 to $84.92	2,547,000 $66.77		MWH Dollars/MWH

FES
Recurring Fair Value Measurements	March 31, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,017		$	—		$	1,017		$	—	$	1,010		$	—		$	1,010
Derivative assets - commodity contracts	1			391			—			392			—		248			—			248
Derivative assets - FTRs	—			—			1			1			—		—			1			1
Equity securities(1)	150			—			—			150			124		—			—			124
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			5			—			5			—		7			—			7
U.S. state debt securities	—			—			—			—			—		5			—			5
Other(2)	—			66			—			66			—		132			—			132
Total assets	151			1,479			1			1,631			124		1,405			1			1,530
Liabilities
Derivative liabilities - commodity contracts	(2		)	(340		)	—			(342		)	—		(234		)	—			(234		)
Derivative liabilities - FTRs	—			—			(5		)	(5		)	—		—			(7		)	(7		)
Total liabilities	(2		)	(340		)	(5		)	(347		)	—		(234		)	(7		)	(241		)
Net assets (liabilities)(3)	$	149		$	1,139		$	(4	)	$	1,284		$	124	$	1,171		$	(6	)	$	1,289

⁽¹⁾  NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.

⁽²⁾  Primarily consists of short-term cash investments.

⁽³⁾  Excludes $2 million and $(58) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

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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 for the periods ended March 31, 2012 and December 31, 2011:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2011 Balance	$	—		$	—		$	—
Realized gain (loss)	—			—			—
Unrealized gain (loss)	4			(8		)	(4		)
Purchases	2			(1		)	1
Issuances	—			—			—
Sales	—			—			—
Settlements	(5		)	2			(3		)
Transfers in (out) of Level 3	—			—			—
December 31, 2011 Balance	$	1		$	(7	)	$	(6	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(1		)	(1		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			4			4
Transfers in (out) of Level 3	—			—			—
March 31, 2012 Balance	$	1		$	(4	)	$	(3	)

Level 3 Quantitative Information

The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	(3	)	Model	RTO auction clearing prices	($4.18) to $8.03	$	0.76	Dollars/MWH

OE
Recurring Fair Value Measurements	March 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets	(In millions)
Corporate debt securities	$	—	$	—	$	—	$	—		$	—	$	3	$	—	$	3
U.S. government debt securities	—		133		—		133			—		132		—		132
Other(1)	—		3		—		3			—		2		—		2
Total assets(2)	$	—	$	136	$	—	$	136		$	—	$	137	$	—	$	137

⁽¹⁾  Primarily consists of short-term cash investments.

⁽²⁾  Excludes $1 million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

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JCP&L
Recurring Fair Value Measurements	March 31, 2012										December 31, 2011
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	148	$	—		$	148		$	—	$	144	$	—		$	144
Derivative assets - NUG contracts(1)	—		—		4			4			—		—		4			4
Equity securities(2)	31		—		—			31			30		—		—			30
U.S. government debt securities	—		—		—			—			—		2		—			2
U.S. state debt securities	—		225		—			225			—		219		—			219
Other(3)	—		16		—			16			—		15		—			15
Total assets	31		389		4			424			30		380		4			414
Liabilities
Derivative liabilities - NUG contracts(1)	—		—		(136		)	(136		)	—		—		(147		)	(147		)
Total liabilities	—		—		(136		)	(136		)	—		—		(147		)	(147		)
Net assets (liabilities)(4)	$	31	$	389	$	(132	)	$	288		$	30	$	380	$	(143	)	$	267

⁽¹⁾  NUG contracts are subject to regulatory accounting and do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

⁽³⁾  Primarily consists of short-term cash investments.

⁽⁴⁾  Excludes $2 million as of December 31, 2011 of receivables, payables, 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 for the periods ended March 31, 2012 and December 31, 2011:

	Derivative Asset NUG Contracts(1)			Derivative Liability NUG Contracts(1)			Net NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	6		(233		)	(227		)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(2		)	(11		)	(13		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			97			97
Transfers in (out) of Level 3	—			—			—
December 31, 2011	$	4		$	(147	)	$	(143	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(6		)	(6		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			17			17
Transfers in (out) of Level 3	—			—			—
March 31, 2012	$	4		$	(136	)	$	(132	)

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

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Level 3 Quantitative Information

The following table provides quantitative information for NUG contracts held by JCP&L that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
NUG Contracts	$	(132	)	Model	Generation Power regional prices	69,000 to 736,000 $58.71 to $84.92	157,000 $68.65	MWH Dollars/MWH

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 and available-for-sale securities.

FE and its subsidiaries 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, FE and its subsidiaries 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 and OE 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 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 NDT 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, OE and JCP&L hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered available-for-sale securities at fair market value. FES, OE and JCP&L 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 March 31, 2012 and December 31, 2011:

	March 31, 2012(1)				December 31, 2011(2)
	Cost Basis	Unrealized Gains	Unrealized Losses	Fair Value	Cost Basis	Unrealized Gains		Unrealized Losses		Fair Value
	(In millions)
Debt securities
FE Consolidated	1,967	42	—	2,009	1,980	25	25	—	—	2,005
FES	1,001	21	—	1,022	1,012	13		—		1,025
OE	133	—	—	133	134	—		—		134
JCP&L	359	12	—	371	356	7		—		363
Equity securities
FE Consolidated	246	42	—	288	222	36		—		258
FES	127	23	—	150	104	20		—		124
JCP&L	27	4	—	31	27	3		—		30

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $160 million; FES - $68 million; OE - $4 million; JCP&L - $19 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $164 million; FES - $74 million; OE - $2 million; JCP&L - $19 million.

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Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales and interest and dividend income for the three months ended March 31, 2012 and 2011 were as follows:

March 31, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	251	$	19	$	(17	)	$	15
FES	83		12		(11		)	7
OE	37		—		—			1
JCP&L	95		1		(1		)	4
March 31, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	969	$	100	$	(29	)	$	24
FES	216		12		(15		)	15
OE	8		—		—			1
JCP&L	217		22		(4		)	4

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and approximate fair values of investments in held-to-maturity securities as of March 31, 2012 and December 31, 2011:

	March 31, 2012			December 31, 2011
	Cost Basis	Unrealized Gains	Fair Value	Cost Basis	Unrealized Gains	Fair Value
	(In millions)
Debt Securities
FE Consolidated	336	41	377	402	50	452
OE	162	19	181	163	21	184

Investments in emission allowances, employee benefit trusts and cost and equity method investments totaling $689 million as of March 31, 2012, and $693 million as of December 31, 2011, are excluded from the amounts reported above.

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, excluding capital lease obligations and net unamortized premiums and discounts, as of March 31, 2012 and December 31, 2011:

	March 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FE Consolidated	$	17,130	$	19,321	$	17,165	$	19,320
FES	3,674		3,944		3,675		3,931
OE	1,158		1,469		1,157		1,434
JCP&L	1,770		2,071		1,777		2,080

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy and its subsidiaries listed above. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of March 31, 2012 and December 31, 2011.

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7. 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 Risk Policy 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.

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 qualified and were designated as cash flow hedge instruments are recorded in AOCI. 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 these 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 a derivative contract are reported as a component of AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships, therefore, as of March 31, 2012 and December 31, 2011, there were no commodity derivative contracts designated in cash flow hedging relationships. Total net unamortized gains included in AOCI associated with dedesignated cash flow hedges totaled $14 million and $19 million as of March 31, 2012 and December 31, 2011, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCI into other operating expenses were $5 million of income and $5 million of loss during the three months ended March 31, 2012 and 2011, respectively. Approximately $7 million is expected to be amortized to income 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 March 31, 2012, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $77 million as of March 31, 2012. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCI into interest expense totaled $2 million and $3 million during the three months ended March 31, 2012 and 2011, respectively.

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 March 31, 2012, 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 $96 million as of March 31, 2012. Based on current estimates, approximately $23 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 $5 million during the three months ended March 31, 2012 and 2011, 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 for use 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.

As of March 31, 2012, FirstEnergy’s net asset position under commodity derivative contracts was $66 million, which related to FES and AE Supply positions. Under these commodity derivative contracts, FES posted $44 million and AE Supply posted $1 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $16

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million and AE Supply to post $3 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on commodity derivative contracts held as of March 31, 2012, an adverse 10% change in commodity prices would decrease net income by approximately $2 million 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 on FirstEnergy’s Consolidated Balance Sheets:

Derivatives not designated as hedging instruments:
Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	March 31, 2012		December 31, 2011			March 31, 2012			December 31, 2011
	(In millions)					(In millions)
Power Contracts					Power Contracts
Current Assets	$	300	$	185	Current Liabilities	$	(282	)	$	(196	)
Noncurrent Assets	115		79		Noncurrent Liabilities	(66		)	(51		)
FTRs					FTRs
Current Assets	1		1		Current Liabilities	(15		)	(22		)
Noncurrent Assets	—		—		Noncurrent Liabilities	—			(1		)
NUGs	42		56		NUGs	(342		)	(349		)
Other					Other
Current Assets	1		—		Current Liabilities	(2		)	—
Noncurrent Assets	—		—		Noncurrent Liabilities	—			—
Total Derivatives Assets	$	459	$	321	Total Derivatives Liabilities	$	(707	)	$	(619	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2012:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	33	47	(14	)	MWH
FTRs	17	—	17		MWH
NUGs	23	—	23		MWH
Natural Gas Futures	11	—	11		Million British Thermal Units

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The effect of derivative instruments on the Consolidated Statements of Income during the three months ended March 31, 2012 and 2011, are summarized in the following tables:

	Three Months Ended March 31
	Power Contracts			FTRs			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(5	)	$	—		$	—		$	(5	)
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(9	)	$	—		$	—		$	(9	)
Effective Gain (Loss) Reclassified to:
Purchased Power Expense	16			—			—			16
Revenues	(12		)	—			—			(12		)
Fuel Expense	—			—			—			—
Derivatives Not in a Hedging Relationship
2012
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	—		$	—		$	—		$	—
Other Operating Expense	55			5			(2		)	58
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(117		)	—			—			(117		)
Revenues	112			6			—			118
Other Operating Expense	—			(24		)	—			(24		)
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	29		$	—		$	—		$	29
Other Operating Expense	(20		)	1			1			(18		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(37		)	—			—			(37		)
Revenue	10			3			(1		)	12
Other Operating Expense	—			(15		)	—			(15		)

The unrealized and realized gains (losses) on FirstEnergy’s NUG contracts and regulated FTRs not in a hedging relationship for the three months ended March 31, 2012 were ($7) million and $3 million, respectively. The unrealized and realized gains (losses) on FirstEnergy’s NUG contracts and other derivative contracts not in a hedging relationship for the three months ended March 31, 2011 were ($17) million and ($10) million, respectively. These unrealized and realized gains (losses) on NUG contracts and regulated FTRs are subject to regulatory accounting and do not impact earnings.

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The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2012	$	(293	)	$	(8	)	$	(301	)
Additions/Change in value of existing contracts	(79		)	(1		)	(80		)
Settled contracts	72			4			76
Outstanding net asset (liability) as of March 31, 2012	$	(300	)	$	(5	)	$	(305	)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts	(89		)	—			(89		)
Settled contracts	72			(10		)	62
Outstanding net asset (liability) as of March 31, 2011	$	(362	)	$	—		$	(362	)

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

8. REGULATORY MATTERS

STATE REGULATION

Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

MARYLAND

PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions overseen by the MDPSC and a third party monitor. The settlements with respect to residential SOS for PE customers expire on December 31, 2012, but by statute service will continue in the same manner unless changed by order of the MDPSC. The settlement provisions relating to non-residential service have expired but, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS.

On September 29, 2009, the MDPSC opened a 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 December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and subsequently the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids.On April 12, 2012, the MDPSC issued an order requiring certain Maryland electric utilities, but not PE, to enter into a contract for differences, an electricity hedging arrangement, with respect to a 661 MW natural gas-fired combined cycle generation plant to be built in Charles County, Maryland.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by10%and reduce electricity demand by15%, in each case by 2015. 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 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsix-year period. Maryland law only allows for the utility to recover lost distribution revenue attributable to the energy efficiency or demand reduction programs through a base rate case proceeding, and to date such recovery has not been sought or obtained by PE. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving PE's plan with various modifications and follow-up assignments.

Pursuant to a bill passed by the Maryland legislature, the MDPSC proposed rules, based on the product of a working group of

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utilities, regulators, and other interested stakeholders, that create specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The bill requires that the MDPSC 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 required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation.Further comments were filed regarding the proposed rules on March 26, 2012, and at a hearing on April 17, 2012, the MDPSC approved re-publication of the rules as final.

NEW JERSEY

JCP&L currently provides BGS for retail customers that do not choose a third party electric generation supplier and for customers of third party electric generation suppliers, that fail to provide the contracted service. The supply for BGS, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. The most recent BGS auction results, for supply commencing June 1, 2012, were approved by the NJBPU on February 9, 2012.

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time. On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to, among other things, set and modify the schedule, decide upon motions, and otherwise control the conduct of this case, subject to subsequent NJBPU ratification.The schedule in the proceeding provides for briefs to be filed by the parties, the initial brief was filed by the parties on April 26, 2012. A decision is expected to be issued in June 2012. JCP&L is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held to solicit comments regarding the state of preparedness and responsiveness of the EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the report of the consultant is due to be submitted to the NJBPU in July 2012.The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

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;

• a load cap of no less than80%, so that no single supplier is awarded more than80%of the tranches, which also applies to tranches assigned post-auction;

• a6%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, 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, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent 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.

The Ohio Companies filed an application with the PUCO to essentially extend their current ESP for two more years. The Ohio Companies requested PUCO approval by May 2, 2012, so that they may bid megawatts of PJM-qualified energy efficiency and demand response resources into the May 7, 2012, PJM capacity auction for the 2015-2016 planning year or in the alternate by June 20, 2012, which would allow adequate time to implement changes to the bidding schedule to capture a greater amount of generation at historically lower prices for the benefit of customers. The PUCO has set an evidentiary hearing for May 21, 2012; therefore approval by May 2, 2012, is not expected.

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As proposed, the extended ESP would maintain the substantial benefits from the current ESP including:

• Freezing current base distribution rates through May 31, 2016;

• Continuing to provide economic development and assistance to low-income customers for the two-year extension period at the levels established in the existing ESP;

• Providing Percentage of Income Payment Plan customers with a 6 percent generation rate discount;

• Continuing to provide capacity to shopping and non-shopping customers at a market-based price set through an auction process; and

• Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.

As proposed, the extended ESP would provide additional new benefits, including:

• Securing generation supply over a longer period of time to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and

• Extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB 221 through the end of the new ESP period. This will reduce the monthly renewable energy charge for all FirstEnergy Ohio utility customers.

The filing is supported by19parties including: Industrial Energy Users, Ohio Energy Group, PUCO Staff, the City of Akron, Ohio Manufacturers Association, Ohio Partners for Affordable Energy, and the Council of Smaller Enterprises (COSE).

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed theirthree-year portfolio plan, as required by SB221, seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies are in the process of implementing those programs included in the plan, and requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the issue was moot for CEI and TE. The Ohio Companies filed an application for rehearing, which was later denied. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision related to the Ohio Companies'threeyear portfolio plan, including the method for calculating savings and certain changes made by the PUCO to specific programs. The PUCO denied those applications for rehearing, and in that entry included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute. The Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO's new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. On March 2, 2012, the PUCO moved to dismiss the Companies' appeal. The Companies filed their Memorandum in Opposition to the PUCO's Motion, along with their merit brief on March 9, 2012. The PUCO filed its brief on April 27, 2012. The Company now has twenty days to file its reply brief. Oral arguments have not yet been scheduled.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond. On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are currently scheduled to be filed with the PUCO by May 15, 2012. In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies have achieved their in-state solar compliance requirements for 2012.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative electric generation supplier or for customers of alternative electric generation suppliers that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through descending clock auctions, competitive requests

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for proposals and spot market purchases. On November 17, 2011, ME, PN, Penn and WP filed a Joint Petition for Approval of their DSP that will provide the method by which the Pennsylvania Companies will procure the supply for their default service obligations for the period June 1, 2013 through May 31, 2015. A final order must be entered by the PPUC by August 17, 2012.

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, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission losses are refunded. In April 2010, ME and PN 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 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME and PN TSC riders. ME and PN filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss ME and PN Amended Complaint on September 15, 2011 to which ME and PN responded and which remains pending.On February 28, 2012, the Supreme Court of Pennsylvania denied the Petition for Allowance of Appeal.

In each of May 2008, 2009 and 2010, the PPUC approved ME's and PN'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 transmission 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 ME's customers to provide for full recovery by December 31, 2010. Although the ultimate outcome of this matter cannot be determined at this time, ME and PN believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 millionin marginal transmission losses for the period prior to January 1, 2011.

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 (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of ME, PN and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements. On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding, and the ALJ's Recommended Decision was issued on April 19, 2012, recommending that the Joint Settlement be adopted as filed.

In addition, Act 129 required utilities to file a SMIP with the PPUC. 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 its previously approved smart meter deployment plan and certain smart meter dependent aspects of the EE&C Plan. WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. WP also proposed to take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. 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. A joint settlement with all parties based on these terms, with one party retaining the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan, was approved by the PPUC on June 30, 2011. 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 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 concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the PPUC entered a final order on

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December 16, 2011, providing recommendations for components to be included in upcoming DSPs, including: the duration of the programs and the length of associated energy contracts; a customer referral program; a retail opt-in auction; time-of-use rate options provided through contracts with electric generation suppliers; and periodic rate adjustments.Following the issuance of a Tentative Order and comments filed by various parties, the PPUC entered a final order on March 2, 2012 outlining an intermediate work plan. Several suggested models for long-range default service have been presented and were the topic of a March 2012 en banc hearing. It is expected that a tentative order will be issued for comment with a final long-range proposal.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by ME, PN, Penn, WP and FES on March 27, 2012. If implemented these rules could require a significant change in the ways FES, ME, PN, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

WEST VIRGINIA

In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in a proceeding for an annual increase in retail rates that provided for:

• $40 millionannualized base rate increases effective June 29, 2010;

• Deferral of February 2010 storm restoration expenses over a maximumfive-year period;

• Additional$20 millionannualized base rate increase effective in January 2011;

• Decrease of$20 millionin ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and

• 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 January 2011, MP and PE filed an application with the WVPSC seeking to certifythreefacilities as Qualified Energy Resource Facilities for purposes of compliance with their approved plan pursuant to AREPA. The application was approved and thethreefacilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. 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 andthreeNUG facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, have participated in the case in opposition to the petition. The WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. The WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. Oral arguments were heard at the West Virginia Supreme Court on April 10, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC. On April 24, 2012, the FERC ruled that the FERC-jurisdictional contracts are intended to pay only for electric energy and capacity (and not for RECs), and that state law controlled on the issues of determining which entity owns RECs and how they are transferred between entities. The FERC declined to act on the complaints and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court. MP is evaluating whether to seek rehearing of the FERC's order.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC 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 RFC.

FirstEnergy believes that it 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

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develops information about the item and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an item to RFC. Moreover, it is clear that the NERC, RFC 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. 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, 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.On March 22, 2012, NERC concluded the investigation of the matter and forwarded it to NCEA for further review. NCEA is currently evaluating the findings of the investigation. JCP&L is not able to predict what actions, if any, NERC may take with respect to this matter.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and processes to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities - the matter is contentious because costs for facilities built in one transmission zone often are allocated to customers in other transmission zones. During recent years, the debate has focused on the question of the methodology for determining the transmission zones and customers who benefit from a given facility and, if so, whether the methodology can determine the pro rata share of each zone's benefit. While FirstEnergy and other parties argue for a traditional "beneficiary pays" approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. This debate is framed by regulatory and court decisions.In 2007, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identifiednineseparate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the costs. Subsequently, 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 utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis.On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at500kV 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 and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to 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. While most of the matters involved with the move have been resolved, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed; the details of which dispute are discussed below in the "MISO Multi-Value Project Rule Proposal." In addition, FERC denied certain exit fees of ATSI's transmission rate until such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move. ATSI has asked for rehearing of FERC's orders that address the Michigan Thumb transmission project, and the exit fee issue.

ATSI's filings and requests for rehearing on these matters, as well as the pleadings submitted by parties that oppose ATSI's position are currently pending before FERC. Finally, a negotiated agreement that requires ATSI to pay a one-time charge of$1.8 millionfor long term firm transmission rights that - according to the MISO - were payable upon ATSI's exit, is pending before FERC.

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 (not including ATSI or First Energy) jointly filed with FERC a proposed

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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 the MISO's MTEP process. Under MISO's proposal, the costs of “Michigan Thumb” MVP projects that were 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 and charged to ATSI. MISO estimated that approximately$15 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction.

FirstEnergy has filed pleadings in opposition to the MISO's efforts to “socialize” the costs of the Michigan Thumb Project onto ATSI or onto ATSI's customers that assert legal, factual and policy arguments.To date, FERC has responded in a series of orders that require ATSI to absorb the charges for the Michigan Thumb Project.

On October 31, 2011, FirstEnergy filed a Petition of Review of certain of the FERC's orders with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit.

On February 27, 2012, FERC issued its most recent order (February 2012 Order) regarding the Michigan Thumb Project, in which FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. MISO's Schedule 39 tariff is the vehicle through which the MISO plans to charge the Michigan Thumb project costs to ATSI.In the February 2012 Order, FERC directed that settlement negotiations occur. On March 28, 2012, FirstEnergy filed for clarification and rehearing of the February 2012 Order, and such request is pending before the FERC.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

PJM Underfunding FTR Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year, through March 31, 2012, are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. On March 2, 2012, FERC dismissed the complaint without prejudice, pending PJM's publication for stakeholder review and discussion, a report on the causes of the FTR underfunding and potential improvements, including modeling, which could be made to minimize the revenue inadequacy. On March 30, 2012, FES and AE Supply requested rehearing and reconsideration of the March 2, 2012 order, arguing that FERC erred in dismissing the complaint because the root cause of the FTR underfunding is irrelevant to the relief requested in the complaint. That request remains pending before FERC.

FTR Allocation Complaint

On March 26, 2012, FES and AE Supply filed a complaint with FERC against PJM challenging PJM's FTR allocation rules. PJM allocates FTRs to load-serving entities in an annual allocation process, up to each LSE's peak load, based on the expected transmission capability for the upcoming planning year. If a transmission facility is scheduled to be out of service for a significant part of the year, it can result in LSEs' FTR allocations being reduced in the annual allocation. When these transmission facilities return to service during the year PJM will create monthly FTRs to reflect the increased transmission capability during that month. However, instead of allocating these new monthly FTRs to the LSEs that were unable to obtain their full allocation of FTRs in the annual allocation process, PJM's rules instead require PJM to auction off these new monthly FTRs in the market. The complaint seeks a change to the PJM rules such that the new FTRs created each month by transmission lines returning to service would first be allocated to those LSEs that were denied a full allocation of their FTR entitlement in the annual allocation process before they are auctioned off in the market. On April 16, 2012, PJM filed its answer to the complaint. Also, on that date, Exelon Corporation filed a protest to, and several parties filed comments on, FES' and AE Supply's complaint, which remains pending before FERC. On April 30, 2012, FES and AE Supply filed a motion for leave to answer and answer to the various pleadings filed on April 16, 2012.

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 CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor 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 remandedoneof 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

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in the California wholesale power market, including AE Supply (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. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

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. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV 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 the WVPSC, the VSCC and MDPSC. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

Yards Creek

The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. FERC issued a license for authorization to operate the project. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the five-year ILP licensure process. FirstEnergy expects FERC to issue the new license before February 28, 2013. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.

Seneca

The Seneca Pumped Storage Project is a451MW 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 related documents in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and related documents necessary for the Seneca Nation 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,

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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.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology and modeling of the hydrological impacts of project operations.In March of 2012, FirstEnergy hosted a meeting as part of the consultation process. In that meeting, FirstEnergy reviewed its proposed methodology for conducting the hydrological impacts study and answered questions from third parties about the methodology. On April 11, 2012, the Seneca Nation and other parties filed comments on the proposed hydrologic impacts study.The study processes, including the discrete hydrological impacts study, will extend through approximately November 2013.

FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

9. COMMITMENTS, GUARANTEES AND CONTINGENCIES

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. 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 credit support to various providers for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements include provisions for parent guarantees, surety bonds and/or LOCs to be issued by FirstEnergy on behalf of one or more of its subsidiaries. Additionally, certain contracts may contain collateral provisions that are contingent upon either FirstEnergy's or its subsidiaries’ credit ratings.

As of March 31, 2012, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting of parental guarantees ($0.9 billion), subsidiaries' guarantees ($2.5 billion), and other guarantees ($0.7 billion).

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $151 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.

While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As of March 31, 2012, FirstEnergy’s exposure to additional credit contingent contractual obligations was $671 million, as shown below:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade (1)	$	439	$	8	$	59	$	506
Material adverse event (2)	91		60		14		165
Total	$	530	$	68	$	73	$	671

⁽¹⁾  Includes $222 million and $40 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.

⁽²⁾  Includes $42 million that is also considered an acceleration of payment or funding obligation for FES.

Certain bilateral non-affiliate contracts entered into by the Competitive Energy Services segment contain margining provisions that require posting of collateral. Based on FES' and AE Supply's power portfolio exposures as of March 31, 2012, FES and AE Supply have posted collateral of $84 million and $1 million, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES or AE Supply and affiliated utilities in the Regulated Distribution Segment. As of March 31, 2012, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post $54 million and $18 million, respectively.

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

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2012. FirstEnergy, together with WMB Loan Ventures LLC and WMB Loan Ventures II LLC, the entities that originally shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. Following the sale of a portion of FEV's ownership interest in Signal Peak and Global Rail in the fourth quarter of 2011, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding, continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral. In March 2012, after an evaluation of its current operations, business plan and market conditions, the Global Rail Board of Managers opted to focus first on extending its current senior secured term loan facility due in October 2012, before replacing that facility with non-recourse financing. There can be no assurance that the term loan facility will be extended on satisfactory terms or at all.

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 SO₂and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂and 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 or non-emitting plants and/or using emission allowances.

In July 2008,threecomplaints representing multiple plaintiffs were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner.” One complaint was filed on behalf oftwenty-oneindividuals and the other is a class action complaint seeking certification as a class with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

In December 2007, the states of New Jersey and Connecticut filed CAA citizen suits in the U.S. District Court for the Eastern District of Pennsylvania alleging NSR violations at the coal-fired 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 ME in 1999) and ME. 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. The Court dismissed New Jersey's and Connecticut's claims for injunctive relief against ME, but denied ME's motion to dismiss the claims for civil penalties. The parties dispute the scope of ME's indemnity obligation to and from Sithe Energy. In February 2012, GenOn announced its plans to retire the Portland Station in January 2015 citing EPA emissions limits and compliance schedules to reduce SO₂air emissions by approximately81%at the Portland Station by January 6, 2015. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. ME, JCP&L and PN, as former owners of the facilities, are unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In January 2011, the U.S. DOJ filed a complaint against PN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PN based on alleged “modifications” at the coal-fired Homer City generating plant 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, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. 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. In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the states of New Jersey and New York against all of the defendants, including PN. In December 2011, the U.S., the Commonwealth of Pennsylvania and the states of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. PN believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.

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 during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements

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under the PSD and NNSR programs. 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. FGCO intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. In September 2007, AE 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 coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. FirstEnergy intends to vigorously defend against these CAA matters, but cannot predict their outcomes or estimate the possible loss or range of loss.

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 U.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the PSD provisions of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. A non-jury trial on liability only was held in September 2010. The parties are awaiting a decision from the District Court, but there is no deadline for that decision. FirstEnergy is unable to predict the outcome or estimate the possible loss or range of loss.

National Ambient Air Quality Standards

The EPA's CAIR requires reductions of NOx and SO₂emissions intwophases (2009/2010 and 2015), ultimately capping SO₂emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia decided that CAIR violated the CAA but 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 decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO₂emissions intwophases (2012 and 2014), ultimately capping SO₂emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO₂emission allowances between power plants located in the same state and interstate trading of NOx and SO₂emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO₂emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO₂emission allowances. On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Hazardous Air Pollutant Emissions

On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) ofninecoal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349MW (generating, on average, approximatelytenpercent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.

On March 8, 2012, FGCO filed an application for a feasibility study with PJM to install and interconnect to the transmission system approximately 800 megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant retirements and requested Reliability Must-Run arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18. During the three months ended March 31, 2012, FirstEnergy recognized pre-tax severance expense of approximately$7 million (including$4 million by FES) as a result of the closures.

On March 9, 2012, to assist the WVPSC with inquiries from public officials and the public, MP provided information to the WVPSC in the form of a closed entry filing in the ENEC case related to the plant deactivations. On April 2, 2012, the WVPSC issued an order requesting additional information from MP related to the Albright, Rivesville and Willow Island plant deactiviation

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announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations. We anticipate deactivating these units by September 1, 2012.

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. 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 and report GHG emissions commencing in 2010. 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 NSR preconstruction permits would be required including an emissions applicability threshold of75,000tons per year of CO₂equivalents for existing facilities under the CAA's PSD program.

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 belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “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. A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO₂emissions 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-CO₂emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA 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 CWA 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 CWA 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 CWA to reduce fish impingement to a12%annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days 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. 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.

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In April 2011, the U.S. Attorney's Office in Cleveland, Ohio advised FGCO that it is no longer considering prosecution under the CWA 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. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil liability claims for those petroleum spills to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.

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 coal-fired Hatfield's Ferry Plant. These criteria are reflected in the NPDES water discharge permit issued by PA DEP for that project. In January 2009, AE Supply appealed the PA DEP's permitting decision to the EHB, due to estimated costs in excess of$150 million in order to install technology to meet TDS and sulfate limits in the NPDES permit. Environmental Integrity Project and Citizens Coal Council also appealed the NPDES permit seeking to impose more stringent technology-based effluent limitations. In April 2012, a joint motion was filed by the parties informing the EHB of a proposed settlement and seeking the lifting of a portion of the EHB's stay of certain terms of the Hatfield's Ferry Plant's NPDES permit. The joint motion was granted by the EHB on April 27, 2012. The parties intend to memorialize the settlement in a Consent Decree to be lodged with the Commonwealth Court of Pennsylvania. The Consent Decree, if entered by the Commonwealth Court of Pennsylvania, will resolve the disputes concerning the Hatfield's Ferry Plant NPDES permit, including TDS and sulphate limits.

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 would apply only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile 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 approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.

In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin Plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES 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 NPDES permit. MP has appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require 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, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit in the U.S. District Court for the Northern District of West Virginia alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. In April 2012, the parties reached a settlement requiring MP to resolve these CWA citizen suit claims for an immaterial amount. If approved by the Court, a Consent Decree will be entered by the Court to resolve these claims. 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 a60-day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.

FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.

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.

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In December 2009, in an advance 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 proposedtwooptions 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. The LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.

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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.

Certain of our utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. 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 ofMarch 31, 2012, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(including$70 millionapplicable to JCP&L) have been accrued throughMarch 31, 2012. Included in the total are accrued liabilities of approximately$63 millionfor 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.FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofMarch 31, 2012, 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. FirstEnergy Corp. currently maintains a $95 millionparental guaranty in support of the decommissioning of nuclear facilities.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. The NRC subsequently narrowed the scope of admitted contentions in this proceeding to a challenge to the computer code used to model source terms in FENOC's Severe Accident Mitigation Alternatives analysis. On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.The ASLB scheduled a May 18, 2012, oral argument on the petitioner's request for a new contention, but has yet to rule on the admission of this contention.

On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.

On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.

By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the

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root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.

On March 12, 2012, the NRC Staff issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities.

On February 16, 2012, the NRC issued a request for information to the licensed operators of11nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in higher burn up fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer and that the NRC might consider imposing restrictions on reactor operating limits.On March 16, 2012, FENOC submitted its response to the NRC demonstrating that the NRC requirements are being met. FENOC also agreed to submit to the NRC revised large break loss of coolant accident analyses by December 15, 2016, that further consider the effects of fuel pellet thermal conductivity degradation.

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and 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 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor 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 millionin future damages and$14 million for replacement coal / interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal.Briefing on the Appeal is concluded with oral argument scheduled for May 16, 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

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 had been approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction. The court granted the motion to dismiss and the plaintiffs appealed the decision to the Court of Appeals of Ohio. The Court of Appeals affirmed the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud which it remanded to the trial court. The Companies timely filed a notice of appeal with the Supreme Court of Ohio on December 5, 2011, challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio agreed to hear the appeal.

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 under Note 8, Regulatory Matters to the Combined Notes to the Consolidated Financial Statements.

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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, 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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10. 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 and Comprehensive Income for the three months endedMarch 31, 2012 and 2011, Consolidating Balance Sheets as of March 31, 2012 and December 31, 2011 and Consolidating Statements of Cash Flows for the three months ended March 31, 2012 and 2011 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 AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,490		$	542		$	394		$	(910	)	$	1,516
OPERATING EXPENSES:
Fuel	—			240			55			—			295
Purchased power from affiliates	965			—			62			(910		)	117
Purchased power from non-affiliates	487			—			—			—			487
Other operating expenses	76			92			116			11			295
Provision for depreciation	1			30			34			(2		)	63
General taxes	20			10			7			—			37
Total operating expenses	1,549			372			274			(901		)	1,294
OPERATING INCOME (LOSS)	(59		)	170			120			(9		)	222
OTHER INCOME (EXPENSE):
Investment income	1			4			5			(4		)	6
Miscellaneous income, including net income from equity investees	258			—			—			(254		)	4
Interest expense — affiliates	(4		)	(1		)	(1		)	4			(2		)
Interest expense — other	(23		)	(26		)	(7		)	15			(41		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	232			(22		)	5			(239		)	(24		)
INCOME BEFORE INCOME TAXES	173			148			125			(248		)	198
INCOME TAXES (BENEFITS)	51			(1		)	23			3			76
NET INCOME	$	122		$	149		$	102		$	(251	)	$	122
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	122		$	149		$	102		$	(251	)	$	122
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized loss on derivative hedges	(5		)	—			—			—			(5		)
Change in unrealized gain on available for sale securities	10			—			10			(10		)	10
Other comprehensive income (loss)	—			(4		)	10			(6		)	—
Income taxes (benefits) on other comprehensive income (loss)	2			(2		)	4			(2		)	2
Other comprehensive income (loss), net of tax	(2		)	(2		)	6			(4		)	(2		)
COMPREHENSIVE INCOME	$	120		$	147		$	108		$	(255	)	$	120

45

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,366		$	743		$	469		$	(1,187	)	$	1,391
OPERATING EXPENSES:
Fuel	1			294			48			—			343
Purchased power from affiliates	1,185			2			69			(1,187		)	69
Purchased power from non-affiliates	297			—			—			—			297
Other operating expenses	162			111			180			12			465
Provision for depreciation	1			32			38			(2		)	69
General taxes	10			11			8			—			29
Impairment of long-lived assets	—			14			—			—			14
Total operating expenses	1,656			464			343			(1,177		)	1,286
OPERATING INCOME (LOSS)	(290		)	279			126			(10		)	105
OTHER INCOME (EXPENSE):
Investment income	1			—			5			—			6
Miscellaneous income, including net income from equity investees	242			1			—			(239		)	4
Interest expense — affiliates	(1		)	—			—			—			(1		)
Interest expense — other	(24		)	(28		)	(17		)	16			(53		)
Capitalized interest	—			5			5			—			10
Total other income (expense)	218			(22		)	(7		)	(223		)	(34		)
INCOME (LOSS) BEFORE INCOME TAXES	(72		)	257			119			(233		)	71
INCOME TAXES (BENEFITS)	(117		)	96			45			2			26
NET INCOME	$	45		$	161		$	74		$	(235	)	$	45
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	45		$	161		$	74		$	(235	)	$	45
OTHER COMPREHENSIVE INCOME
Pensions and OPEB prior service costs	(10		)	(4		)	(6		)	10			(10		)
Amortized loss on derivative hedges	(9		)	—			—			—			(9		)
Change in unrealized gain on available for sale securities	8			—			8			(8		)	8
Other comprehensive income (loss)	(11		)	(4		)	2			2			(11		)
Income taxes (benefits) on other comprehensive income (loss)	(6		)	(2		)	1			1			(6		)
Other comprehensive income (loss), net of tax	(5		)	(2		)	1			1			(5		)
COMPREHENSIVE INCOME	$	40		$	159		$	75		$	(234	)	$	40

46

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of March 31, 2012	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	395		—		—		—			395
Affiliated companies	472		439		241		(611		)	541
Other	50		19		53		—			122
Notes receivable from affiliated companies	81		1,369		44		(1,482		)	12
Materials and supplies, at average cost	62		283		206		—			551
Derivatives	322		—		—		—			322
Prepayments and other	7		17		1		(1		)	24
	1,389		2,134		545		(2,094		)	1,974
PROPERTY, PLANT AND EQUIPMENT:
In service	84		5,614		5,689		(385		)	11,002
Less — Accumulated provision for depreciation	29		1,843		2,524		(182		)	4,214
	55		3,771		3,165		(203		)	6,788
Construction work in progress	31		171		971		—			1,173
	86		3,942		4,136		(203		)	7,961
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,240		—			1,240
Investment in affiliated companies	5,956		—		—		(5,956		)	—
Other	—		7		—		—			7
	5,956		7		1,240		(5,956		)	1,247
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		274		—		(274		)	—
Customer intangibles	120		—		—		—			120
Goodwill	24		—		—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		21		—		99			120
Derivatives	117		—		—		—			117
Other	123		111		2		(65		)	171
	384		426		25		(240		)	595
	$	7,815	$	6,509	$	5,946	$	(8,493	)	$	11,777
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	411	$	514	$	(21	)	$	905
Short-term borrowings-
Affiliated companies	1,413		69		—		(1,482		)	—
Accounts payable-
Affiliated companies	663		175		256		(611		)	483
Other	69		121		—		—			190
Accrued Taxes	31		33		24		(13		)	75
Derivatives	281		—		—		—			281
Other	38		111		24		72			245
	2,496		920		818		(2,055		)	2,179
CAPITALIZATION:
Total equity	3,695		3,244		2,697		(5,941		)	3,695
Long-term debt and other long-term obligations	1,482		1,903		641		(1,229		)	2,797
	5,177		5,147		3,338		(7,170		)	6,492
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		917			917
Accumulated deferred income taxes	18		—		532		(185		)	365
Asset retirement obligations	—		28		891		—			919
Retirement benefits	31		120		—		—			151
Lease market valuation liability	—		160		—		—			160
Other	93		134		367		—			594
	142		442		1,790		732			3,106
	$	7,815	$	6,509	$	5,946	$	(8,493	)	$	11,777

47

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2011	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	424		—		—		—			424
Affiliated companies	476		643		262		(781		)	600
Other	28		20		13		—			61
Notes receivable from affiliated companies	155		1,346		69		(1,187		)	383
Materials and supplies, at average cost	60		232		200		—			492
Derivatives	219		—		—		—			219
Prepayments and other	11		26		1		—			38
	1,373		2,274		545		(1,968		)	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	84		5,573		5,711		(385		)	10,983
Less — Accumulated provision for depreciation	28		1,813		2,449		(180		)	4,110
	56		3,760		3,262		(205		)	6,873
Construction work in progress	29		195		790		—			1,014
	85		3,955		4,052		(205		)	7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,223		—			1,223
Investment in affiliated companies	5,716		—		—		(5,716		)	—
Other	—		7		—		—			7
	5,716		7		1,223		(5,716		)	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	10		307		—		(317		)	—
Customer intangibles	123		—		—		—			123
Goodwill	24		—		—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		5		—		75			80
Derivatives	79		—		—		—			79
Other	89		99		3		(62		)	129
	325		431		26		(304		)	478
	$	7,499	$	6,667	$	5,846	$	(8,193	)	$	11,819
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	411	$	513	$	(20	)	$	905
Short-term borrowings-
Affiliated companies	1,065		89		32		(1,186		)	—
Accounts payable-
Affiliated companies	777		228		211		(780		)	436
Other	99		121		—		—			220
Accrued Taxes	84		42		110		(9		)	227
Derivatives	189		—		—		—			189
Other	62		141		16		42			261
	2,277		1,032		882		(1,953		)	2,238
CAPITALIZATION:
Common stockholder’s equity	3,593		3,097		2,587		(5,700		)	3,577
Long-term debt and other long-term obligations	1,483		1,905		641		(1,230		)	2,799
	5,076		5,002		3,228		(6,930		)	6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		925			925
Accumulated deferred income taxes	12		—		510		(236		)	286
Asset retirement obligations	—		28		876		—			904
Retirement benefits	56		300		—		—			356
Lease market valuation liability	—		171		—		—			171
Other	78		134		350		1			563
	146		633		1,736		690			3,205
	$	7,499	$	6,667	$	5,846	$	(8,193	)	$	11,819

48

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(419	)	$	66		$	175		$	—		$	(178	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	347			—			—			(347		)	—
Redemptions and Repayments-
Short-term borrowings, net	—			(20		)	(32		)	52			—
Other	—			(2		)	(1		)	—			(3		)
Net cash provided from (used for) financing activities	347			(22		)	(33		)	(295		)	(3		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(18		)	(161		)	—			(181		)
Sales of investment securities held in trusts	—			—			83			—			83
Purchases of investment securities held in trusts	—			—			(90		)	—			(90		)
Loans to affiliated companies, net	74			(23		)	25			295			371
Other	—			(3		)	1			—			(2		)
Net cash provided from (used for) investing activities	72			(44		)	(142		)	295			181
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—		$	7

49

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2011	FES			FGCO			NGC			Eliminations		Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(215	)	$	267		$	42		$	—	$	94
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			90			60			—		150
Short-term borrowings, net	322			28			—			—		350
Redemptions and Repayments-
Long-term debt	(131		)	(141		)	(60		)	—		(332		)
Other	(1		)	—			—			—		(1		)
Net cash used for financing activities	190			(23		)	—			—		167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(3		)	(40		)	(116		)	—		(159		)
Sales of investment securities held in trusts	—			—			216			—		216
Purchases of investment securities held in trusts	—			—			(231		)	—		(231		)
Loans to affiliated companies, net	28			(200		)	90			—		(82		)
Customer acquisition costs	—			—			—			—		—
Other	—			(6		)	(1		)	—		(7		)
Net cash provided from (used for) investing activities	25			(246		)	(42		)	—		(263		)
Net change in cash and cash equivalents	—			(2		)	—			—		(2		)
Cash and cash equivalents at beginning of period	—			9			—			—		9
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—	$	7

50

11. SEGMENT INFORMATION

FirstEnergy has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below, which includes financial results for Allegheny subsidiaries beginning February 25, 2011. FES, OE and JCP&L 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 65,000 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, ME, PN, 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. Its results reflect the commodity costs of securing electric generation 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 formulaic rates that recover costs and provide 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 revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

The Competitive Energy Services segment, through FES and AE Supply, supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. This business segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012 (see Note 8, Regulatory Matters of the Combined Notes to Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from 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.

Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. Reconciling adjustments primarily consist of elimination of intersegment transactions.

51

Segment Financial Information

Three Months Ended	Regulated Distribution		Competitive Energy Services		Regulated Independent Transmission		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
March 31, 2012
External revenues	$	2,383	$	1,607	$	109	$	(24	)	$	1		$	4,076
Internal revenues	—		268		—		—			(266		)	2
Total revenues	2,383		1,875		109		(24		)	(265		)	4,078
Depreciation and amortization	234		100		18		8			—			360
Investment income	24		6		—		—			(19		)	11
Net interest charges	142		54		12		21			—			229
Income taxes	108		83		20		(16		)	27			222
Net income	183		141		34		(28		)	(24		)	306
Total assets	27,551		17,187		2,452		501			—			47,691
Total goodwill	5,551		893		—		—			—			6,444
Property additions	301		243		28		17			—			589
March 31, 2011
External revenues	$	2,268	$	1,254	$	67	$	(23	)	$	(22	)	$	3,544
Internal revenues	—		343		—		—			(311		)	32
Total revenues	2,268		1,597		67		(23		)	(333		)	3,576
Depreciation and amortization	250		88		13		6			—			357
Investment income	25		6		—		—			(10		)	21
Net interest charges	131		68		9		19			(14		)	213
Income taxes	64		9		7		—			31			111
Net income	109		15		12		(55		)	(34		)	47
Total assets	27,766		17,399		2,486		914			—			48,565
Total goodwill	5,551		956		—		—			—			6,507
Property additions	177		214		27		31			—			449

52

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

OVERVIEW

Earnings Available to FirstEnergy Corp. in the first quarter of 2012 were $306 million, or basic and diluted earnings of $0.73 per share of common stock, compared with $52 million, or basic and diluted earnings of $0.15 per share of common stock in the first quarter of 2011. The principal reasons for the changes in basic earnings per share are summarized below.

Change In Basic Earnings Per Share From Prior Year	Three Months Ended March 31
Basic Earnings Per Share - First Quarter 2011	$	0.15
Segment operating results(1) -
Regulated Distribution	(0.03		)
Competitive Energy Services	0.04
Regulated Independent Transmission	0.01
Regulatory charges	(0.01		)
Income Tax Charge – retiree prescription drug subsidy	(0.02		)
Merger-related costs	0.37
Impact of non-core asset sales/impairments	0.03
Mark-to-market adjustments	0.08
Merger accounting — commodity contracts	(0.01		)
Plant closing costs	(0.05		)
Net merger accretion(1)(2)	0.17
Interest expense, net of amounts capitalized	0.02
Investment Income	(0.01		)
Other	(0.01		)
Basic Earnings Per Share - First Quarter 2012	$	0.73

⁽¹⁾  Excludes amounts that are shown separately

⁽²⁾  Includes dilutive effect of shares issued in connection with the Allegheny merger, and 3 months of Allegheny results in the first quarter of 2012 compared to 1 month during the same period of 2011.

Financial Matters

On April 2, 2012, FGCO and NGC refinanced $52.1 million and $29.5 million, respectively, of PCRBs. The bonds were converted from a fixed-rate mandatory put mode to a variable-rate mode enhanced with a 3-year LOC. Additionally, on April 2, 2012, FGCO and NGC remarketed $146.7 million and $315 million of PCRBs, respectively, in a variable rate mode enhanced with a LOC.

On April 16, 2012, WP issued $100 million of FMBs through a private placement at a rate of 3.34%. These bonds have a maturity date of April 15, 2022, and the proceeds were used in part to retire $80 million of 6.625% medium term notes that matured on April 16, 2012.

On April 16, 2012, AE Supply retired $503.2 million of 8.25% medium term notes at maturity.

Operational Matters

Request for New Generation

On March 8, 2012, FGCO filed an application for a feasibility study with PJM Interconnection to install and interconnect to the transmission system approximately 800 MW of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant retirements and requested Reliability Must-Run arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18.

53

Root Cause Analysis Completed for Davis-Besse

On February 28, 2012, FENOC announced it completed its Root Cause Analysis Report regarding the hairline cracks identified in portions of the Davis-Besse Shield Building during the fall 2011 reactor head replacement outage. The report was submitted to the NRC and concluded that based on extensive evaluation, the structural integrity of the shield building remains intact and the building is able to perform its safety function.

Regulatory Matters

Ohio Utilities File to Extend Electric Security Plan

FE's Ohio Companies filed an application with the PUCO to essentially extend their current ESP for two more years. If approved by the PUCO, the extension would allow the Ohio Companies to establish electricity prices for their customers through May 31, 2016. The Ohio Companies requested PUCO approval by May 2, 2012, so that they may bid megawatts of PJM-qualified energy efficiency and demand response resources into the May 7, 2012, PJM capacity auction for the 2015-2016 planning year or in the alternate by June 20 which would be too late to bid a portion of the demand resources into the May 7, 2012, PJM capacity auction but would allow adequate time to implement changes to the bidding schedule to capture a greater amount of generation at historically lower prices for the benefit of customers. The PUCO has set an evidentiary hearing for May 21, 2012; therefore approval by May 2, 2012, is not expected.

As proposed, the extended ESP would maintain the substantial benefits from the current ESP including:

• Freezing current base distribution rates through May 31, 2016;

• continuing to provide economic development and assistance to low-income customers for the two-year extension period at the levels established in the existing ESP;

• providing Percentage of Income Payment Plan customers with a 6 percent generation rate discount;

• continuing to provide capacity to shopping and non-shopping customers at a market-based price set through an auction process; and

• continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.

As proposed, the extended ESP would provide additional new benefits, including:

• Securing generation supply over a longer period to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and

• extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB221 through the end of the new ESP period. This will reduce the monthly renewable energy charge for all of the FirstEnergy Ohio utility customers.

The filing is supported by 19 parties including: Industrial Energy Users, Ohio Energy Group, PUCO Staff, the City of Akron, Ohio Manufacturers Association, Ohio Partners for Affordable Energy, and the Council of Smaller Enterprises (COSE).

FIRSTENERGY’S BUSINESS

FirstEnergy has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below, which includes financial results for the Allegheny subsidiaries beginning February 25, 2011. FES, OE and JCP&L 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 65,000 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, ME, PN, 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. Its results reflect the commodity costs of securing electric generation 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 formulaic rates that recover costs and provide 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 revenue from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

The Competitive Energy Services segment, through FES and AE Supply, supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan,

54

New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. This business segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012, (see Note 8, Regulatory Matters, of the Combined Notes to Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from 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.

Other and Reconciling Adjustments 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. See Note 11, Segment Information, of the Combined Notes to Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.

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 (FE and its subsidiaries prior to the merger) have been segregated from the Allegheny companies for variance reporting and analysis. Results of operations for the three months ended March 31, 2011, include only one month of Allegheny results. In addition, Allegheny's results were affected by many of the same factors that influenced the operating results of the pre-merged companies. A reconciliation of segment financial results is provided in Note 11, Segment Information, to the Combined Notes to Consolidated Financial Statements. Earnings available to FirstEnergy by business segment were as follows:

	Three Months Ended March 31
	2012			2011			Increase (Decrease)
	(In millions, except per share data)
Earnings (Loss) By Business Segment:
Regulated Distribution	$	183		$	109		$	74
Competitive Energy Services	141			15			126
Regulated Independent Transmission	34			12			22
Other and reconciling adjustments*	(52		)	(84		)	32
Earnings available to FirstEnergy Corp.	$	306		$	52		$	254
Basic Earnings Per Share	$	0.73		$	0.15		$	0.58
Diluted Earnings Per Share	$	0.73		$	0.15		$	0.58

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

55

Summary of Results of Operations — First Quarter 2012 Compared with First Quarter 2011

Financial results for FirstEnergy’s business segments in the first quarter of 2012 and 2011 were as follows:

First Quarter 2012 Financial Results	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,270		$	1,531		$	—		$	—		$	3,801
Other	113			76			109			(23		)	275
Internal	—			268			—			(266		)	2
Total Revenues	2,383			1,875			109			(289		)	4,078
Operating Expenses:
Fuel	39			502			—			—			541
Purchased power	1,082			531			—			(266		)	1,347
Other operating expenses	427			409			15			(39		)	812
Provision for depreciation	159			100			18			8			285
Amortization of regulatory assets, net	75			—			—			—			75
General taxes	192			61			10			9			272
Total Operating Expenses	1,974			1,603			43			(288		)	3,332
Operating Income	409			272			66			(1		)	746
Other Income (Expense):
Investment income	24			6			—			(19		)	11
Interest expense	(145		)	(65		)	(12		)	(24		)	(246		)
Capitalized interest	3			11			—			3			17
Total Other Expense	(118		)	(48		)	(12		)	(40		)	(218		)
Income Before Income Taxes	291			224			54			(41		)	528
Income taxes	108			83			20			11			222
Net Income	183			141			34			(52		)	306
Loss attributable to noncontrolling interest	—			—			—			—			—
Earnings Available to FirstEnergy Corp.	$	183		$	141		$	34		$	(52	)	$	306

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First Quarter 2011 Financial Results	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,175		$	1,162		$	—		$	—		$	3,337
Other	93			92			67			(45		)	207
Internal	—			343			—			(311		)	32
Total Revenues	2,268			1,597			67			(356		)	3,576
Operating Expenses:
Fuel	24			429			—			—			453
Purchased power	1,179			318			—			(311		)	1,186
Other operating expenses	360			632			18			(17		)	993
Provision for depreciation	121			88			10			6			225
Amortization of regulatory assets, net	129			—			3			—			132
General taxes	176			44			8			9			237
Total Operating Expenses	1,989			1,511			39			(313		)	3,226
Operating Income	279			86			28			(43		)	350
Other Income (Expense):
Investment income	25			6			—			(10		)	21
Interest expense	(132		)	(78		)	(9		)	(12		)	(231		)
Capitalized interest	1			10			—			7			18
Total Other Expense	(106		)	(62		)	(9		)	(15		)	(192		)
Income Before Income Taxes	173			24			19			(58		)	158
Income taxes	64			9			7			31			111
Net Income	109			15			12			(89		)	47
Loss attributable to noncontrolling interest	—			—			—			(5		)	(5		)
Earnings Available to FirstEnergy Corp.	$	109		$	15		$	12		$	(84	)	$	52

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Changes Between First Quarter 2012 and First Quarter 2011 Financial Results Increase (Decrease)	Regulated Distribution			Competitive Energy Services			Regulated Independent Transmission			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	95		$	369		$	—		$	—		$	464
Other	20			(16		)	42			22			68
Internal	—			(75		)	—			45			(30		)
Total Revenues	115			278			42			67			502
Operating Expenses:
Fuel	15			73			—			—			88
Purchased power	(97		)	213			—			45			161
Other operating expenses	67			(223		)	(3		)	(22		)	(181		)
Provision for depreciation	38			12			8			2			60
Amortization of regulatory assets, net	(54		)	—			(3		)	—			(57		)
General taxes	16			17			2			—			35
Total Operating Expenses	(15		)	92			4			25			106
Operating Income	130			186			38			42			396
Other Income (Expense):
Investment income	(1		)	—			—			(9		)	(10		)
Interest expense	(13		)	13			(3		)	(12		)	(15		)
Capitalized interest	2			1			—			(4		)	(1		)
Total Other Expense	(12		)	14			(3		)	(25		)	(26		)
Income Before Income Taxes	118			200			35			17			370
Income taxes	44			74			13			(20		)	111
Net Income	74			126			22			37			259
Loss attributable to noncontrolling interest	—			—			—			5			5
Earnings Available to FirstEnergy Corp.	$	74		$	126		$	22		$	32		$	254

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Regulated Distribution — First Quarter 2012 Compared with First Quarter 2011

Net income increased by $74 million in the first quarter of 2012 compared to the same period of 2011, primarily due to earnings from the Allegheny companies and lower merger-related costs, partially offset by decreased weather-related customer usage in the first quarter of 2012.

Revenues —

The increase in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Pre-merger companies:
Distribution services	$	766	$	909	$	(143	)
Generation sales:
Retail	696		873		(177		)
Wholesale	49		116		(67		)
Total generation sales	745		989		(244		)
Transmission	84		37		47
Other	42		58		(16		)
Total pre-merger companies	1,637		1,993		(356		)
Allegheny companies(1)	746		275		471
Total Revenues	$	2,383	$	2,268	$	115

⁽¹⁾  Allegheny results include 3 months in 2012 and 1 month in 2011.

The decrease in distribution services revenue for the pre-merger companies primarily reflects lower distribution revenues due to lower distribution deliveries (described below), the suspension of Ohio's deferred distribution rider in September 2011, and an NJBPU-approved rate reduction that became effective March 1, 2011, for all of JCP&L's customer classes, partially offset by Ohio's Demand Side Energy Rider that was effective in May 2011. Distribution deliveries (excluding the Allegheny companies) decreased by 3.6% in the first quarter of 2012 from the same period of 2011. Distribution deliveries by customer class are summarized in the following table:

	Three Months Ended March 31		Increase
Electric Distribution MWH Deliveries	2012	2011	(Decrease)
	(in thousands)
Pre-merger companies:
Residential	9,794	10,638	(7.9	)%
Commercial	7,801	7,929	(1.6	)%
Industrial	8,820	8,841	(0.3	)%
Other	123	130	(4.9	)%
Total pre-merger companies	26,538	27,538	(3.6	)%
Allegheny companies(1)	10,659	3,540	201.1	%
Total Electric Distribution MWH Deliveries	37,197	31,078	19.7	%

⁽¹⁾  Allegheny results include 3 months in 2012 and 1 month in 2011.

Lower deliveries to residential and commercial customers for the pre-merged companies reflect decreased weather-related usage resulting from heating degree days that were 25% below 2011 levels, slightly offset by load growth in first quarter of 2012 compared to the same period of 2011. In the industrial sector, MWH deliveries decreased by 2% to petroleum customers, 5% to chemical customers and 6% to electrical equipment customers, partially offset by an increase of 3% to steel customers.

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The following table summarizes the price and volume factors contributing to the $244 milliondecrease in generation revenues for the pre-merger companies in the first quarter of 2012 compared to the same period of 2011:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(206	)
Change in prices	29
	(177		)
Wholesale:
Effect of decrease in sales volumes	(46		)
Change in prices	(21		)
	(67		)
Net Decrease in Generation Revenues	$	(244	)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the service territories of the pre-merger companies in the first quarter of 2012, compared with the same period of 2011. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 77% from 73% for the Ohio Companies and to 59% from 42% for ME’s, PN’s and Penn's service areas.

The decrease in wholesale generation revenues of $67 million in the first quarter of 2012 was a result of the expiration of a NUG contract in August 2011 and lower PJM market prices.

Transmission revenues increased $47 million primarily due tothe implementation of Ohio's non-market based (NMB) transmission rider in June of 2011, which recovers network integration transmission service charges as described below.

The Allegheny companies added $471 million in revenues for the first quarter of 2012 compared to the first quarter of 2011, including $142 million from distribution services, $305million from generation sales and $17 million from transmission services.

Operating Expenses —

Total operating expenses decreased by $15 million due to the following:

• Purchased power costs, excluding the Allegheny companies, were $338 millionlower in the first quarter of 2012 due primarily to a decrease in volumes required resulting from warmer than normal weather. Additionally, increased customer shopping decreased purchased power requirements. The Allegheny companies added $241 million in purchased power costs in the first quarter of 2012 compared to the same period of 2011.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs	$	(43	)
Change due to decreased volumes	(182		)
	(225		)
Purchases from FES:
Change due to decreased unit costs	(15		)
Change due to decreased volumes	(93		)
	(108		)
Increase in costs deferred	(5		)
Total pre-merger companies	(338		)
Purchases by Allegheny companies	241
Net Decrease in Purchased Power Costs	$	(97	)

• Transmission expenses increased $57 million during the first quarter of 2012 compared to the same period of 2011. The increase is primarily due to network integration transmission service expenses that, prior to June 2011, were incurred by

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the generation supplier, and are now being recovered through the NMB transmission rider discussed above.

• Amortization expense decreased $65 million due to the following:

◦ The suspension of the rider recovering deferred distribution costs in September 2011,

◦ The completion of JCP&L's NUG deferred cost recovery,

◦ Partially offset by the recovery in Ohio of residential generation credits for electric heating discounts, which began in September 2011.

• Energy Efficiency program costs, which are recovered through rates, increased by $27 million.

• The absence of a provision for excess and obsolete material of $13 million that was recognized in the first quarter of 2011 relating to revised inventory practices adopted in conjunction with the Allegheny merger.

• Merger-related costs decreased $55 million in the first quarter of 2012 compared to the same period of 2011.

• The inclusion of Allegheny resulted in the following net increase in operating expenses in the first quarter of 2012:

	Three Months Ended March 31					Increase
Operating Expenses - Allegheny(1)	2012		2011			(Decrease)
	(In millions)
Purchased power	$	383	$	143		$	241
Fuel	39		24			15
Transmission	26		12			14
Amortization of regulatory assets, net	—		(11		)	11
Other operating expenses	80		32			48
General taxes	34		12			22
Depreciation expense	49		16			33
Total Operating Expenses	$	611	$	228		$	384

⁽¹⁾  Allegheny results include 3 months in 2012 and 1 month in 2011.

Other Expense —

Other expense increased $12 million in the first quarter of 2012 primarily due to interest expense on debt of the Allegheny companies.

Regulated Independent Transmission — First Quarter 2012 Compared with First Quarter 2011

Net income increased by $22 million in the first quarter of 2012 compared to the same period of 2011 primarily due to earnings associated with TrAIL and PATH acquired in the Allegheny merger.

Revenues —

Total revenues increased by $42 million principally due to revenues from TrAIL and PATH.

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

Revenues by	Three Months Ended March 31				Increase
Transmission Asset Owner	2012		2011		(Decrease)
	(In millions)
ATSI	$	53	$	52	$	1
TrAIL(1)	51		14		37
PATH(1)	5		1		4
Total Revenues	$	109	$	67	$	42

⁽¹⁾  Allegheny results include 3 months in 2012 and 1 month in 2011.

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Operating Expenses —

Total operating expenses increased by $4 million principally due to the addition of TrAIL and PATH operating expenses for a full quarter in 2012 ($7 million), partially offset by the completion in May 2011 of ATSI deferred vegetation management cost recovery ($3 million).

Other Expense —

Other expense increased $3 million in the first quarter of 2012 due to higher interest expense, principally associated with debt of TrAIL.

Competitive Energy Services — First Quarter 2012 Compared with First Quarter 2011

Net income increased by $126 million in the first quarter of 2012, compared to the same period of 2011, due to higher retail revenues, lower operating expenses and the inclusion of the results of the Allegheny companies for a full quarter.

Revenues —

Total revenues increased by $278 million in the first quarter of 2012 primarily due to growth in combined direct and governmental aggregation sales and the inclusion of the Allegheny companies for a full quarter, partially offset by a net decline in POLR and structured sales.

The increase in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	1,007	$	840	$	167
POLR and Structured Sales	231		374		(143		)
Wholesale(1)	160		91		69
Transmission	31		26		5
RECs	5		32		(27		)
Other	21		41		(20		)
Allegheny Companies(2)	420		193		227
Total Revenues	$	1,875	$	1,597	$	278
Allegheny Companies(2)
Direct and Governmental Aggregation	$	23	$	9	$	14
POLR and Structured Sales	149		68		81
Wholesale(1)	224		91		133
Transmission	16		12		4
Other	8		13		(5		)
Total Revenues	$	420	$	193	$	227
(1) Includes $55 million in intra-segment sales by AE Supply to FES
(2) Allegheny results include 3 months in 2012 and 1 month in 2011.

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	Three Months Ended March 31		Increase
MWH Sales by Type of Service	2012	2011	(Decrease)
	(In thousands)
Direct	12,391	9,671	28.1	%
Governmental Aggregation	5,186	4,310	20.3	%
POLR and Structured Sales	4,030	5,843	(31.0	)%
Wholesale	21	985	(97.9	)%
Allegheny Companies(1)	6,520	2,636	147.3	%
Total Sales	28,148	23,445	20.1	%
Allegheny Companies(1)
Direct and Governmental Aggregation	388	145	167.6	%
POLR	2,459	812	202.8	%
Structured Sales	156	303	(48.5	)%
Wholesale	3,517	1,376	155.6	%
Total Sales	6,520	2,636	147.3	%
(1) Allegheny results include 3 months in 2012 and 1 month in 2011.

The increase in combined direct and governmental aggregation revenues of $167 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio and Illinois that provided generation to approximately 1.9 million residential and small commercial customers as of March 2012, compared to approximately 1.5 million as of March 2011. These increases were partially offset by lower sales to residential and small commercial customers as a result of weather that was 25% warmer this year in the markets served compared to 2011.

The decrease in combined POLR and structured revenues of $143 million was due primarily to lower sales volumes to the Ohio Companies, ME and PN. Revenues were also adversely impacted by lower unit prices which were partially offset by increased structured sales. The decline in POLR sales reflects our continued focus on other sales channels.

Wholesale revenues increased $69 million due to a $55 million gain on financially settled contracts and a $43 million increase in capacity revenues. These increases were partially offset by decreased short-term (net hourly positions) transactions in MISO.

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

Source of Change in Direct and Governmental Aggregation	Increase (Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	159
Change in prices	(43		)
	116
Governmental Aggregation:
Effect of increase in sales volumes	55
Change in prices	(4		)
	51
Net Increase in Direct and Governmental Aggregation Revenues	$	167

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of decrease in sales volumes	$	(116	)
Change in prices	(27		)
	$	(143	)

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Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(28	)
Change in prices	(1		)
Gain on settled contracts	55
Capacity revenue	43
	$	69

Transmission revenues increased by $5 million primarily due to higher PJM congestion and ancillary revenue. The revenues derived from the sale of RECs decreased by $27 million in the first quarter of 2012.

Operating Expenses —

Total operating expenses increased by $92 million in the first quarter of 2012. Excluding the results of the Allegheny companies, operating expenses decreased $54 million due to the following:

• Purchased power costs increased $191 million due to higher volumes ($103 million), loss on settled contracts ($106 million) and capacity expense ($54 million), partially offset by lower unit prices ($72 million). The increase in purchased power volumes primarily relates to the overall increase in sales volumes and economic purchases.

• Fuel costs decreased $33 million primarily due to lower volumes consumed ($83 million), partially offset by higher unit prices ($50 million). Volumes decreased due to lower fossil generation, partially offset by higher generation from the nuclear units.

• Fossil operating costs decreased by $7 million due primarily to lower contractor and materials and equipment costs resulting from a decrease in planned and unplanned outages, partially offset by higher labor costs.

• Nuclear operating costs decreased by $28 million due primarily to lower labor, contractor and materials and equipment costs, as there were no refueling outages this quarter while the first quarter of the previous year included the Beaver Valley Unit 2 refueling outage.

• Transmission expenses decreased $62 million due primarily to decreases of $68 million from lower congestion, network and line loss costs in MISO. These decreases were partially offset by increases in PJM of $6 million from higher network costs, partially offset by lower congestion and line loss expenses.

• General taxes increased by $6 million due to an increase in revenue-related taxes.

• Depreciation expense decreased $11 million primarily due to credits resulting from a settlement with the DOE regarding the storage of spent nuclear fuel.

• Other operating expenses decreased by $110 million primarily due to favorable mark-to-market adjustments on commodity contract positions ($28 million) and reduced corporate-related costs associated with the merger ($14 million). In addition, 2011 expenses included a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger and a $13 million impairment charge related to non-core assets.

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The inclusion of the Allegheny companies’ operations for three months in 2012 and one month in 2011 contributed $357 million and $211 million to operating expenses in 2012 and 2011, respectively, as shown in the following table:

	Three Months Ended March 31					Increase
Operating Expenses (Credits) - Allegheny(1)	2012			2011		(Decrease)
	(In millions)
Fuel	$	188		$	82	$	106
Purchased power	43			21		22
Fossil generation	45			27		18
Transmission	32			24		8
Other operating expenses	16			8		8
Mark-to-market adjustments	(16		)	34		(50		)
General taxes	15			4		11
Depreciation	34			11		23
Total Operating Expense	$	357		$	211	$	146
(1) Allegheny results include 3 months in 2012 and 1 month in 2011.

Other Expense —

Total other expense in the first quarter of 2012 was $14 million lower than the first quarter of 2011, primarily due to a decrease in net interest expense resulting from debt reductions in 2011 ($6 million) and credits related to the settlement with the DOE regarding the storage of spent nuclear fuel ($7 million).

Other — First Quarter of 2012 Compared with First Quarter of 2011

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 $32 million increase in earnings available to FirstEnergy in the first quarter of 2012 compared to the same period of 2011. The increase resulted primarily from operating income ($42 million) due to lower merger-related costs, partially offset by decreased capitalized interest resulting from completed construction projects ($4 million) and decreased investment income ($9 million).

Regulatory Assets

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 tables provide information about the composition of net regulatory assets as of March 31, 2012 and December 31, 2011, and the changes during the quarter:

Regulatory Assets by Source	March 31, 2012			December 31, 2011			Increase (Decrease)
	(In millions)
Regulatory transition costs	$	642		$	608		$	34
Customer receivables for future income taxes	479			508			(29		)
Nuclear decommissioning and spent fuel disposal costs	(215		)	(210		)	(5		)
Asset removal costs	(251		)	(240		)	(11		)
Deferred transmission costs	376			340			36
Deferred generation costs	329			382			(53		)
Deferred distribution costs	258			267			(9		)
Other	388			375			13
Total	$	2,006		$	2,030		$	(24	)

FirstEnergy had $413 million of net regulatory liabilities as of March 31, 2012 that are primarily related to asset removal costs.

Regulatory assets that do not earn a current return totaled approximately $292 million as of March 31, 2012. JCP&L had $119 million of regulatory assets not earning a current return, which include certain storm damage costs and pension and OPEB benefits that are expected to be recovered by 2026. The remaining $173 million of regulatory assets include certain PJM transmission and regulatory transition costs, which are expected to be recovered by 2020.

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CAPITAL RESOURCES AND LIQUIDITY

As of March 31, 2012, FirstEnergy had $74 million of cash and cash equivalents and available liquidity of approximately $3.9 billion. 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. In addition to internal sources to fund liquidity and capital requirements for 2012 and beyond, FirstEnergy expects to 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 the incurrence of long-term debt or access to capital markets. 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.

As of March 31, 2012, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was principally due to currently payable long-term debt, which, as of March 31, 2012, included the following:

Currently Payable Long-term Debt	(In millions)
PCRBs supported by bank LOCs (1)	$	632
Unsecured notes	733
Unsecured PCRBs (1)	270
Collateralized lease obligation bonds	67
Sinking fund requirements	53
Other notes	17
	$	1,772

⁽¹⁾  These PCRBs are classified as currently payable long-term debt because the applicable interest rate mode permits individual debt holders to put the respective debt back to the issuer prior to maturity.

Short-Term Borrowings

FirstEnergy had approximately $1 billion of short-term borrowings as of March 31, 2012, and no significant short-term borrowings as of December 31, 2011. FirstEnergy’s available liquidity as of March 31, 2012, is summarized in the following table:

Company	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	June 2016	$	2,000	$	895
FES / AE Supply	Revolving	June 2016	2,500		2,498
TrAIL	Revolving	Jan. 2013	450		450
AGC	Revolving	Dec. 2013	50		—
		Subtotal	$	5,000	$	3,843
		Cash	—		54
		Total	$	5,000	$	3,897

⁽¹⁾  FirstEnergy Corp. and the Utilities.

Revolving Credit Facilities

FirstEnergy and FES/AE Supply Facilities

FE and certain of its subsidiaries participate in two five-year syndicated revolving credit facilities with aggregate commitments of $4.5 billion (Facilities). The Facilities consist of a $2 billion aggregate FirstEnergy Facility and a $2.5 billion FES/AE Supply Facility, that are each 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 Facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the 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. FirstEnergy is negotiating amendments to the FirstEnergy and FES/AE Supply Facilities to, among other things, extend their commitment dates by one year. However, FirstEnergy cannot provide any assurance that the Facilities will be amended and extended on satisfactory terms or at all.

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The following table summarizes the borrowing sub-limits for each borrower under the Facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations, as well as the debt to total capitalization ratios (as defined under each of the Facilities) as of March 31, 2012:

Borrower	FirstEnergy Revolving Credit Facility Sub-Limit			FES/AE Supply Revolving Credit Facility Sub-Limit			Regulatory and Other Short-Term Debt Limitations				Debt to Capitalization
	(In millions)
FE		$	2,000		$	—		$	—	(1)	58.8%
FES		—			1,500			—		(2)	50.6%
AE Supply		—			1,000			—		(2)	43.6%
OE		500			—			500			62.4%
CEI		500			—			500			61.0%
TE		500			—			500			63.1%
JCP&L		425			—			411		(3)	43.9%
ME		300			—			300		(3)	55.8%
PN		300			—			300		(3)	60.5%
WP		200			—			200		(3)	53.2%
MP		150			—			150		(3)	55.3%
PE		150			—			150		(3)	55.6%
ATSI		100			—			100			48.5%
Penn		50			—			33		(3)	41.9%

⁽¹⁾  No limitations.

⁽²⁾  No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.

⁽³⁾  On April 11, 2012, a joint application was filed with FERC seeking authorization to incur short-term debt in the amount of $600 million for JCP&L, $500 million for ME, $150 million for MP, $150 million for PE, $300 million for PN, $50 million for Penn, $400 million for TrAIL and $200 million for WP during the period June 1, 2012 through May 31, 2014.

As of March 31, 2012, FE and its subsidiaries could issue additional debt of approximately $5.6 billion, or recognize a reduction in equity of approximately $3.0 billion, and remain within the limitations of the financial covenants required by the Facilities.

The entire amount of the FES/AE Supply Facility and $700 million of the 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 Facilities and against the applicable borrower’s borrowing sub-limit.

The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. 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. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million.

AGC and TrAIL Revolving Credit Facilities

Separate revolving credit facilities are available to TrAIL ($450 million) and AGC ($50 million) until January 2013 and December 2013, respectively.

Under the terms of these credit facilities, 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 and outstanding debt for TrAIL may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. These provisions limit debt levels of these subsidiaries and also limit the net assets of each subsidiary that may be transferred to AE. As of March 31, 2012, the debt to total capitalization ratios for TrAIL and AGC (as defined under each of their credit facilities) were 46% and 51%, respectively.

As of March 31, 2012, TrAIL could issue additional debt of approximately $243 million and AGC could issue additional debt of approximately $43 million and remain within the limitations of the financial covenants under their credit facilities.

New Transmission Revolving Credit Facility     

FirstEnergy is in the process of negotiating a new $1 billion five-year revolving credit facility with a group of lenders. The borrowers under such facility are expected to be AET, and two of its direct subsidiaries, ATSI, which became a subsidiary of AET in April 2012,

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and TrAIL. ATSI is expected to have a $100 million sublimit and TrAIL is expected to have a $200 million sublimit. Once this facility is in place, it is expected that the current $450 million facility for TrAIL discussed above will be terminated and the $100 million sublimit for ATSI under the existing $2 billion FirstEnergy Facility will be eliminated. FirstEnergy cannot provide any assurance that the new revolving credit facility will be completed on satisfactory terms or at all.

FirstEnergy Money Pools

FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first quarter of 2012 was 0.85% per annum for the regulated companies’ money pool and 1.22% per annum for the unregulated companies’ money pool.

Pollution Control Revenue Bonds

As of March 31, 2012, FirstEnergy’s currently payable long-term debt included approximately $632 million ($558 million applicable to FES) 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's variable interest rate PCRBs were issued by the following banks as of March 31, 2012:

LOC Bank	Aggregate LOC Amount(1)		LOC Termination Date	Reimbursements of LOC Draws Due
	(In millions)
UBS	$	272	April 2014	April 2014
CitiBank N.A.	165		June 2014	June 2014
Wachovia Bank	153		March 2014	March 2014
The Bank of Nova Scotia	49		April 2014	Multiple dates(2)
Total	$	639

⁽¹⁾  Includes approximately $7 million of applicable interest coverage.

⁽²⁾  Earlier of 6 months from drawing or the LOC termination date.

On April 2, 2012, FGCO and NGC refinanced $52.1 million and $29.5 million, respectively, of PCRBs. The bonds were converted from a fixed-rate mandatory put mode to a variable-rate mode enhanced with a 3-year LOC. Additionally, on April 2, 2012, FGCO and NGC remarketed $146.7 million and $315 million of PCRBs, respectively, in a variable rate mode enhanced with a LOC.

Other Financings

On April 16, 2012, WP issued $100 million of FMBs through a private placement at a rate of 3.34%. These bonds have a maturity date of April 15, 2022, and the proceeds were used in part to retire $80 million of 6.625% medium term notes that matured on April 16, 2012.

On April 16, 2012, AE Supply retired $503.2 million of 8.25% medium term notes at maturity.

Long-Term Debt Capacity

As of March 31, 2012, the Ohio Companies and Penn had the aggregate capacity to issue approximately $2.7 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 $134 million and $1 million, respectively. As a result of the indenture provisions, TE cannot incur any additional secured debt. ME and PN had the capability to issue secured debt of approximately $380 million and $391 million, respectively, under provisions of their senior note indentures as of March 31, 2012. In addition, based upon their net earnings and available bondable property additions as of March 31, 2012, MP, PE and WP had the capacity to issue approximately $1.5 billion of additional FMBs in the aggregate under the terms of their FMB indentures. These companies may be further limited by the financial covenants of the Facilities and may be subject to regulatory approvals and applicable statutory and/or charter limitations.

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The Ohio Companies intend to file an application with the PUCO for a financing order under the recent Ohio securitization legislation, which is expected to assist the Ohio Companies in their planned debt reductions.

Based upon FGCO’s net earnings and available bondable property additions under its FMB indentures as of March 31, 2012, FGCO had the capacity to issue $1.8 billion of additional FMBs under the terms of that indenture. Based upon NGC’s net earnings and available bondable property additions under its FMB indenture as of March 31, 2012, NGC had the capacity to issue $2 billion of additional FMBs under the terms of that indenture.

FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. On January 18, 2012, Moody's upgraded the Senior Unsecured ratings for TrAIL to A3 from Baa2. The following table displays FE’s and its subsidiaries’ debt credit ratings as of March 31, 2012:

	Senior Secured			Senior Unsecured
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FE	—	—	—	BB+	Baa3	BBB
FES	—	—	—	BBB-	Baa3	BBB
AE Supply	—	—	—	BBB-	Baa3	BBB-
AGC	—	—	—	BBB-	Baa3	BBB
ATSI	—	—	—	BBB-	Baa1	A-
CEI	BBB	Baa1	BBB	BBB-	Baa3	BBB-
JCP&L	—	—	—	BBB-	Baa2	BBB+
ME	BBB	A3	A-	BBB-	Baa2	BBB+
MP	BBB+	Baa1	A-	BBB-	Baa3	BBB+
OE	BBB	A3	BBB+	BBB-	Baa2	BBB
PN	BBB	A3	BBB+	BBB-	Baa2	BBB
Penn	BBB+	A3	BBB+	—	—	—
PE	BBB+	Baa1	A-	BBB-	Baa3	BBB+
TE	BBB	Baa1	BBB	—	—	—
TrAIL	—	—	—	BBB-	A3	A-
WP	BBB+	A3	A-	BBB-	Baa2	BBB+

Changes in Cash Position

As of March 31, 2012, FirstEnergy had $74 million of cash and cash equivalents compared to $202 million of cash and cash equivalents as of December 31, 2011. As of March 31, 2012 and December 31, 2011, FirstEnergy had approximately $67 million and $79 million, respectively, of restricted cash included in other current assets on the Consolidated Balance Sheets.

Cash Flows From Operating Activities

FirstEnergy’s consolidated net cash from operating activities was provided primarily by its regulated distribution, regulated independent transmission and competitive energy services businesses (see Results of Operations above). Net cash used for operating activities was $413 million during the first three months of 2012 compared with $491 million being provided from operating activities during the first three months of 2011, as summarized in the following table:

	Three Months Ended March 31						Increase
Operating Cash Flows	2012			2011			(Decrease)
	(In millions)
Net income	$	306		$	47		$	259
Non-cash charges	366			504			(138		)
Pension trust contributions	(600		)	(157		)	(443		)
Working capital and other	(485		)	97			(582		)
	$	(413	)	$	491		$	(904	)

The decrease in non-cash charges and other adjustments is primarily due to decreased accrued compensation and retirement benefits ($109 million) due in part to higher performance-related incentive compensation payments during the first quarter of 2012 compared to the same period of 2011.

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The $582 million decrease in cash flows from working capital and other is primarily due to the following:

• $105 million from lower collections from customers during the first quarter of 2012 as a result of the effects of milder weather described in Results of Operations above.

• $158 million from increased materials and supplies balances as a result of increased coal inventories and the absence in 2012 of the $67 million non-cash inventory valuation adjustment recorded in connection with the merger.

• $137 million reflecting the absence of income tax refunds received during the first quarter of 2011 due to cash benefits realized on bonus depreciation and settlements with the IRS on certain prior year returns.

• $166 million from lower accounts payable balances as a result of the timing of payments to vendors during the first quarter of 2012 as compared to the same period of 2011.

Cash Flows From Financing Activities

In the first three months of 2012, cash provided from financing activities was $819 million compared to $550 million of net cash used for financing activities during the first three months of 2011. The following tables summarize new debt financing (net of any discounts) and redemptions:

	Three Months Ended March 31
Securities Issued or Redeemed / Retired	2012			2011
	(In millions)
New Issues
PCRBs	$	—		$	150
Long-term revolving credit	—			60
Unsecured Notes	—			7
	$	—		$	217
Redemptions / Retirements
PCRBs	$	—		$	(200	)
Long-term revolving credit	—			(20		)
Senior secured notes	(16		)	(109		)
Unsecured notes	—			(30		)
	$	(16	)	$	(359	)
Short-term borrowings, net	$	1,075		$	(214	)

Cash Flows From Investing Activities

Cash used for investing activities in the first three months of 2012 principally represented cash used for property additions. The following table summarizes investing activities for the first three months of 2012 and the comparable period of 2011:

	Three Months Ended March 31						Increase
Cash Used for (Provided from) Investing Activities	2012			2011			(Decrease)
	(In millions)
Property Additions:
Regulated distribution	$	301		$	177		$	124
Competitive energy services	243			214			29
Regulated independent transmission	28			27			1
Other and reconciling adjustments	17			31			(14		)
Cash received in Allegheny merger	—			(590		)	590
Investments	(63		)	(23		)	(40		)
Other	8			23			(15		)
	$	534		$	(141	)	$	675

Net cash used for investing activities during the first three months of 2012 increased by $675 million compared to the same period of 2011. The increase was principally due to the absence in 2012 of cash acquired in the Allegheny merger ($590 million) and

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increased property additions ($140 million), partially offset by a decrease in net purchases of investment securities ($9 million) and additional restricted cash investments ($31 million).

During the remainder of 2012, capital requirements for property additions and capital leases are estimated to be approximately $1.8 billion, including approximately $212 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. 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 credit support to various providers for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements include provisions for parent guarantees, surety bonds and/or LOCs to be issued by FirstEnergy on behalf of one or more of its subsidiaries. Additionally, certain contracts may contain collateral provisions that are contingent upon either FirstEnergy's or its subsidiaries’ credit ratings.

As of March 31, 2012, FirstEnergy’s maximum exposure to potential future payments under outstanding guarantees and other assurances approximated $4.1 billion, as summarized below:

Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FirstEnergy Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts(1)	$	273
LOC (long-term debt) - interest coverage(2)	5
OVEC obligations	300
Other(3)	299
	877
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts	137
LOC (long-term debt) - interest coverage(2)	2
FES’ guarantee of NGC’s nuclear property insurance	79
FES’ guarantee of FGCO’s sale and leaseback obligations	2,286
Other	12
	2,516
Signal Peak & Global Rail facility	350
Surety Bonds	151
LOCs(4)	185
	686
Total Guarantees and Other Assurances	$	4,079

⁽¹⁾  Issued for open-ended terms, with a 10-day termination right by FirstEnergy.

⁽²⁾  Reflects the interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities. The principal amount of floating-rate PCRBs of $632 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

⁽³⁾  Includes guarantees of $95 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangement, and $34 million for railcar leases.

⁽⁴⁾  Includes $32 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $116 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $37 million pledged in connection with the sale and leaseback of Perry by OE.

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $151 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.

While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As of March 31, 2012, FirstEnergy’s exposure to additional credit contingent contractual obligations was $671 million, as shown below:

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Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade (1)	$	439	$	8	$	59	$	506
Material adverse event (2)	91		60		14		165
Total	$	530	$	68	$	73	$	671

⁽¹⁾  Includes $222 million and $40 million that are also considered accelerations of payment or funding obligation for FES and the Utilities, respectively.

⁽²⁾  Includes $42 million that is also considered an acceleration of payment or funding obligation for FES.

Certain bilateral non-affiliate contracts entered into by the Competitive Energy Services segment contain margining provisions that require posting of collateral. Based on FES' and AE Supply's power portfolios exposure as of March 31, 2012, FES and AE Supply have posted collateral of $84 million and $1 million, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES or AE Supply and certain of the Utilities in the Regulated Distribution Segment. As of March 31, 2012, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post $54 million and $18 million, respectively.

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 originally shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. Following the sale of a portion of FEV's ownership interest in Signal Peak and Global Rail in the fourth quarter of 2011, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding, continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral. In March 2012, after an evaluation of its current operations, business plan and market conditions, the Global Holding Board of Managers opted to focus first on extending its current senior secured term loan facility due in October 2012, before replacing that facility with non-recourse financing. There can be no assurance that the term loan facility will be extended on satisfactory terms or at all.

OFF-BALANCE SHEET ARRANGEMENTS

FES and certain of 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 March 31, 2012, of which $118 million is applicable to the 1987 Bruce Mansfield Plant leases, which may be terminated pursuant to an early buyout option. In March 2012, FGCO, as assignee, provided notice of its irrevocable election of the early buyout option of the 1987 Bruce Mansfield Plant leases. The purchase price to be paid by FGCO will be equal to the higher of the special termination value under the applicable facility leases (in the aggregate approximately $435 million covering both debt and equity under the leases) and the fair market value. An appraisal process to determine such fair market value has been invoked by certain of the parties.

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. FirstEnergy's Risk Management 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.

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In

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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 6, Fair Value Measurements of the Combined Notes to the Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of March 31, 2012 are summarized by year in the following table:

Source of Information- Fair Value by Contract Year	2012			2013			2014			2015			2016		Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	(2	)	$	—		$	—		$	—		$	—	$	—	$	(2	)
Other external sources(2)	(158		)	(49		)	(28		)	(25		)	—		—		(260		)
Prices based on models	(14		)	—			—			—			1		27		14
Total(3)	$	(174	)	$	(49	)	$	(28	)	$	(25	)	$	1	$	27	$	(248	)

⁽¹⁾  Represents exchange traded New York Mercantile Exchange futures and options.

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

⁽³⁾  Includes $(305) 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 March 31, 2012, an adverse 10% change in commodity prices would decrease net income by approximately $2 million 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 March 31, 2012, the FirstEnergy pension plan was invested in approximately 24% of equity securities, 51% of fixed income securities, 17% of absolute return strategies, 5% of real estate, 2% of private equity and 1% 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 endedMarch 31, 2012, FirstEnergy made pre-tax contributions to its qualified pension plans of $600 million.

NDT funds have been established to satisfy NGC’s, OE's, JCP&L's and other FE subsidiaries' nuclear decommissioning obligations. As of March 31, 2012, approximately 80% of the funds were invested in fixed income securities, 13% of the funds were invested in equity securities and 7% 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 $1,699 million, $288 million and $146 million for fixed income securities, equity securities and short-term investments, respectively, as of March 31, 2012, excluding $2 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $29 million reduction in fair value as of March 31, 2012. JCP&L's decommissioning trust is 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 and OE recognized in earnings the unrealized losses on available-for-sale securities held in their NDT as OTTI. A decline in the value of FirstEnergy’s NDT or a significant escalation in estimated decommissioning costs could result in additional funding requirements. FENOC has submitted a $95 million parental guarantee to the NRC relating to a short-fall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry.

CREDIT RISK

Credit risk is defined as the risk that a counterparty to a transaction will be unable to fulfill its contractual obligations. FirstEnergy evaluates the credit standing of a prospective counterparty based on the prospective counterparty's financial condition. FirstEnergy may impose specified collateral requirements and use standardized agreements that facilitate the netting of cash flows. FirstEnergy monitors the financial conditions of existing counterparties on an ongoing basis. An independent risk management group oversees credit risk.

Wholesale Credit Risk

FirstEnergy measures wholesale credit risk as the replacement cost for derivatives in power, natural gas, coal and emission

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allowances, adjusted for amounts owed to or due from counterparties for settled transactions. The replacement cost of open positions represents unrealized gains, net of any unrealized losses, where FirstEnergy has a legally enforceable right of set-off. FirstEnergy monitors and manages the credit risk of wholesale marketing, risk management and energy transacting operations through credit policies and procedures, which include an established credit approval process, daily monitoring of counterparty credit limits, the use of credit mitigation measures such as margin, collateral and the use of master netting agreements. FirstEnergy manages the quality of its portfolio of energy contracts, currently having a weighted average risk rating for energy contract counterparties of BBB (S&P).

Retail Credit Risk

FirstEnergy is exposed to retail credit risk through competitive electricity activities, which serve residential, commercial and industrial companies. Retail credit risk results when customers default on contractual obligations or fail to pay for service rendered. This risk represents the loss that may be incurred due to the nonpayment of customer accounts receivable balances, as well as the loss from the resale of energy previously committed to serve customers.

Retail credit risk is managed through established credit approval policies, monitoring customer exposures and the use of credit mitigation measures such as deposits in the form of LOCs, cash or prepayment arrangements.

Retail credit quality is affected by the economy and the ability of customers to manage through unfavorable economic cycles and other market changes. If the business environment were to be negatively affected by changes in economic or other market conditions, FirstEnergy's retail credit risk may be adversely impacted.

OUTLOOK

STATE REGULATION

Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

MARYLAND

PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions overseen by the MDPSC and a third party monitor. The settlements with respect to residential SOS for PE customers expire on December 31, 2012, but by statute service will continue in the same manner unless changed by order of the MDPSC. The settlement provisions relating to non-residential service have expired but, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS.

On September 29, 2009, the MDPSC opened a 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 December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and subsequently the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids.On April 12, 2012, the MDPSC issued an order requiring certain Maryland electric utilities, but not PE, to enter into a contract for differences, an electricity hedging arrangement, with respect to a 661 MW natural gas-fired combined cycle generation plant to be built in Charles County, Maryland.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by10%and reduce electricity demand by15%, in each case by 2015. 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 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsix-year period. Maryland law only allows for the utility to recover lost distribution revenue attributable to the energy efficiency or demand reduction programs through a base rate case proceeding, and to date such recovery has not been sought or obtained by PE. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving PE's plan with various modifications and follow-up assignments.

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Pursuant to a bill passed by the Maryland legislature, the MDPSC proposed rules, based on the product of a working group of utilities, regulators, and other interested stakeholders, that create specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The bill requires that the MDPSC 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 required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation.Further comments were filed regarding the proposed rules on March 26, 2012, and at a hearing on April 17, 2012, the MDPSC approved re-publication of the rules as final.

NEW JERSEY

JCP&L currently provides BGS for retail customers that do not choose a third party electric generation supplier and for customers of third party electric generation suppliers, that fail to provide the contracted service. The supply for BGS, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. The most recent BGS auction results, for supply commencing June 1, 2012, were approved by the NJBPU on February 9, 2012.

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time. On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to, among other things, set and modify the schedule, decide upon motions, and otherwise control the conduct of this case, subject to subsequent NJBPU ratification.The schedule in the proceeding provides for briefs to be filed by the parties, the initial brief was filed by the parties on April 26, 2012. A decision is expected to be issued in June 2012. JCP&L is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held to solicit comments regarding the state of preparedness and responsiveness of the EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the report of the consultant is due to be submitted to the NJBPU in July 2012.The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

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;

• a load cap of no less than80%, so that no single supplier is awarded more than80%of the tranches, which also applies to tranches assigned post-auction;

• a6%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, 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, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent 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.

The Ohio Companies filed an application with the PUCO to essentially extend their current ESP for two more years. The Ohio Companies requested PUCO approval by May 2, 2012, so that they may bid megawatts of PJM-qualified energy efficiency and demand response resources into the May 7, 2012, PJM capacity auction for the 2015-2016 planning year or in the alternate by June 20, 2012, which would allow adequate time to implement changes to the bidding schedule to capture a greater amount of generation at historically lower prices for the benefit of customers. The PUCO has set an evidentiary hearing for May 21, 2012; therefore approval by May 2, 2012, is not expected.

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As proposed, the extended ESP would maintain the substantial benefits from the current ESP including:

• Freezing current base distribution rates through May 31, 2016;

• Continuing to provide economic development and assistance to low-income customers for the two-year extension period at the levels established in the existing ESP;

• Providing Percentage of Income Payment Plan customers with a 6 percent generation rate discount;

• Continuing to provide capacity to shopping and non-shopping customers at a market-based price set through an auction process; and

• Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.

As proposed, the extended ESP would provide additional new benefits, including:

• Securing generation supply over a longer period of time to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and

• Extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB 221 through the end of the new ESP period. This will reduce the monthly renewable energy charge for all FirstEnergy Ohio utility customers.

The filing is supported by19parties including: Industrial Energy Users, Ohio Energy Group, PUCO Staff, the City of Akron, Ohio Manufacturers Association, Ohio Partners for Affordable Energy, and the Council of Smaller Enterprises (COSE).

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed theirthree-year portfolio plan, as required by SB221, seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies are in the process of implementing those programs included in the plan, and requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the issue was moot for CEI and TE. The Ohio Companies filed an application for rehearing, which was later denied. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision related to the Ohio Companies'threeyear portfolio plan, including the method for calculating savings and certain changes made by the PUCO to specific programs. The PUCO denied those applications for rehearing, and in that entry included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute. The Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO's new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. On March 2, 2012, the PUCO moved to dismiss the Companies' appeal. The Companies filed their Memorandum in Opposition to the PUCO's Motion, along with their merit brief on March 9, 2012. The PUCO filed its brief on April 27, 2012. The Company now has twenty days to file its reply brief. Oral arguments have not yet been scheduled.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond. On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are currently scheduled to be filed with the PUCO by May 15, 2012. In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies have achieved their in-state solar compliance requirements for 2012.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative electric generation supplier or for customers of alternative electric generation suppliers that fail to provide the contracted service. The default service supply is currently provided by wholesale

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suppliers through a mix of long-term and short-term contracts procured through descending clock auctions, competitive requests for proposals and spot market purchases. On November 17, 2011, ME, PN, Penn and WP filed a Joint Petition for Approval of their DSP that will provide the method by which the Pennsylvania Companies will procure the supply for their default service obligations for the period June 1, 2013 through May 31, 2015. A final order must be entered by the PPUC by August 17, 2012.

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, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission losses are refunded. In April 2010, ME and PN 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 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME and PN TSC riders. ME and PN filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss ME and PN Amended Complaint on September 15, 2011 to which ME and PN responded and which remains pending.On February 28, 2012, the Supreme Court of Pennsylvania denied the Petition for Allowance of Appeal.

In each of May 2008, 2009 and 2010, the PPUC approved ME's and PN'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 transmission 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 ME's customers to provide for full recovery by December 31, 2010. Although the ultimate outcome of this matter cannot be determined at this time, ME and PN believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 millionin marginal transmission losses for the period prior to January 1, 2011.

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 (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of ME, PN and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements. On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding, and the ALJ's Recommended Decision was issued on April 19, 2012, recommending that the Joint Settlement be adopted as filed.

In addition, Act 129 required utilities to file a SMIP with the PPUC. 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 its previously approved smart meter deployment plan and certain smart meter dependent aspects of the EE&C Plan. WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. WP also proposed to take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. 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. A joint settlement with all parties based on these terms, with one party retaining the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan, was approved by the PPUC on June 30, 2011. 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 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 concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31,

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2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the PPUC entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming DSPs, including: the duration of the programs and the length of associated energy contracts; a customer referral program; a retail opt-in auction; time-of-use rate options provided through contracts with electric generation suppliers; and periodic rate adjustments.Following the issuance of a Tentative Order and comments filed by various parties, the PPUC entered a final order on March 2, 2012 outlining an intermediate work plan. Several suggested models for long-range default service have been presented and were the topic of a March 2012 en banc hearing. It is expected that a tentative order will be issued for comment with a final long-range proposal.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by ME, PN, Penn, WP and FES on March 27, 2012. If implemented these rules could require a significant change in the ways FES, ME, PN, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

WEST VIRGINIA

In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in a proceeding for an annual increase in retail rates that provided for:

• $40 millionannualized base rate increases effective June 29, 2010;

• Deferral of February 2010 storm restoration expenses over a maximumfive-year period;

• Additional$20 millionannualized base rate increase effective in January 2011;

• Decrease of$20 millionin ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and

• 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 January 2011, MP and PE filed an application with the WVPSC seeking to certifythreefacilities as Qualified Energy Resource Facilities for purposes of compliance with their approved plan pursuant to AREPA. The application was approved and thethreefacilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. 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 andthreeNUG facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, have participated in the case in opposition to the petition. The WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. The WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. Oral arguments were heard at the West Virginia Supreme Court on April 10, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC. On April 24, 2012, the FERC ruled that the FERC-jurisdictional contracts are intended to pay only for electric energy and capacity (and not for RECs), and that state law controlled on the issues of determining which entity owns RECs and how they are transferred between entities. The FERC declined to act on the complaints and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court. MP is evaluating whether to seek rehearing of the FERC's order.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC 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 RFC.

FirstEnergy believes that it 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

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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 RFC. Moreover, it is clear that the NERC, RFC 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. 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, 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.On March 22, 2012, NERC concluded the investigation of the matter and forwarded it to NCEA for further review. NCEA is currently evaluating the findings of the investigation. JCP&L is not able to predict what actions, if any, NERC may take with respect to this matter.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and processes to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities - the matter is contentious because costs for facilities built in one transmission zone often are allocated to customers in other transmission zones. During recent years, the debate has focused on the question of the methodology for determining the transmission zones and customers who benefit from a given facility and, if so, whether the methodology can determine the pro rata share of each zone's benefit. While FirstEnergy and other parties argue for a traditional "beneficiary pays" approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. This debate is framed by regulatory and court decisions.In 2007, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identifiednineseparate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the costs. Subsequently, 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 utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis.On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at500kV 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 and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to 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. While most of the matters involved with the move have been resolved, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed; the details of which dispute are discussed below in the "MISO Multi-Value Project Rule Proposal." In addition, FERC denied certain exit fees of ATSI's transmission rate until such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move. ATSI has asked for rehearing of FERC's orders that address the Michigan Thumb transmission project, and the exit fee issue.

ATSI's filings and requests for rehearing on these matters, as well as the pleadings submitted by parties that oppose ATSI's position are currently pending before FERC. Finally, a negotiated agreement that requires ATSI to pay a one-time charge of$1.8 millionfor long term firm transmission rights that - according to the MISO - were payable upon ATSI's exit, is pending before FERC.

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.

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MISO Multi-Value Project Rule Proposal

In July 2010, MISO and certain MISO transmission owners (not including ATSI or First Energy) jointly filed with FERC a 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 the MISO's MTEP process. Under MISO's proposal, the costs of “Michigan Thumb” MVP projects that were 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 and charged to ATSI. MISO estimated that approximately$15 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction.

FirstEnergy has filed pleadings in opposition to the MISO's efforts to “socialize” the costs of the Michigan Thumb Project onto ATSI or onto ATSI's customers that assert legal, factual and policy arguments.

To date, FERC has responded in a series of orders that require ATSI to absorb the charges for the Michigan Thumb Project.

On October 31, 2011, FirstEnergy filed a Petition of Review of certain of the FERC's orders with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit.

On February 27, 2012, FERC issued its most recent order (February 2012 Order) regarding the Michigan Thumb Project, in which FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. MISO's Schedule 39 tariff is the vehicle through which the MISO plans to charge the Michigan Thumb project costs to ATSI.In the February 2012 Order, FERC directed that settlement negotiations occur. On March 28, 2012, FirstEnergy filed for clarification and rehearing of the February 2012 Order, and such request is pending before the FERC.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

PJM Underfunding FTR Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year, through March 31, 2012, are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. On March 2, 2012, FERC dismissed the complaint without prejudice, pending PJM's publication for stakeholder review and discussion, a report on the causes of the FTR underfunding and potential improvements, including modeling, which could be made to minimize the revenue inadequacy. On March 30, 2012, FES and AE Supply requested rehearing and reconsideration of the March 2, 2012 order, arguing that FERC erred in dismissing the complaint because the root cause of the FTR underfunding is irrelevant to the relief requested in the complaint. That request remains pending before FERC.

FTR Allocation Complaint

On March 26, 2012, FES and AE Supply filed a complaint with FERC against PJM challenging PJM's FTR allocation rules. PJM allocates FTRs to load-serving entities in an annual allocation process, up to each LSE's peak load, based on the expected transmission capability for the upcoming planning year. If a transmission facility is scheduled to be out of service for a significant part of the year, it can result in LSEs' FTR allocations being reduced in the annual allocation. When these transmission facilities return to service during the year PJM will create monthly FTRs to reflect the increased transmission capability during that month. However, instead of allocating these new monthly FTRs to the LSEs that were unable to obtain their full allocation of FTRs in the annual allocation process, PJM's rules instead require PJM to auction off these new monthly FTRs in the market. The complaint seeks a change to the PJM rules such that the new FTRs created each month by transmission lines returning to service would first be allocated to those LSEs that were denied a full allocation of their FTR entitlement in the annual allocation process before they are auctioned off in the market. On April 16, 2012, PJM filed its answer to the complaint. Also, on that date, Exelon Corporation filed a protest to, and several parties filed comments on, FES' and AE Supply's complaint, which remains pending before FERC. On April 30, 2012, FES and AE Supply filed a motion for leave to answer and answer to the various pleadings filed on April 16, 2012.

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 CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor these alleged overcharges. This proposal

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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 remandedoneof 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). 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. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

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. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV 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 the WVPSC, the VSCC and MDPSC. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

Yards Creek

The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. FERC issued a license for authorization to operate the project. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the five-year ILP licensure process. FirstEnergy expects FERC to issue the new license before February 28, 2013. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.

Seneca

The Seneca Pumped Storage Project is a451MW 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 related documents in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and related documents necessary for the Seneca Nation 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

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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.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology and modeling of the hydrological impacts of project operations.In March of 2012, FirstEnergy hosted a meeting as part of the consultation process. In that meeting, FirstEnergy reviewed its proposed methodology for conducting the hydrological impacts study and answered questions from third parties about the methodology. On April 11, 2012, the Seneca Nation and other parties filed comments on the proposed hydrologic impacts study.The study processes, including the discrete hydrological impacts study, will extend through approximately November 2013.

FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

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 SO₂and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂and 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 or non-emitting plants and/or using emission allowances.

In July 2008,threecomplaints representing multiple plaintiffs were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner.” One complaint was filed on behalf oftwenty-oneindividuals and the other is a class action complaint seeking certification as a class with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

In December 2007, the states of New Jersey and Connecticut filed CAA citizen suits in the U.S. District Court for the Eastern District of Pennsylvania alleging NSR violations at the coal-fired 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 ME in 1999) and ME. 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. The Court dismissed New Jersey's and Connecticut's claims for injunctive relief against ME, but denied ME's motion to dismiss the claims for civil penalties. The parties dispute the scope of ME's indemnity obligation to and from Sithe Energy. In February 2012, GenOn announced its plans to retire the Portland Station in January 2015 citing EPA emissions limits and compliance schedules to reduce SO₂air emissions by approximately81%at the Portland Station by January 6, 2015. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. ME, JCP&L and PN, as former owners of the facilities, are unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In January 2011, the U.S. DOJ filed a complaint against PN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PN based on alleged “modifications” at the coal-fired Homer City generating plant 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, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. 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. In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the states of New Jersey and New York against all of the defendants, including PN. In December 2011, the U.S., the Commonwealth

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of Pennsylvania and the states of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. PN believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.

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 during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. 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. FGCO intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. In September 2007, AE 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 coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. FirstEnergy intends to vigorously defend against these CAA matters, but cannot predict their outcomes or estimate the possible loss or range of loss.

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 U.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the PSD provisions of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. A non-jury trial on liability only was held in September 2010. The parties are awaiting a decision from the District Court, but there is no deadline for that decision. FirstEnergy is unable to predict the outcome or estimate the possible loss or range of loss.

National Ambient Air Quality Standards

The EPA's CAIR requires reductions of NOx and SO₂emissions intwophases (2009/2010 and 2015), ultimately capping SO₂emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia decided that CAIR violated the CAA but 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 decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO₂emissions intwophases (2012 and 2014), ultimately capping SO₂emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO₂emission allowances between power plants located in the same state and interstate trading of NOx and SO₂emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO₂emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO₂emission allowances. On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Hazardous Air Pollutant Emissions

On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) ofninecoal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349MW (generating, on average, approximatelytenpercent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.

On March 8, 2012, FGCO filed an application for a feasibility study with PJM to install and interconnect to the transmission system approximately 800 megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to

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help ensure reliable electric service in the region. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant retirements and requested Reliability Must-Run arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18. During the three months ended March 31, 2012, FirstEnergy recognized pre-tax severance expense of approximately$7 million (including$4 million by FES) as a result of the closures.

On March 9, 2012, to assist the WVPSC with inquiries from public officials and the public, MP provided information to the WVPSC in the form of a closed entry filing in the ENEC case related to the plant deactivations. On April 2, 2012, the WVPSC issued an order requesting additional information from MP related to the Albright, Rivesville and Willow Island plant deactiviation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations. We anticipate deactivating these units by September 1, 2012.

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. 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 and report GHG emissions commencing in 2010. 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 NSR preconstruction permits would be required including an emissions applicability threshold of75,000tons per year of CO₂equivalents for existing facilities under the CAA's PSD program.

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 belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “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. A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO₂emissions 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-CO₂emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA 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 CWA 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 CWA 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

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28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a12%annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days 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. 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 CWA 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. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil liability claims for those petroleum spills to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.

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 coal-fired Hatfield's Ferry Plant. These criteria are reflected in the NPDES water discharge permit issued by PA DEP for that project. In January 2009, AE Supply appealed the PA DEP's permitting decision to the EHB, due to estimated costs in excess of$150 million in order to install technology to meet TDS and sulfate limits in the NPDES permit. Environmental Integrity Project and Citizens Coal Council also appealed the NPDES permit seeking to impose more stringent technology-based effluent limitations. In April 2012, a joint motion was filed by the parties informing the EHB of a proposed settlement and seeking the lifting of a portion of the EHB's stay of certain terms of the Hatfield's Ferry Plant's NPDES permit. The joint motion was granted by the EHB on April 27, 2012. The parties intend to memorialize the settlement in a Consent Decree to be lodged with the Commonwealth Court of Pennsylvania. The Consent Decree, if entered by the Commonwealth Court of Pennsylvania, will resolve the disputes concerning the Hatfield's Ferry Plant NPDES permit, including TDS and sulphate limits.

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 would apply only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile 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 approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.

In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin Plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES 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 NPDES permit. MP has appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require 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, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit in the U.S. District Court for the Northern District of West Virginia alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. In April 2012, the parties reached a settlement requiring MP to resolve these CWA citizen suit claims for an immaterial amount. If approved by the Court, a Consent Decree will be entered by the Court to resolve these claims. 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 a60-day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.

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FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.

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 December 2009, in an advance 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 proposedtwooptions 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. The LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.

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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.

Certain of our utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. 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 ofMarch 31, 2012, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(including$70 millionapplicable to JCP&L) have been accrued throughMarch 31, 2012. Included in the total are accrued liabilities of approximately$63 millionfor 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.FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofMarch 31, 2012, 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. FirstEnergy Corp. currently maintains a $95 millionparental guaranty in support of the decommissioning of nuclear facilities.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. The NRC subsequently narrowed the scope of admitted contentions in this proceeding to a challenge to the computer code used to model source terms in FENOC's Severe Accident Mitigation Alternatives analysis. On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.The ASLB scheduled a May 18, 2012, oral argument on the petitioner's request for a new contention, but has yet to rule on the admission of this contention.

On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.

On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting

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a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.

By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.

On March 12, 2012, the NRC Staff issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities.

On February 16, 2012, the NRC issued a request for information to the licensed operators of11nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in higher burn up fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer and that the NRC might consider imposing restrictions on reactor operating limits.On March 16, 2012, FENOC submitted its response to the NRC demonstrating that the NRC requirements are being met. FENOC also agreed to submit to the NRC revised large break loss of coolant accident analyses by December 15, 2016, that further consider the effects of fuel pellet thermal conductivity degradation.

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and 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 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor 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 millionin future damages and$14 million for replacement coal / interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal.Briefing on the Appeal is concluded with oral argument scheduled for May 16, 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

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 had been approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction. The court granted the motion to dismiss and the plaintiffs appealed the decision to the Court of Appeals of Ohio. The Court of Appeals affirmed the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud which it remanded to the trial court. The Companies timely filed a notice of appeal with the Supreme Court of Ohio on December 5, 2011, challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio agreed to hear the appeal.

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 under Note 8, Regulatory Matters to the Combined Notes to the Consolidated Financial Statements.

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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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, 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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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 to wholesale and retail customers, and through its principal subsidiaries, FGCO and NGC, owns or leases, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns, through its subsidiary, NGC, FirstEnergy’s nuclear generation facilities. FENOC, a wholly owned subsidiary of FirstEnergy, operates and maintains the nuclear generating facilities. FES purchases the entire output of the generation facilities owned by FGCO and NGC, 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, and pursuant to full output, cost-of-service PSAs.

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, Michigan, New Jersey and Maryland.

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

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: Overview, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk and Outlook.

Results of Operations

Net income increased by $77 million in the first three months of 2012 compared to the same period of 2011. The increase was primarily due to higher revenues and other income partially offset by higher operating expenses.

Revenues

Total revenues increased $125 million, or 9%, in the first three months of 2012, compared to the same period of 2011, primarily due to growth in combined direct and governmental aggregation sales and wholesale sales partially offset by a net decline in POLR and structured sales.

The increase in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	1,007	$	840	$	167
POLR and Structured Sales	231		374		(143		)
Wholesale	215		91		124
Transmission	31		26		5
RECs	5		32		(27		)
Other	27		28		(1		)
Total Revenues	$	1,516	$	1,391	$	125

	Three Months Ended March 31		Increase
MWH Sales by Type of Service	2012	2011	(Decrease)
	(In thousands)
Direct	12,391	9,671	28.1	%
Governmental Aggregation	5,186	4,310	20.3	%
POLR and Structured Sales	4,030	5,843	(31.0	)%
Wholesale	21	985	(97.9	)%
Total Sales	21,628	20,809	3.9	%

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The increase in combined direct and governmental aggregation revenues of $167 million resulted from the acquisition of new commercial and industrial customers as well as new governmental aggregation contracts with communities in Ohio and Illinois that provided generation to approximately 1.9 million residential and small commercial customers as of March 2012 compared to approximately 1.5 million as of March 2011. These increases were partially offset by lower sales to residential and small commercial customers primarily as a result of weather that was 25% warmer this year in the markets served compared to 2011.

The decrease in combined POLR and structured revenues of $143 million was due primarily to lower sales volumes to the Ohio Companies, ME and PN. Revenues were also adversely impacted by lower unit prices which were partially offset by increased structured sales. The decline in POLR sales reflects our continued focus on other sales channels.

Wholesale revenues increased by $124 million due to a $110 million gain on financially settled contracts and a $43 million increase in capacity revenues. These increases were partially offset by decreased short-term (net hourly positions) transactions in MISO.

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

Source of Change in Direct and Governmental Aggregation	Increase (Decrease)
	(In millions)
Direct Sales:
Effect of increase in sales volumes	$	159
Change in prices	(43		)
	116
Governmental Aggregation:
Effect of increase in sales volumes	55
Change in prices	(4		)
	51
	$	167

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of decrease in sales volumes	$	(116	)
Change in prices	(27		)
	$	(143	)

Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(28	)
Change in prices	(1		)
Gain on settled contracts	110
Capacity revenue	43
	$	124

Transmission revenues increased by $5 million due primarily to higher PJM congestion and ancillary revenue. The revenues derived from the sale of RECs decreased$27 million in the first quarter of 2012.

Operating Expenses

Total operating expenses increased by $8 million in the first three months of 2012, compared with the same period of 2011.

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The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2012 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	$	9
Change due to volume consumed	(64		)
	(55		)
Nuclear Fuel:
Change due to increased unit costs	2
Change due to volume consumed	5
	7
Non-affiliated Purchased Power:
Change due to decreased unit costs	(73		)
Change due to volume purchased	103
Loss on settled contracts	106
Capacity expense	54
	190
Affiliated Purchased Power:
Change due to decreased unit costs	(25		)
Change due to volume purchased	18
Loss on settled contracts	55
	48
Net Increase in Fuel and Purchased Power Costs	$	190

Total fuel costs decreased by $48 million in the first three months of 2012, compared to the same period of 2011, as a result of reduced generation by the fossil units, partially offset by higher unit prices. Nuclear fuel expenses increased primarily due to higher generation.

Non-affiliated purchased power costs increased by $190 million in the first three months of 2012, compared to the same period of 2011, due to higher volumes purchased, loss on settled contracts and capacity expense, partially offset by lower unit prices. The increase in volumes primarily relates to the overall increase in sales volumes and economic purchases. Affiliated purchased power costs increased by $48 million in the first three months of 2012, compared to the same period of 2011, due to higher volumes purchased and loss on settled contracts, partially offset by lower unit prices.

Other operating expenses decreased by $170 million in the first three months of 2012, compared to the same period of 2011 due to the following:

• Transmission expenses decreased $62 million due primarily to decreases of $68 million from lower congestion, network and line loss costs in MISO. These decreases were partially offset by increases in PJM of $6 million from higher network costs, partially offset by lower congestion and line loss expenses.

• Nuclear operating costs decreased by $28 million due primarily to lower labor, contractor and materials and equipment costs as there were no refueling outages this year while the previous year included the Beaver Valley Unit 2 refueling outage.

• Fossil operating costs decreased by $7 million due primarily to lower contractor and materials and equipment costs resulting from a decrease in planned and unplanned outages, partially offset by higher labor costs.

• Other operating expenses decreased by $73 million as the expenses in the previous year included a $54 million provision for excess and obsolete material relating to revised inventory practices adopted in connection with the Allegheny merger and favorable net mark-to-market adjustments of $28 million on commodity contract positions, partially offset by higher agent commission costs of $9 million from increased retail sales.

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Impairment charges on long-lived assets decreased by $14 million due to last year's charge related to non-core peaking facilities that were subsequently sold in 2011.

General taxes increased by $8 million due to an increase in revenue-related taxes.

Depreciation expense decreased by $6 million primarily due to credits resulting from a settlement with the DOE regarding the storage of spent nuclear fuel.

Other Expense

Total other expense decreased by $10 million in the first three months of 2012, compared to the same period of 2011, primarily due to lower interest expense of $10 million resulting from debt reductions in 2011 and credits related to the settlement with the DOE noted above.

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OHIO EDISON COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

OE is a wholly owned electric utility subsidiary of FE. OE engages in the distribution and sale of electric energy to communities in a 7,000 square mile area of central and northeastern Ohio and, through its wholly owned subsidiary, Penn, 1,100 square miles in western Pennsylvania. OE and Penn conduct business in portions of Ohio and Pennsylvania, by providing regulated electric distribution services for their customers as well as generation procurement services for customers who have not selected an alternative supplier. The areas served by OE and Penn have populations of approximately 2.3 million and 0.4 million, respectively.

For additional information with respect to OE, please see the information contained in FE’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Overview, Results of Operations - Regulatory Assets, Capital Resources and Liquidity, Market Risk Information, Credit Risk and Outlook.

Results of Operations

Net income decreased by $1 million for the first three months of 2012, compared to the same period of 2011. The decrease was primarily due to lower revenues and higher other operating expenses, partially offset by lower purchased power costs.

Revenues

Revenues decreased by $6 million, or 2%, in the first three months of 2012, compared with the same period of 2011, due to a decrease in distribution and wholesale generation revenues, partially offset by higher retail generation revenues.

Distribution revenues decreased by $10 million in the first three months of 2012, compared to the same period of 2011, due to lower MWH deliveries to the residential and commercial customer classes, partially offset by higher MWH deliveries to the industrial customer class. Lower MWH deliveries to the residential and commercial classes were driven primarily by lower weather-related usage. The increase in distribution deliveries to industrial customers was principally due to improving economic conditions in OE’s and Penn’s service territories.

Changes in distribution MWH deliveries and revenues in the first three months of 2012, compared to the same period of 2011, are summarized in the following tables:

Distribution MWH Deliveries	Increase (Decrease)
Residential	(7.2	)%
Commercial	(1.7	)%
Industrial	3.2	%
Net Decrease in Distribution Deliveries	(2.4	)%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	(14	)
Commercial	1
Industrial	3
Net Decrease in Distribution Revenues	$	(10	)

Retail generation revenues increased by $4 million primarily due to higher average prices in the residential customer class, offset by a decrease in MWH sales from increased customer shopping and warmer weather. Higher average prices for residential customers were primarily due to the implementation of Ohio's non-market based (NMB) transmission rider in June 2011, which recovers network integration transmission service charges described below. Lower MWH sales were primarily due to lower weather-related usage resulting from heating degree days that were 26% below 2011 levels and an increase in customer shopping levels to 71% compared to 67% in the same quarter of last year. Retail generation revenues are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. OE and Penn defer the difference between retail generation revenues and purchased power costs, resulting in no material effect to current period earnings.

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Changes in retail generation MWH sales and revenues in the first three months of 2012, compared to the same period of 2011, are summarized in the following tables:

Retail Generation MWH Sales	Decrease
Residential	(14.3	)%
Commercial	(22.6	)%
Industrial	(15.6	)%
Decrease in Retail Generation Sales	(15.9	)%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	19
Commercial	(10		)
Industrial	(5		)
Net Increase in Retail Generation Revenues	$	4

Wholesale generation revenues decreased by $2 million in the first three months of 2012, compared to the same period of 2011, due to lower revenues from sales to NGC from OE’s leasehold interests in Perry Unit 1 and Beaver Valley Unit 2.

Operating Expenses

Total operating expenses decreased by $6 million in the first three months of 2012, compared to the same period of 2011. The following table presents changes from the prior period by expense category:

Operating Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(31	)
Other operating expenses	25
Provision for depreciation	1
Amortization of regulatory assets, net	(1		)
Net Decrease in Operating Expenses	$	(6	)

Purchased power costs decreased in the first three months of 2012, compared to the same period of 2011, due to lower MWH purchases resulting from reduced generation sales requirements from warmer than normal weather and increased customer shopping. The increase in other operating expenses for the first three months of 2012 compared to the same period of 2011, was principally due to expenses associated with network integration transmission service charges that, prior to June 2011, were incurred by generation suppliers and are being recovered through the NMB transmission rider discussed above.

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JERSEY CENTRAL POWER & LIGHT COMPANY

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

JCP&L is a wholly owned, electric utility subsidiary of FE. JCP&L conducts business in New Jersey, by providing regulated electric transmission and distribution services in 3,200 square miles of northern, western and east central New Jersey. The area it serves has a population of approximately 2.7 million. JCP&L also has an ownership interest in a hydroelectric generating facility. JCP&L procures electric supply to serve its BGS customers through a statewide auction process approved by the NJBPU.

For additional information with respect to JCP&L, please see the information contained in FE’s Management’s Discussion and Analysis of Financial Condition and Results of Operations under the following subheadings, which information is incorporated by reference herein: Overview, Results of Operations - Regulatory Assets, Capital Resources and Liquidity, Market Risk Information, Credit Risk and Outlook.

Results of Operations

Net income increased by $3 million in the first three months of 2012, compared to the same period of 2011, resulting from decreased purchased power costs and amortization of regulatory assets, net, partially offset by lower revenues.

Revenues

Revenues decreased by $159 million, or 25%, in the first three months of 2012, compared to the same period of 2011. The decrease in revenues was due to lower distribution, retail generation and wholesale generation revenues.

Distribution revenues decreased by $51 million in the first three months of 2012, compared to the same period of 2011, primarily due to lower MWH deliveries and an NJBPU-approved rate reduction that became effective March 1, 2012, for all customer classes. Lower MWH deliveries were principally from residential customers, reflecting decreased weather-related usage in the first three months of 2012.

Decreases in distribution MWH deliveries and revenues in the first three months of 2012 compared to the same period of 2011 are summarized in the following tables:

Distribution MWH Deliveries	Decrease
Residential	(8.8	)%
Commercial	(0.3	)%
Industrial	(1.1	)%
Decrease in Distribution Deliveries	(4.3	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(27	)
Commercial	(18		)
Industrial	(6		)
Decrease in Distribution Revenues	$	(51	)

Retail generation revenues decreased by $63 million due to lower retail generation MWH sales in all customer classes primarily due to lower weather-related usage resulting from heating degree days that were 23% below 2011 levels and an increase in customer shopping levels to 48% compared to 41% in the same quarter of last year. Retail generation obligations are attributable to non-shopping customers and are satisfied by generation procured through full-requirements auctions. JCP&L defers the difference between retail generation revenues and purchased power costs, resulting in no material effect on earnings.

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Decreases in retail generation MWH sales and revenues in the first three months of 2012, compared to the same period of 2011, are summarized in the following tables:

Retail Generation MWH Sales	Decrease
Residential	(16.2	)%
Commercial	(14.6	)%
Industrial	(26.6	)%
Decrease in Retail Generation Sales	(16.1	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(45	)
Commercial	(14		)
Industrial	(4		)
Decrease in Retail Generation Revenues	$	(63	)

Wholesale generation revenues decreased by $43 million in the first three months of 2012, compared to the same period of 2011, primarily due to a decrease in PJM spot market energy sales, reflecting less volume available for sale as a result of the expiration of a NUG contract in August, 2011.

Operating Expenses

Total operating expenses decreased by $166 million in the first three months of 2012, compared to the same period of 2011. The following table presents changes from the prior period by expense category:

Operating Expenses - Changes	Increase (Decrease)
	(In millions)
Purchased power costs	$	(106	)
Other operating expenses	1
Provision for depreciation	4
Amortization of regulatory assets, net	(62		)
General taxes	(3		)
Net Decrease in Operating Expenses	$	(166	)

Purchased power costs decreased by $106 million in the first three months of 2012 due to the expiration of a NUG contract and a decrease in volumes required, resulting from warmer than normal weather and increased customer shopping. Amortization of regulatory assets, net, decreased by $62 million primarily due to the completion of the NJBPU-approved NUG deferred cost recovery.

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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 15d-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 March 31, 2012, 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 and JCP&L’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.        LEGAL PROCEEDINGS

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

ITEM 1A.    RISK FACTORS

For the quarter ended March 31, 2012, 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, 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 first quarter of 2012.

	Period
	January		February		March		First Quarter
Total Number of Shares Purchased(1)	163,030		165,753		1,325,407		1,654,190
Average Price Paid per Share	$	42.26	$	43.60	$	44.59	$	44.26
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	—		—		—		—

⁽¹⁾  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, DCPD, EDCP, Savings Plan, Director Compensation, Allegheny Energy, Inc. 1998 LTIP, Allegheny Energy, Inc. 2008 LTIP, 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 3.        DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.        MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.        OTHER INFORMATION

Not Applicable

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ITEM 6.        EXHIBITS

Exhibit Number
FirstEnergy
(A)(B)	10.1		Employment Agreement between FirstEnergy Corp. and Anthony J. Alexander, dated March 20, 2012.
	3.1		Amendment to the Amended Code of Regulations (Incorporated by reference to Appendix 1 to FirstEnergy's Definitive Proxy Statement filed on April 1, 2011).
(A)	12		Fixed charge ratio
(A)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2012, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements tagged as blocks of text and (v) document and entity information.
FES
(A)	4.1	(g)	Seventh Supplemental Indenture of FGCO, dated as of February 14, 2012.
(A)	4.2	(d)	Fourth Supplemental Indenture of NGC, dated as of February 14, 2012.
(A)(C)	10.1		First Amendment to Loan Agreement, dated as of February 14, 2012, between the Ohio Water Development Authority, as issuer, and FirstEnergy Nuclear Generation Corp.
(A)(D)	10.2		First Amendment to Loan Agreement, dated as of February 14, 2012, between the Ohio Air Quality Development Authority, as issuer, and FirstEnergy Generation Corp.
(A)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(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 March 31, 2012, 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
(A)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(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 March 31, 2012, 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
(A)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(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 March 31, 2012, 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.
(A)			Provided herein in electronic format as an exhibit.
(B)			Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.
(C)			This is an amendment to a Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp., dated as of December 1, 2005.
(D)			This is an amendment to a Form of Waste Water Facilities and Solid Waste Facilities Loan Agreement between Ohio Air Quality Development Authority and FirstEnergy Generation Corp. dated as of December 1, 2006.

* Users of this data are advised in accordance with Rule 406T of Regulation S-T promulgated by the SEC that this Interactive Data Files of FES, OE and JCP&L are 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, are 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 paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, neither FirstEnergy, FES, OE nor JCP&L 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.

98

SIGNATURES

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

May 1, 2012

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

OHIO EDISON COMPANY

Registrant

/s/ Harvey L. Wagner

Harvey L. Wagner 

Vice President, Controller

and Chief Accounting Officer 

JERSEY CENTRAL POWER & LIGHT COMPANY

Registrant

/s/ Marlene A. Barwood

Marlene A. Barwood

Controller

(Principal Accounting Officer) 

99

EX-4.1G

EXHIBIT 4.1g

SEVENTH SUPPLEMENTAL INDENTURE

__________

FIRSTENERGY GENERATION CORP.

TO

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.

(formerly known as The Bank of New York Trust Company, N.A.),

as Trustee

__________

Dated as of February 14, 2012

_________

Supplemental to Open-End Mortgage, General Mortgage

Indenture and Deed of Trust, Dated as of June 19, 2008

EXHIBIT 4.1g

THIS SEVENTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of February 14, 2012 between FIRSTENERGY GENERATION CORP., a corporation organized and existing under the laws of the State of Ohio (hereinafter called the “Company”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. (formerly known as The Bank of New York Trust Company, N.A.), a national banking association organized and existing under the laws of the United States of America, as Trustee (hereinafter called the “Trustee”) under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 19, 2008 (hereinafter called the “Original Indenture”) with the Company.

W I T N E S S E T H:

WHEREAS, the Company has heretofore duly executed and delivered to the Trustee the Original Indenture to secure Bonds of the Company, issuable in series, from time to time, in the manner and subject to the conditions set forth, and without limit as to principal amount except as provided in the Original Indenture which Original Indenture has been filed for record in the filing offices set forth on Schedule 1 attached hereto and incorporated herein by reference; and

WHEREAS, the Company has heretofore executed and delivered to the Trustee, a First Supplemental Indenture supplementing the Original Indenture dated as of June 25, 2008 (the “First Supplemental Indenture”), a Second Supplemental Indenture supplementing the Original Indenture dated as of March 1, 2009 (the “Second Supplemental Indenture”), a Third Supplemental Indenture supplementing the Original Indenture dated as of March 31, 2009 (the “Third Supplemental Indenture”), a Fourth Supplemental Indenture supplementing the Original Indenture dated as of June 15, 2009 (the “Fourth Supplemental Indenture”), a Fifth Supplemental Indenture supplementing the Original Indenture dated as of June 30, 2009 (the “Fifth Supplemental Indenture”), a Sixth Supplemental Indenture supplementing the Original Indenture dated as of December 1, 2009 (the “Sixth Supplemental Indenture”) and the Original Indenture, as supplemented by the aforementioned First Supplemental Indenture, Second Supplemental Indenture, Third Supplemental Indenture, Fourth Supplemental Indenture, Fifth Supplemental Indenture, the Sixth Supplemental Indenture and this Supplemental Indenture and any other indentures supplemental to the Original Indenture are herein collectively called the “Indenture”; and

WHEREAS, it is provided in the Indenture, among other things, that the Company shall execute and file with the Trustee and the Trustee, at the request of the Company, when required by the Indenture, shall join in the execution of indentures supplemental thereto, and which thereafter shall form a part thereof, for the purpose, among others of making amendments to the Indenture with the consents of the Bondholders; and

WHEREAS, the Company deems it advisable to enter into this Supplemental Indenture for the purpose of amending certain covenants of the Company contained in the Indenture so as to permit the Company to convert from an Ohio corporation to an Ohio limited liability company and to amend certain additional definitions and other provisions to be consistent therewith, and the Company has requested and hereby requests the Trustee to join in the execution of this Supplemental Indenture.

WHEREAS, all acts and things have been done and performed which are necessary to make this Supplemental Indenture, when duly executed and delivered, a valid, binding and legal instrument in accordance with its terms and for the purposes herein expressed; and the execution and delivery of this Supplemental Indenture have been in all respects duly authorized.

NOW THEREFORE, in consideration of the premises and in further consideration of the sum of One Dollar in lawful money of the United States of America paid to the Company by the Trustee at or before the execution and delivery of this Supplemental Indenture, the receipt whereof is hereby acknowledged, and of other good and valuable consideration, it is agreed by and between the Company and the Trustee as follows:

ARTICLE I

DEFINITIONS

SECTION 1.01. Terms Incorporated by Reference.

Except for the terms defined in this Supplemental Indenture, all capitalized terms used in this Supplemental Indenture have the respective meanings set forth in the Original Indenture.

SECTION 1.02. Rules of Construction. All references to any agreement refer to such agreement as modified, varied, supplemented, amended or restated from time to time by the parties thereto (including any permitted successors or assigns) in accordance with its terms.

ARTICLE II

AMENDMENTS TO ORIGINAL INDENTURE

SECTION 2.01 Definitions and Other Provisions of General Application. Section 1.01 of the Original Indenture is amended to replace the definition of “Person” with the following definition: “ “Person” means any individual, corporation, limited liability company, association, partnership, joint venture, trust or unincorporated organization or any Governmental Authority.”

SECTION 2.02 Representations and Covenants. Section 6.04 of the Original Indenture is amended and restated in its entirety to read as follows:

EXHIBIT 4.1g

“Section 6.04 Corporate Existence. Subject to the rights of the Company under Article XIII, the Company shall do or cause to be done all things necessary to preserve and keep in full force and effect its existence and the rights (charter and statutory) and franchises of the Company; provided, however, that the Company shall not be required to preserve any such right or franchise if, in the judgment of the Company, the preservation thereof is no longer desirable in the conduct of the business of the Company and the loss thereof would not adversely affect the interests of the Holders in any material respect.”

SECTION 2.03 Company May Consolidate, etc., Only on Certain Terms. Sections 13.01(a) and (b) of the Original Indenture are amended and restated as follows:

“The Company shall not consolidate with or merge into any other Person or convey, or otherwise transfer or lease, the Mortgaged Property as or substantially as an entirety to any Person, unless:

(a)    such consolidation, merger, conveyance, other transfer or lease shall be on such terms as shall fully preserve in all material respects the Lien and security of this Indenture and the rights and powers of the Trustee and the Holders of the Bonds hereunder;

(b)    the Person formed by such consolidation or into which the Company is merged or the Person which acquires by conveyance or other transfer, or which leases, the Mortgaged Property as or substantially as an entirety shall be a Person organized and existing under the laws of the United States of America, any state or territory thereof or the District of Columbia (such Person being hereinafter sometimes called the “Successor Corporation”) and shall execute and deliver to the Trustee an indenture supplemental hereto, in form recordable and satisfactory to the Trustee, which:”

SECTION 2.04 Merger into Company; Extent of Lien Hereof. Section 13.05(a) of the Original Indenture is amended and restated in its entirety to read as follows:

“(a)    Nothing in this Indenture shall be deemed to prevent or restrict any consolidation or merger after the consummation of which the Company would be the surviving or resulting entity, or any conveyance or other transfer or lease, subject to the Lien of this Indenture, of any part of the Mortgaged Property which does not constitute the entirety, or substantially the entirety, thereof;”

ARTICLE III

MISCELLANEOUS

SECTION 3.01    Except as herein otherwise expressly provided, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture; the Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals herein, all of which are made by the Company solely; and this Supplemental Indenture is executed and accepted by the Trustee, subject to all the terms and conditions set forth in the Indenture, as fully to all intents and purposes as if the terms and conditions of the Indenture were herein set forth at length.

SECTION 3.02    As supplemented by this Supplemental Indenture, the Indenture is in all respects ratified and confirmed, and the Indenture as herein defined, and this Supplemental Indenture, shall be read, taken and construed as one and the same instrument.

SECTION 3.03    Nothing in this Supplemental Indenture contained shall or shall be construed to confer upon any person other than a Holder of Bonds issued under the Indenture, the Company and the Trustee any right or interest to avail himself of any benefit under any provision of the Indenture or of this Supplemental Indenture.

SECTION 3.04    This Supplemental Indenture may be simultaneously executed in several counterparts and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.

EXHIBIT 4.1g

IN WITNESS WHEREOF, FIRSTENERGY GENERATION CORP., party of the first part hereto, and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., party of the second part hereto, have caused these presents to be executed in their respective names as of the day and year first above written.

	FIRSTENERGY GENERATION CORP.
By:	/s/ Steven R. Staub
	Steven R. Staub, Assistant Treasurer
	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. as Trustee
By:	/s/ Biagio S. Impala
	Biagio S. Impala, Vice President

Signature Page to Seventh Supplemental Indenture

FirstEnergy Generation Corp.

EXHIBIT 4.1g

STATE OF OHIO        )

)ss.:

COUNTY OF        )

On the 14th day of February, 2012, personally appeared before me, a Notary Public in and for the said County and State aforesaid, Steven R. Staub, to me known and known to me to be the Assistant Treasurer of FIRSTENERGY GENERATION CORP., the corporation which executed the foregoing instrument, and who severally acknowledged that he did sign such instrument as such Assistant Treasurer of FIRSTENERGY GENERATION CORP., the same is his free act and deed and the free and corporate act and deed of said corporation.

IN WITNESS WHEREOF, I have hereunto set my hand and seal the 14th day of February, 2012.

/s/ Michele A. Buchtel

Michele A. Buchtel, Notary Public

Commission Expires 08/28/2016

Signature Page to Seventh Supplemental Indenture

FirstEnergy Generation Corp.

EXHIBIT 4.1g

STATE OF OHIO        )

)ss.:

COUNTY OF CUYAHOGA    )

On the 14th day of February, 2012, personally appeared before me, a Notary Public in and for the said County and State aforesaid, Biagio S. Impala, to me known and known to me to be a Vice President of THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., the national banking association which executed the foregoing instrument, and who severally acknowledged that he did sign such instrument as such Vice President for and on behalf of said national banking association and that the same is his free act and deed and the free and corporate act and deed of said national banking association.

IN WITNESS WHEREOF, I have hereunto set my hand and seal the 14th day of February, 2012.

/s/ Susan Demaske

Susan Demaske, Attorney at Law, Notary Public

Commission Expires [No expiration date]

Signature Page to Seventh Supplemental Indenture

FirstEnergy Generation Corp.

EXHIBIT 4.1g

The Bank of New York Mellon Trust Company, N.A. hereby certifies that its precise name and address as Trustee is:

The Bank of New York Mellon Trust Company, N.A.

Global Corporate Trust

1660 West 2^nd Street, Suite 830

Cleveland, Ohio 44113

	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
By:	/s/ Biagio S. Impala
	Biagio S. Impala, Vice President

Signature Page to Seventh Supplemental Indenture

FirstEnergy Generation Corp.

EXHIBIT 4.1g

THIS INSTRUMENT PREPARED BY:

Lucas F. Torres

Akin Gump Strauss Hauer & Feld LLP

One Bryant Park

New York, NY 10036

EXHIBIT 4.1g

Schedule 1 Filing Offices For the Original Indenture
Plant	Jurisdiction/Filing Office	Recording Information	Date filed
Ashtabula Plant	Ashtabula County - Office of the County Recorder of Ashtabula County, Ohio	Instrument No. 200800007364 Volume 436 Page 1732	6/27/2008
Bay Shore Plant	Lucas County - Office of the County Recorder of Lucas County, Ohio	Instrument No. 20080627-0032756	6/27/2008
Bruce Mansfield Plant	Beaver County - Office of the County Recorder of Beaver County, Pennsylvania	Instrument No. 3326465	6/27/2008
Burger Plant	Belmont County - Office of the County Recorder of Belmont County, Ohio	Instrument No. 200800004786 Volume 0157 Page 172	6/27/2008
Eastlake Plant	Lake County - Office of the County Recorder of Lake County, Ohio	Instrument No. 2008R018408	6/27/2008
Edgewater Plant and West Lorain Plant	Lorain County - Office of the County Recorder of Lorain County, Ohio	Instrument No. 2008-0259135	6/27/2008
Fremont Plant [Released]	Sandusky County - Office of the County Recorder of Sandusky County, Ohio	Instrument No. 200800004585 Official Record Book 66 Page 708 Official Record Book 105 Page 732 - 756	06/27/2008 Release date: 7/28/2011
Lake Shore Plant	Cuyahoga County - Office of the County Recorder of Cuyahoga County, Ohio	Instrument No. 200806270329	6/27/2008
Mad River Plant	Clark County - Office of the County Recorder of Clark County, Ohio	Instrument No. 200800010888 Official Record Volume 1852 Page 1946 Instrument No. 200800011009 Official Record Volume 1853 Page 18	06/27/2008 06/30/2008 (Re-recorded)
Richland Plant [Released]	Defiance County - Office of the County Recorder of Defiance County, Ohio	Instrument No. 200800003811 Official Record Book 327 Page 482 Official Record Book 356 Page 734-758	06/27/2008 Release date: 10/21/2011
Sammis Plant	Jefferson County - Office of the County Recorder of Jefferson County, Ohio	Instrument No. 232633 Official Record Volume 851 Page 344	6/27/2008
Seneca Plant	Warren County - Office of the County Recorder of Warren County, Pennsylvania	Instrument No. 2008-2962	6/27/2008
Stryker Plant [Released]	Williams County - Office of the County Recorder of Williams County, Ohio	Instrument No. 200800082091 Official Record Book 0240 Page 0516 Official Record Book 280 Page 85-109	06/27/2008 Release date: 10/20/2011

EX-4.2D

EXHIBIT 4.2d

FOURTH SUPPLEMENTAL INDENTURE

__________

FIRSTENERGY NUCLEAR GENERATION CORP.

TO

THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.

(formerly known as The Bank of New York Trust Company, N.A.),

as Trustee

__________

Dated as of February 14, 2012

_________

Supplemental to Open-End Mortgage, General Mortgage

Indenture and Deed of Trust, Dated as of June 1, 2009

EXHIBIT 4.2d

THIS FOURTH SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of February 14, 2012 between FIRSTENERGY NUCLEAR GENERATION CORP., a corporation organized and existing under the laws of the State of Ohio (hereinafter called the “Company”), and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. (formerly known as The Bank of New York Trust Company, N.A.), a national banking association organized and existing under the laws of the United States of America, as Trustee (hereinafter called the “Trustee”) under the Open-End Mortgage, General Mortgage Indenture and Deed of Trust, dated as of June 1, 2009 (hereinafter called the “Original Indenture”) with the Company.

W I T N E S S E T H:

WHEREAS, the Company has heretofore duly executed and delivered to the Trustee the Original Indenture to secure Bonds of the Company, issuable in series, from time to time, in the manner and subject to the conditions set forth, and without limit as to principal amount except as provided in the Original Indenture which Original Indenture has been filed for record in the filing offices set forth on Schedule 1 attached hereto and incorporated herein by reference; and

WHEREAS, the Company has heretofore executed and delivered to the Trustee, a First Supplemental Indenture supplementing the Original Indenture dated as of June 15, 2009 (the “First Supplemental Indenture”), a Second Supplemental Indenture supplementing the Original Indenture dated as of June 30, 2009 (the “Second Supplemental Indenture”), a Third Supplemental Indenture supplementing the Original Indenture dated as of December 1, 2009 (the “Third Supplemental Indenture”) and the Original Indenture, as supplemented by the aforementioned First Supplemental Indenture, Second Supplemental Indenture, Third Supplemental Indenture and this Supplemental Indenture and any other indentures supplemental to the Original Indenture are herein collectively called the “Indenture”; and

WHEREAS, it is provided in the Indenture, among other things, that the Company shall execute and file with the Trustee and the Trustee, at the request of the Company, when required by the Indenture, shall join in the execution of indentures supplemental thereto, and which thereafter shall form a part thereof, for the purpose, among others of making amendments to the Indenture with the consents of the Bondholders; and

WHEREAS, the Company deems it advisable to enter into this Supplemental Indenture for the purpose of amending certain covenants of the Company contained in the Indenture so as to permit the Company to convert from an Ohio corporation to an Ohio limited liability company and to amend certain additional definitions and other provisions to be consistent therewith, and the Company has requested and hereby requests the Trustee to join in the execution of this Supplemental Indenture.

WHEREAS, all acts and things have been done and performed which are necessary to make this Supplemental Indenture, when duly executed and delivered, a valid, binding and legal instrument in accordance with its terms and for the purposes herein expressed; and the execution and delivery of this Supplemental Indenture have been in all respects duly authorized.

NOW THEREFORE, in consideration of the premises and in further consideration of the sum of One Dollar in lawful money of the United States of America paid to the Company by the Trustee at or before the execution and delivery of this Supplemental Indenture, the receipt whereof is hereby acknowledged, and of other good and valuable consideration, it is agreed by and between the Company and the Trustee as follows:

ARTICLE I

DEFINITIONS

SECTION 1.01.    Terms Incorporated by Reference.

Except for the terms defined in this Supplemental Indenture, all capitalized terms used in this Supplemental Indenture have the respective meanings set forth in the Original Indenture.

SECTION 1.02.    Rules of Construction. All references to any agreement refer to such agreement as modified, varied, supplemented, amended or restated from time to time by the parties thereto (including any permitted successors or assigns) in accordance with its terms.

ARTICLE II

AMENDMENTS TO ORIGINAL INDENTURE

SECTION 2.01 Definitions and Other Provisions of General Application. Section 1.01 of the Original Indenture is amended to replace the definition of “Person” with the following definition: “ “Person” means any individual, corporation, limited liability company, association, partnership, joint venture, trust or unincorporated organization or any Governmental Authority.”

SECTION 2.02 Representations and Covenants. Section 6.04 of the Original Indenture is amended and restated in its entirety to read as follows:

“Section 6.04 Corporate Existence. Subject to the rights of the Company under Article XIII, the Company shall do or cause to be done all things necessary to preserve and keep in full force and effect its existence and the rights (charter and statutory) and franchises of the Company; provided, however, that the

EXHIBIT 4.2d

Company shall not be required to preserve any such right or franchise if, in the judgment of the Company, the preservation thereof is no longer desirable in the conduct of the business of the Company and the loss thereof would not adversely affect the interests of the Holders in any material respect.”

SECTION 2.03 Company May Consolidate, etc., Only on Certain Terms. Sections 13.01(a) and (b) of the Original Indenture are amended and restated as follows:

“The Company shall not consolidate with or merge into any other Person or convey, or otherwise transfer or lease, the Mortgaged Property as or substantially as an entirety to any Person, unless:

(a)    such consolidation, merger, conveyance, other transfer or lease shall be on such terms as shall fully preserve in all material respects the Lien and security of this Indenture and the rights and powers of the Trustee and the Holders of the Bonds hereunder;

(b)    the Person formed by such consolidation or into which the Company is merged or the Person which acquires by conveyance or other transfer, or which leases, the Mortgaged Property as or substantially as an entirety shall be a Person organized and existing under the laws of the United States of America, any state or territory thereof or the District of Columbia (such Person being hereinafter sometimes called the “Successor Corporation”) and shall execute and deliver to the Trustee an indenture supplemental hereto, in form recordable and satisfactory to the Trustee, which:”

SECTION 2.04 Merger into Company; Extent of Lien Hereof. Section 13.05(a) of the Original Indenture is amended and restated in its entirety to read as follows:

“(a)    Nothing in this Indenture shall be deemed to prevent or restrict any consolidation or merger after the consummation of which the Company would be the surviving or resulting entity, or any conveyance or other transfer or lease, subject to the Lien of this Indenture, of any part of the Mortgaged Property which does not constitute the entirety, or substantially the entirety, thereof;”

ARTICLE III

MISCELLANEOUS

SECTION 3.01    Except as herein otherwise expressly provided, no duties, responsibilities or liabilities are assumed, or shall be construed to be assumed, by the Trustee by reason of this Supplemental Indenture; the Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals herein, all of which are made by the Company solely; and this Supplemental Indenture is executed and accepted by the Trustee, subject to all the terms and conditions set forth in the Indenture, as fully to all intents and purposes as if the terms and conditions of the Indenture were herein set forth at length.

SECTION 3.02    As supplemented by this Supplemental Indenture, the Indenture is in all respects ratified and confirmed, and the Indenture as herein defined, and this Supplemental Indenture, shall be read, taken and construed as one and the same instrument.

SECTION 3.03    Nothing in this Supplemental Indenture contained shall or shall be construed to confer upon any person other than a Holder of Bonds issued under the Indenture, the Company and the Trustee any right or interest to avail himself of any benefit under any provision of the Indenture or of this Supplemental Indenture.

SECTION 3.04    This Supplemental Indenture may be simultaneously executed in several counterparts and all such counterparts executed and delivered, each as an original, shall constitute but one and the same instrument.

EXHIBIT 4.2d

IN WITNESS WHEREOF, FIRSTENERGY NUCLEAR GENERATION CORP., party of the first part hereto, and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., party of the second part hereto, have caused these presents to be executed in their respective names as of the day and year first above written.

	FIRSTENERGY NUCLEAR GENERATION CORP.
By:	/s/ Steven R. Staub
	Steven R. Staub, Assistant Treasurer
	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. as Trustee
By:	/s/ Biagio S. Impala
	Biagio S. Impala, Vice President

Signature Page to Fourth Supplemental Indenture

FirstEnergy Nuclear Generation Corp.

EXHIBIT 4.2d

STATE OF OHIO        )

)ss.:

COUNTY OF        )

On the 14th day of February, 2012, personally appeared before me, a Notary Public in and for the said County and State aforesaid, Steven R. Staub, to me known and known to me to be the Assistant Treasurer of FIRSTENERGY NUCLEAR GENERATION CORP., the corporation which executed the foregoing instrument, and who severally acknowledged that he did sign such instrument as such Assistant Treasurer of FIRSTENERGY NUCLEAR GENERATION CORP., the same is his free act and deed and the free and corporate act and deed of said corporation.

IN WITNESS WHEREOF, I have hereunto set my hand and seal the 14th day of February, 2012.

/s/ Michele A. Buchtel

Michele A. Buchtel, Notary Public

Commission Expires 08/28/2016

Signature Page to Fourth Supplemental Indenture

FirstEnergy Nuclear Generation Corp.

EXHIBIT 4.2d

STATE OF OHIO        )

)ss.:

COUNTY OF CUYAHOGA    )

On the 14th day of February, 2012, personally appeared before me, a Notary Public in and for the said County and State aforesaid, Biagio S. Impala, to me known and known to me to be a Vice President of THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A., the national banking association which executed the foregoing instrument, and who severally acknowledged that he did sign such instrument as such Vice President for and on behalf of said national banking association and that the same is his free act and deed and the free and corporate act and deed of said national banking association.

IN WITNESS WHEREOF, I have hereunto set my hand and seal the 14th day of February, 2012.

/s/ Susan Demaske

Susan Demaske, Attorney at Law, Notary Public

Commission Expires [No expiration date]

Signature Page to Fourth Supplemental Indenture

FirstEnergy Nuclear Generation Corp.

EXHIBIT 4.2d

The Bank of New York Mellon Trust Company, N.A. hereby certifies that its precise name and address as Trustee is:

The Bank of New York Mellon Trust Company, N.A.

Global Corporate Trust

1660 West 2^nd Street, Suite 830

Cleveland, Ohio 44113

	THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A.
By:	/s/ Biagio S. Impala
	Biagio S. Impala, Vice President

Signature Page to Fourth Supplemental Indenture

FirstEnergy Nuclear Generation Corp.

EXHIBIT 4.2d

THIS INSTRUMENT PREPARED BY:

Lucas F. Torres

Akin Gump Strauss Hauer & Feld LLP

One Bryant Park

New York, NY 10036

EXHIBIT 4.2d

Schedule 1 Filing Offices For the Original Indenture
Plant	Jurisdiction/Filing Office	Recording Information	Date filed
Davis Besse	Office of the County Recorder of Ottawa County, Ohio	OR Volume 1278, Page 204	June 12, 2009
Perry	Office of the County Recorder of Lake County, Ohio	Document # 2009R015200	June 12, 2009
Beaver Valley	Office of the County Recorder of Beaver County, Pennsylvania	Instrument No. 3346070	June 12, 2009

EX-10.1

EXHIBIT 10.1

Execution Copy

EMPLOYMENT AGREEMENT

This Employment Agreement (this “Agreement”), effective as of March 20, 2012 (the “Effective Date”), is made between FirstEnergy Corp. (the “Company”) and Anthony J. Alexander (“Executive”).

WHEREAS, Executive is currently President and Chief Executive Officer of the Company; and

WHEREAS, Executive and the Company desire to more fully establish and reduce to writing the fundamental terms and conditions of Executive's employment and the parties' respective rights and obligations with respect thereto; and

WHEREAS, the Board of Directors of the Company (the “Board”) has determined that it is in the best interests of the shareholders of the Company to take further action to secure the continued services of Executive, consistent with FirstEnergy's executive compensation philosophy;

NOW, THEREFORE, in consideration of the foregoing and of the respective covenants and agreements of the parties herein contained, the parties hereto agree as follows:

1.    Term of Employment. The Company hereby agrees to continue to employ Executive, and Executive hereby agrees to continue to serve the Company, on the terms and conditions set forth herein, for the period commencing as of the Effective Date and ending on April 30, 2016, unless earlier terminated under the terms and conditions hereof (the “Employment Period”). Upon termination of the Employment Period for any reason, Executive shall be entitled to any and all of his retirement and pension benefits under all qualified and non-qualified plans adopted by the Company in accordance with and subject to the terms of such plans.

2.    Position. Executive shall serve as President and Chief Executive Officer; provided that, the Board, at any time, may elect another person as the President of the Company, who shall assume the duties of such position and report to Executive and, further, the Board may elect another person as Chief Executive Officer of the Company at any time who shall assume the duties of such position and report to Executive. In the event the Board elects to name another person the President and/or the Chief Executive Officer, then the Executive shall be elected Executive Chairman or Chairman of the Board and remain Chief Executive Officer, as applicable. During the Employment Period, Executive shall be considered for nomination and election to the Board and agrees to serve if so elected. Upon termination of the Employment Period, Executive shall resign from the Board and shall not accept or seek a nomination to the Board thereafter.

3.    Duties. Executive shall be responsible for the general management and operation of the Company and shall have such powers and duties as are commensurate with his office and position as the Chief Executive Officer and President of the Company, and, as applicable, as Chairman of the Board (while he holds such offices as described above), and such other powers and duties as may from time to time be assigned by the Board. Executive shall devote his full business time and attention to the continued success of the business and affairs of the Company throughout the Employment Period. Subject to Board approval, Executive may serve on corporate, civic or charitable boards or committees to the extent that such service does not materially interfere with the performance of his duties under this Agreement or as a member of the Board.

4.    Compensation.

(a)    Base Salary. During the Employment Period, Executive shall receive an annual base salary in an amount determined consistent with the Company's compensation philosophy (“Base Salary”) and payable in accordance with the prevailing payroll practices of the Company.

(b)    Incentive Compensation. During the Employment Period, Executive shall be eligible to participate in the FirstEnergy Corp. Short-Term Incentive Program (the “STIP”) and the FirstEnergy Corp. Long-Term Incentive Program (the “LTIP”) subject to and on a consistent basis with the terms, conditions and overall administration of those programs.

(c)    Retention Stock Award. As of the Effective Date, the Compensation Committee will grant to Executive a restricted stock award (the “New Restricted Stock Award”) covering 200,000 common shares of the Company that vests as follows: 25% on December 31, 2013; 25% on December 31, 2014; and 50% on December 31, 2015, in each case plus accrued dividends on such shares. The New Restricted Stock Award shall vest in full in the event that this Agreement is terminated (1) voluntarily by the Executive upon notice if the total compensation opportunity of the Executive at any time is reduced below the opportunity established for 2012; provided, that, such vesting shall not occur if (i) such reduction is also applicable to other Company senior executives generally; or (ii) the Company remedies such reduction in total compensation opportunity within thirty (30) days following the notice of voluntary termination from Executive under this Section 4(c)(1); (2) by the Board without Cause; or (3) as a result of death or Disability of the Executive. If this Agreement is terminated by the Board for Cause, or voluntarily by the Executive at any time prior to any vesting date, except as provided above, then the unvested portion of the New Restricted Stock Award shall be forfeited and no prorating shall be applicable. The foregoing New Restricted Stock Award is made pursuant to the FirstEnergy Corp. 2007 Incentive Plan and shall be subject to additional terms and conditions set forth in a separate award agreement consistent with the terms of this Agreement. Following a Change in Control, the terms of this Section 4 shall govern the treatment of the

EXHIBIT 10.1

foregoing New Restricted Stock Award upon termination of Executive's employment, whether voluntarily or involuntarily, and not the terms of any Company plan applicable to termination of employment following a Change in Control.

(d)    Treatment of RS41. In accordance with the terms of such agreement, the Board has determined that the restricted stock award under RS41 (“RS41”) shall be 100% vested as of the Effective Date of this Agreement. For the avoidance of doubt, the Share Value Protection Rights contained in RS41 shall no longer be applicable.

(e)    Participation in Benefit Plans. During the Employment Period, in addition to the aforementioned plans, except as otherwise provided in this Agreement, Executive shall be entitled to continue to participate in or receive benefits under all other employee benefit plans made available by the Company to its senior executives, subject to and on a basis consistent with the terms, conditions and overall administration of those plans. Executive's right to participate in any benefit plan shall be subject to the applicable eligibility criteria for participation and Executive shall not be entitled to any benefits under, or based on, any benefit plan for any purposes of this Agreement if Executive does not during the Employment Period satisfy the eligibility criteria for participation in such plan.

(f)    Expenses. During the Employment Period, Executive shall be entitled to receive prompt reimbursement for all reasonable business expenses incurred by him (in accordance with Company practice) in performing services hereunder, provided that Executive properly accounts therefor in accordance with Company policies or guidelines.

(g)    Vacations. During the Employment Period, Executive shall be entitled to the same number of paid vacation days in each year determined by the Company from time to time for its other senior executive officers, to be taken at such time or times as is reasonably desired by Executive. Executive may use his good faith judgment and reasonable discretion in determining whether out-of-office time should be considered vacation.

(h)    Other Benefits. During the Employment Period, Executive shall be entitled to continue to receive the fringe benefits appertaining to his position with the Company in accordance with present practice and financial planning services for an additional year. For security reasons, Executive is required to use corporate aircraft for all travel, including for limited personal use.

5.    Effects of Termination of Employment

(a)    Either the Board or the Executive may terminate the Executive's employment at any time and for any reason during the Employment Period. Upon termination or expiration of this Agreement, Executive shall receive his Base Salary up through the date of termination and all accrued and/or vested benefits, compensation or awards of any kind to which he is entitled under the applicable plans and award agreements and as provided in this Agreement.

(b)    Notice of Termination. Any termination of employment by the Company, or by Executive, shall be communicated by notice of termination to the other party, as applicable, given in accordance with Section 8. Except as provided in Section 4(c)(1) (voluntary termination of employment by Executive for a reduction in compensation), Executive shall endeavor to provide twelve (12) months prior notice of his intention to retire, provided that the failure to provide such notice shall not create any rights of any kind on the part of the Company nor in any way diminish Executive's rights under this Agreement.

6.    Payment Obligations. Other than as set forth in the Deferred Compensation Plan or the SERP, the Company's obligations to pay the severance benefits or make any other payments described in Section 5(a) shall not be affected by any set-off, counterclaim, recoupment, defense or other right which the Company or any of its subsidiaries may have against Executive or anyone else. Nothing in this Agreement entitles Executive to participation or continued participation in the Deferred Compensation Plan, the SERP or any other plan, program or arrangement of the Company unless participation is specifically designated under, and in accordance with, the applicable plan, program or arrangement.

7.    Restrictive Covenants.

(a)    Non-Competition; Non-Disclosure; Non-Solicitation. During the Employment Period andfor a period of twenty-four (24)monthsthereafter, Executive shall not on his own account without the consent of the Company, or as a shareholder, employee, officer, director, consultant or otherwise, engage directly or indirectly in any business or enterprise which is in competition with the Company, an Affiliate or any Subsidiary in a market locatedin any state or states in which, on the date of expiration of the Employment Period, the Company sells, has sold or reasonably intends to sell to Customers. For all purposes of this Agreement, the words "competition with the Company, an Affiliate or any Subsidiary" shall mean:

i.    Directly participating or engaging, on the behalf of other parties, in the purchase or sale of products, supplies or services of the kind, nature or description of those sold by the Company, an Affiliate or any Subsidiary;

ii.    Soliciting, diverting, taking away or attempting to take away any of the Customers with respect to their purchase or sale, or potential purchase or sale, of the products, supplies or services of the kind, nature or description of those sold or reasonably intended to be sold by the Company, an Affiliate or any Subsidiary or the business or patronage of any such Customers with respect to their purchase or sale, or potential purchase or sale, of the products, supplies or services of the kind, nature or description of those sold or reasonably intended to be sold by the Company, an Affiliate or

EXHIBIT 10.1

any Subsidiary;

iii.    Soliciting, enticing, luring, employing or endeavoring to employ any employees of the Company, an Affiliate or any Subsidiary;

iv.    Divulging to others or using for Executive's own benefit any confidential information obtained during the course of Executive's employment with the Company, an Affiliate or any Subsidiary relative to sales, services, processes, methods, machines, manufacturers, compositions, ideas, improvements, patents, trademarks, or inventions belonging to or relating to the affairs of the Company, an Affiliate or any Subsidiary;

v.    Divulging to others or using to Executive's own benefit any trade secrets belonging to the Company, an Affiliate or any Subsidiary obtained during the course of Executive's employment or that Executive became aware of as a consequence of his employment.

The term “Customer” shall mean any person, firm, association, corporation or other entity to which the Company, an Affiliate or any Subsidiary sells, has sold or reasonably intends to sell the products, supplies or services of the Company, an Affiliate or any Subsidiary within the thirty (30) month period immediately preceding the date of expiration of the Employment Period. The term “Affiliate” and “Subsidiary” shall be as defined in the FirstEnergy Corp. Change in Control Severance Plan.

However, nothing herein contained shall prevent Executive from purchasing and holding for investment less than 5% of the shares of any corporation the shares of which are regularly traded either on a national securities exchange or in the over-the-counter market, and notwithstanding any provision hereof, Executive may disclose to any and all persons, without limitation of any kind, the tax treatment and any facts that may be relevant to the tax structure of the transactions contemplated by this Agreement, other than any information for which nondisclosure is reasonably necessary in order to comply with applicable federal or state securities laws, and except that, with respect to any document or other information that in either case contains information concerning the tax treatment or tax structure of such transactions as well as other information, this paragraph shall apply only to such portions of the document or similar item that is relevant to an understanding of such tax treatment or tax structure.

(b)    Non-Disparagement. Executive and the Company agree that neither party shall disparage the other nor shall either party communicate to any person and/or entity in a manner that is disrespectful, demeaning, and/or insulting toward the other party; provided, that nothing contained herein shall preclude either party from providing truthful testimony in any trial, deposition, hearing, or other proceeding as required by law.

8.    Notice. All notices, requests and other communications under this Agreement shall be in writing and shall be deemed to have been duly given (a) when hand delivered, (b) when dispatched by electronic facsimile transmission (with receipt electronically confirmed), (c) one business day after being sent by recognized overnight delivery service, or (d) three business days after being sent by registered or certified mail, return receipt requested, postage prepaid, and in each case addressed as follows (or addressed as otherwise specified by notice under this Section):

If to Executive:

Mr. Anthony J. Alexander

Akron, OH 44308

If to the Company:

Secretary

FirstEnergy

76 South Main Street

Akron, OH 44308

9.    Withholding. The Company may withhold from any amounts payable under or in connection with this Agreement all federal, state, local and other taxes as may be required to be withheld by the Company under applicable law or governmental regulation or ruling.

10.    Amendments; Waivers; Jurisdiction. No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing, and is signed by Executive and by another executive officer of the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Ohio. Executive and the Company each agree that the state and federal courts located in the State of Ohio shall have jurisdiction in any action, suit or proceeding against Executive or the Company based on or arising out of this Agreement and each of Executive and the Company hereby: (a) submits to the personal jurisdiction of such courts; (b) consents to service of process in connection with any such action, suit or proceeding; and (c) waives any other requirement (whether imposed by statute, rule of court or otherwise) with respect to personal jurisdiction, venue or service of process.

11.    Remedies; Validity. Executive and the Company acknowledge and agree that the restrictive covenants contained in Section 7 are of a special nature and that any breach, violation or evasion by Executive of the terms of Section 7 will

EXHIBIT 10.1

result in immediate and irreparable injury and continuing damage to the Company and its business, for which there is no adequate remedy at law, and will cause damage to the Company in amounts difficult to ascertain. Accordingly, the Company, its Affiliates and Subsidiaries and their successors and assigns, shall be entitled to temporary and permanent injunctive relief and to such further relief, including damages, as is proper under the circumstances.

The invalidity or unenforceability of any provision or provisions of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect to the maximum extent permitted and that the Agreement shall be enforceable as if such void or unenforceable provision or term had never been a part hereof. If any portion of Section 7 shall be found by a court of competent jurisdiction to be invalid or unenforceable, such court may exercise its discretion in reforming such provisions to the end that Executive shall be subject to non-disclosure, non-competition, non-solicitation or non-disparagement covenants that are reasonable under the circumstances and enforceable by the Company.

12.    Code Section 409A.

(a)If Executive is a Specified Employee, as determined under the Company's policy for determining Specified Employees on the date of his Termination of Employment, all payments, benefits, or reimbursements provided under this Agreement that would otherwise be paid or provided during the first six (6) months following such Termination of Employment (other than payments, benefits, or reimbursements that are treated as separation pay under Section 1.409A-1(b)(9)(v) of the Treasury Regulations or short-term deferrals) shall be accumulated through and paid or provided (together with interest at the applicable federal rate under Code Section 7872(f)(2)(A), in effect on the date of the Termination of Employment) on the first business day following the six (6) month anniversary of such Termination of Employment. Notwithstanding the foregoing, payments delayed pursuant to this Section 13(a) shall commence on Executive's death prior to the end of the six (6) month period.

(b)Any reimbursement of expenses or in-kind benefits provided under this Agreement (other than reimbursements or in-kind benefits that are treated as separation pay under Section 1.409A-1(b)(9)(v) of the Treasury Regulations), shall be subject to the following additional rules: (i) any reimbursement of eligible expenses shall be paid as they are incurred (but not prior to the end of the six-month delay period set forth in Section 13(a)); provided that Executive first provides documentation thereof in reasonable detail not later than sixty (60) days following the end of the calendar year in which the eligible expenses were incurred: (ii) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during any calendar year shall not affect the amount of expenses eligible for reimbursement, or in-kind benefits to be provided, during any other calendar year; and (iii) the right to reimbursement or in-kind benefits shall not be subject to liquidation or exchange for another benefit.

(c)    It is intended that the payments and benefits provided under this Agreement shall either be exempt from application of, or comply with, the requirements of Code Section 409A.  This Agreement shall be construed, administered, and governed in a manner that effects such intent, and the Company shall not take any action that would be inconsistent with such intent. Without limiting the foregoing, the payments and benefits provided under this Agreement may not be deferred, accelerated, extended, paid out, or modified in a manner that would result in the imposition of an additional tax under Code Section 409A upon Executive. Although the Company shall use its best efforts to avoid the imposition of taxation, interest and penalties under Code Section 409A, the tax treatment of the benefits provided under this Agreement is not warranted or guaranteed. Neither the Company, its Affiliates or Subsidiaries nor their respective boards of directors shall be held liable for any taxes, interest, penalties, or other similar monetary amounts owed by Executive or other taxpayers as a result of the Agreement. If Executive is required to execute, submit and not revoke a release of claims against the Company in order to receive the payment of benefits hereunder as a result of the terms of this Agreement and the period in which to execute, submit and not revoke the release begins in a first taxable year and ends in a second taxable year, any payment to which Executive would be entitled hereunder will be paid in the second taxable year, but no later than the end of the payment period specified in this Agreement.

13.    Counterparts; Headings; Definitions. This Agreement may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument. The headings contained herein are for reference purposes only and shall not in any way affect the meaning or interpretation of this Agreement. Any capitalized terms used but not defined in this Agreement will have the meaning attributed to them under the FirstEnergy Corp. 2007 Incentive Plan or successor plans thereto.

14.    Clawback of Incentive-Based Compensation. Notwithstanding any other provision in this Agreement to the contrary, Executive agrees that any “incentive-based compensation” within the meaning of Section 10D of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), will be subject to claw-back by the Company in the manner required by Section 10D(b)(2) of the Exchange Act, as determined by the applicable rules and regulations promulgated thereunder from time to time by the U.S. Securities and Exchange Commission, as may be implemented by the Board or Compensation Committee from time to time.

15.    Binding Agreement; Successors; Assignment. This Agreement shall inure to the benefit of and be binding upon Executive's personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If Executive should die while any amounts would still be payable to him hereunder if he had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to Executive's devisee, legatee, or other designee or, if there be no such designee, to Executive's estate. This Agreement shall inure to the benefit of and be binding upon the successors and assigns of the Company, including, without limitation, any person acquiring directly or indirectly all or substantially all of the assets of the Company, whether by merger, consolidation, sale or otherwise (and such successor shall thereafter be deemed the “Company” for the purposes of this Agreement). Except as provided above, this Agreement may not be

EXHIBIT 10.1

assigned by either party without the prior written consent of the other party.

16.    Agreement Controls. The terms of this Agreement shall take precedence, and control the rights and obligations of the parties, if they conflict with the terms of any other contracts, plans, programs, agreements, arrangements, awards or other documents or understandings between or involving the parties.

[Remainder of page intentionally blank]

EXHIBIT 10.1

IN WITNESS WHEREOF, the parties have executed this Agreement effective as of the date and year first above written.

FIRSTENERGY CORP.

By:	/s/ George M. Smart
	George M. Smart, Chairman
	"Company"
	/s/ Anthony J. Alexander
	Anthony J. Alexander
	"Executive"

79528/RPR

EX-10.2

EXHIBIT 10.2

FIRST AMENDMENT TO LOAN AGREEMENT

THIS FIRST AMENDMENT TO LOAN AGREEMENT (the “First Amendment”), dated as of February 14, 2012 by and between the OHIO WATER DEVELOPMENT AUTHORITY (the “Issuer”) and FIRSTENERGY NUCLEAR GENERATION CORP. (the “Company”), to the Loan Agreement, dated as of December 1, 2005, entered into by the Issuer and the Company in connection with the issuance by the Issuer of $82,800,000 State of Ohio Pollution Control Revenue Refunding Bonds Series 2005-B (FirstEnergy Nuclear Generation Corp. Project) (the “Agreement”), with capitalized terms used herein and not otherwise defined herein having the meanings ascribed to such terms in the Agreement;

W I T N E S S E T H :

WHEREAS, the Issuer has issued $82,800,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2005-B (FirstEnergy Nuclear Generation Corp. Project) (the “Bonds”) pursuant to Chapters 6121 and 6123 of the Ohio Revised Code and a Trust Indenture dated as of December 1, 2005 between the Issuer and the trustee thereunder (the “Trustee”), currently The Bank of New York Mellon Trust Company, N.A. (the “Indenture”), for the purpose of assisting the Company in the refinancing of a portion of the cost of the acquiring, constructing and installing certain facilities comprising “waste water facilities” and “solid waste facilities” as defined in Sections 6121.01 and 6123.01 of the Ohio Revised Code; and

WHEREAS, the Company has determined that it is in its best interests to pursue converting from an Ohio corporation to an Ohio limited liability company; and

WHEREAS, the Waste Water Facilities and Solid Waste Facilities Loan Agreement dated as of December 1, 2005 between the Issuer and the Company (the “Loan Agreement”) provides that the Issuer and the Company may enter into amendments and supplements to the Loan Agreement for certain purposes and with the consent of the holders of at least a majority in aggregate principal amount of the Bonds then Outstanding; and

WHEREAS, consistent with the foregoing, and pursuant to the requirements of Section 15.03 of the Indenture, the Issuer and the Company have determined to amend the Agreement to remove references to “corporate” existence; and

WHEREAS, having determined that at least a majority in aggregate principal amount of the Bonds Outstanding have consented to the amendments to the Loan Agreement, the Trustee has consented to this First Amendment to the Agreement as evidenced below;

NOW, THEREFORE, the Issuer and the Company covenant and agree as follows:

SECTION 1.    Section 5.2 of the Agreement is hereby amended to read as follows:

5.2 Existence. So long as the Bonds are outstanding, the Company will maintain its existence and its qualification to do business in Ohio, except that it may dissolve or otherwise dispose of all or substantially all of its assets and may consolidate with or merge into another entity or permit one or more entities to consolidate with or merge into it, if the surviving, resulting or transferee entity, if other than the Company, is solvent, has a net worth at least equal to the net worth of the Company immediately prior to the transaction, and assumes in writing all of the obligations of the Company hereunder and under the Note, and is an entity organized under one of the states of the United States of America and is duly qualified to do business in Ohio.

SECTION 2.    Upon effectuating the conversion from a corporation to a limited liability company, the entity as so organized and as renamed, ipso facto, shall be the Company under the Agreement and the Note, without the execution of an amended promissory note or the filing of any instrument or any further act, deed or conveyance on the part of any of the parties hereto.

SECTION 3.      This First Amendment may be executed in any number of counterparts, each of which shall be regarded as an original and all of which shall constitute but one and the same instrument.

EXHIBIT 10.2

IN WITNESS WHEREOF, the Issuer and the Company have caused this First Amendment to be duly executed and delivered in their respective names, all as of the date hereinbefore written.

	OHIO WATER DEVELOPMENT
	AUTHORITY
By:	/s/ Steve Grossman
	Executive Director
	FIRSTENERGY NUCLEAR
	GENERATION CORP.
By:	/s/ James F. Pearson
	Vice President and Treasurer

Acknowledged and consented to as of the date set forth above.

THE BANK OF NEW YORK MELLON

TRUST COMPANY, N.A., as Trustee

By:	/s/ Biagio Impala
	Vice President

EX-10.3

EXHIBIT 10.3

FIRST AMENDMENT TO LOAN AGREEMENT

THIS FIRST AMENDMENT TO LOAN AGREEMENT (the “First Amendment”), dated as of February 14, 2012 by and between the OHIO AIR QUALITY DEVELOPMENT AUTHORITY (the “Issuer”) and FIRSTENERGY GENERATION CORP. (the “Company”), to the Loan Agreement, dated as of December 1, 2006, entered into by the Issuer and the Company in connection with the issuance by the Issuer of $234,520,000 State of Ohio Pollution Control Revenue Refunding Bonds Series 2006-A (FirstEnergy Generation Corp. Project) (the “Agreement”), with capitalized terms used herein and not otherwise defined herein having the meanings ascribed to such terms in the Agreement;

W I T N E S S E T H :

WHEREAS, the Issuer has issued $234,520,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-A (FirstEnergy Generation Corp. Project) (the “Bonds”) pursuant to Chapter 3706 of the Ohio Revised Code and a Trust Indenture dated as of December 1, 2006 between the Issuer and the trustee thereunder (the “Trustee”), currently The Bank of New York Mellon Trust Company, N.A. (the “Original Indenture”), for the purpose of assisting the Company in the refinancing of a portion of the cost of the acquiring, constructing and installing certain facilities comprising “air quality facilities” as defined in Section 3706.01 of the Ohio Revised Code; and

WHEREAS, the Company has determined that it is in its best interests to pursue converting from an Ohio corporation to an Ohio limited liability company; and

WHEREAS, the Air Quality Facilities Loan Agreement dated as of December 1, 2006 between the Issuer and the Company (the “Loan Agreement”) provides that the Issuer and the Company may enter into amendments and supplements to the Loan Agreement for certain purposes and with the consent of the holders of at least a majority in aggregate principal amount of the Bonds then Outstanding; and

WHEREAS, consistent with the foregoing, and pursuant to the requirements of Section 15.03 of the Indenture, the Issuer and the Company have determined to amend the Agreement by removing references to maintaining its “corporate” existence; and

WHEREAS, having determined that at least a majority in aggregate principal amount of the Bonds Outstanding have consented to the amendments to the Loan Agreement, the Trustee has consented to this First Amendment to the Agreement as evidenced below;

NOW, THEREFORE, the Issuer and the Company covenant and agree as follows:

SECTION 1.    Section 5.2 of the Agreement is hereby amended to read as follows:

5.2 Existence. So long as the Bonds are outstanding, the Company will maintain its existence and its qualification to do business in Ohio, except that it may dissolve or otherwise dispose of all or substantially all of its assets and may consolidate with or merge into another entity or permit one or more entities to consolidate with or merge into it, if the surviving, resulting or transferee entity, if other than the Company, is solvent, has a net worth at least equal to the net worth of the Company immediately prior to the transaction, and assumes in writing all of the obligations of the Company hereunder and under the Note, and is an entity organized under one of the states of the United States of America and is duly qualified to do business in Ohio.

SECTION 2.    Upon effectuating the conversion from a corporation to a limited liability company, the entity as so organized and as renamed, ipso facto, shall be the Company under the Agreement and the Note, without the execution of an amended promissory note or the filing of any instrument or any further act, deed or conveyance on the part of any of the parties hereto.

SECTION 3.      This First Amendment may be executed in any number of counterparts, each of which shall be regarded as an original and all of which shall constitute but one and the same instrument.

EXHIBIT 10.3

IN WITNESS WHEREOF, the Issuer and the Company have caused this First Amendment to be duly executed and delivered in their respective names, all as of the date hereinbefore written.

	OHIO AIR QUALITY
	DEVELOPMENT AUTHORITY
By:	/s/ Todd Nein
	Interim Executive Director
	FIRSTENERGY GENERATION CORP.
By:	/s/ James F. Pearson
	Vice President and Treasurer

Acknowledged and consented to as of the date set forth above.

THE BANK OF NEW YORK MELLON

TRUST COMPANY, N.A., as Trustee

By:	/s/ Biagio Impala
	Vice President

EX-12

EXHIBIT 12

FIRSTENERGY CORP.

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Three Months Ended March 31
	2012		2011
	(Dollars in millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	306	$	47
Interest and other charges, before reduction for amounts capitalized and deferred	246		231
Provision for income taxes	222		111
Interest element of rentals charged to income (1)	36		36
Earnings as defined	$	810	$	425
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	246	$	231
Interest element of rentals charged to income (1)	36		36
Fixed charges as defined	$	282	$	267
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES	2.87		1.59

⁽¹⁾  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: May 1, 2012

/s/ Anthony J. Alexander

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: May 1, 2012

/s/ Donald R. Schneider

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: May 1, 2012

/s/ Charles E. Jones

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: May 1, 2012

/s/ Donald M. Lynch

Donald M. Lynch

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: May 1, 2012

/s/ Mark T. Clark

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: May 1, 2012

/s/ Mark T. Clark

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: May 1, 2012

/s/ Mark T. Clark

Mark T. Clark

Chief Financial Officer

EXHIBIT 31.2

Certification

I, Marlene A. Barwood, 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: May 1, 2012

/s/ Marlene A. Barwood

Marlene A. Barwood

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 March 31, 2012 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.

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

/s/ Mark T. Clark

Mark T. Clark

Chief Financial Officer

Date: May 1, 2012

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 March 31, 2012 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.

/s/ Donald R. Schneider

Donald R. Schneider

President

(Chief Executive Officer)

/s/ Mark T. Clark

Mark T. Clark

Chief Financial Officer

Date: May 1, 2012

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 March 31, 2012 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.

/s/ Charles E. Jones

Charles E. Jones

President

(Chief Executive Officer)

/s/ Mark T. Clark

Mark T. Clark

Chief Financial Officer

Date: May 1, 2012

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 March 31, 2012 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.

/s/ Donald M. Lynch

Donald M. Lynch

President

(Chief Executive Officer)

/s/ Marlene A. Barwood

Marlene A. Barwood

Controller

(Chief Financial Officer)

Date: May 1, 2012

XML

Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011
Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	$ 1,967	[1]	$ 1,980	[2]
Unrealized Gains	42	[1]	25	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	2,009	[1]	2,005	[2]
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	246	[1]	222	[2]
Unrealized Gains	42	[1]	36	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	288	[1]	258	[2]
FES | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	1,001	[1]	1,012	[2]
Unrealized Gains	21	[1]	13	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	1,022	[1]	1,025	[2]
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	127	[1]	104	[2]
Unrealized Gains	23	[1]	20	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	150	[1]	124	[2]
OE | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	133	[1]	134	[2]
Unrealized Gains	0	[1]	0	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	133	[1]	134	[2]
JCP&L | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	359	[1]	356	[2]
Unrealized Gains	12	[1]	7	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	371	[1]	363	[2]
JCP&L | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	27	[1]	27	[2]
Unrealized Gains	4	[1]	3	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	$ 31	[1]	$ 30	[2]

[1] Excludes short-term cash investments: FE Consolidated - $160 million; FES - $68 million; OE - $4 million; JCP&L - $19 million

[2] Excludes short-term cash investments: FE Consolidated - $164 million; FES - $74 million; OE - $2 million; JCP&L - $19 million

XML

Supplemental Guarantor Information (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$ (413)	$ 491
New Financing-
Long-term debt	0	217
Short-term borrowings, net	1,075	0
Redemptions and Repayments-
Long-term debt	(16)	(359)
Short-term borrowings, net	0	(214)
Other	(10)	(4)
Net cash provided from (used for) financing activities	819	(550)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(589)	(449)
Sales of investment securities held in trusts	251	969
Purchases of investment securities held in trusts	(266)	(993)
Other	(8)	(23)
Net cash provided from (used for) investing activities	(534)	141
Net change in cash and cash equivalents	(128)	82
Cash and cash equivalents at beginning of period	202	1,019
Cash and cash equivalents at end of period	74	1,101
FES Corp
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	(419)	(215)
New Financing-
Long-term debt		0
Short-term borrowings, net	347	322
Redemptions and Repayments-
Long-term debt		(131)
Short-term borrowings, net	0
Other		(1)
Net cash provided from (used for) financing activities	347	190
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2)	(3)
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	74	28
Customer acquisition costs		0
Other	0	0
Net cash provided from (used for) investing activities	72	25
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	66	267
New Financing-
Long-term debt		90
Short-term borrowings, net	0	28
Redemptions and Repayments-
Long-term debt		(141)
Short-term borrowings, net	(20)
Other	(2)	0
Net cash provided from (used for) financing activities	(22)	(23)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(18)	(40)
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	(23)	(200)
Customer acquisition costs		0
Other	(3)	(6)
Net cash provided from (used for) investing activities	(44)	(246)
Net change in cash and cash equivalents	0	(2)
Cash and cash equivalents at beginning of period	7	9
Cash and cash equivalents at end of period	7	7
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	175	42
New Financing-
Long-term debt		60
Short-term borrowings, net	0	0
Redemptions and Repayments-
Long-term debt		(60)
Short-term borrowings, net	(32)
Other	(1)	0
Net cash provided from (used for) financing activities	(33)	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(161)	(116)
Sales of investment securities held in trusts	83	216
Purchases of investment securities held in trusts	(90)	(231)
Loans to affiliated companies, net	25	90
Customer acquisition costs		0
Other	1	(1)
Net cash provided from (used for) investing activities	(142)	(42)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	0	0
New Financing-
Long-term debt		0
Short-term borrowings, net	(347)	0
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	52
Other		0
Net cash provided from (used for) financing activities	(295)	0
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	295	0
Customer acquisition costs		0
Other	0	0
Net cash provided from (used for) investing activities	295	0
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	(178)	94
New Financing-
Long-term debt	0	150
Short-term borrowings, net	0	350
Redemptions and Repayments-
Long-term debt	0	(332)
Short-term borrowings, net	0
Other	(3)	(1)
Net cash provided from (used for) financing activities	(3)	167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(181)	(159)
Sales of investment securities held in trusts	83	216
Purchases of investment securities held in trusts	(90)	(231)
Loans to affiliated companies, net	371	(82)
Customer acquisition costs		0
Other	(2)	(7)
Net cash provided from (used for) investing activities	181	(263)
Net change in cash and cash equivalents	0	(2)
Cash and cash equivalents at beginning of period	7	9
Cash and cash equivalents at end of period	$ 7	$ 7

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Derivative Instruments (Details Textuals) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011	Dec. 31, 2011
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 14		$ 19
Reclassifications from AOCL into other operating expense	5	(5)
Losses to be amortized to interest expenses during next twelve months	7
Unamortized gains or losses associated with prior interest rate hedges	77
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	96
Net asset position under commodity derivative contracts	66
Expected adverse change in quoted market prices of derivative instruments	10.00%
Decrease net income due to adverse change in commodity prices	2
Period In Which LSEs May Request Direct Allocation Of FTRs	2 years
FES
Derivative [Line Items]
Collateral posted	44
Additional collateral related to commodity derivatives	16
AE Supply
Derivative [Line Items]
Collateral posted	1
Additional collateral related to commodity derivatives	3
Cash Flow Hedges
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months	9
Number of Interest Rate Swap Agreements	0
Reclassifications from accumulated other comprehensive loss	2	3
Fair Value Hedging
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months	23
Number of Interest Rate Swap Agreements	0
Reclassifications from long-term debt	6	5
Subject to Regulatory Accounting, Excluded from Earnings | Non Utility Generation contract
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(7)	(17)
Subject to Regulatory Accounting, Excluded from Earnings | FTRs
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 3	$ (10)

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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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Derivative Instruments (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
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
Hedging Relationship; Gain (Loss) Recognized in AOCL (Effective Portion)	$ (5)	$ (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
Hedging Relationship Effective Gain (Loss) Reclassified to:		16
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	0	29
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(117)	(37)
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		(12)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	118	12
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		0
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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	58	(18)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(24)	(15)
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
Hedging Relationship; Gain (Loss) Recognized in AOCL (Effective Portion)	(5)	(9)
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		16
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	0	29
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(117)	(37)
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		(12)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	112	10
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	55	(20)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	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
Hedging Relationship; Gain (Loss) Recognized in AOCL (Effective Portion)	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
Hedging Relationship Effective Gain (Loss) Reclassified to:		0
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	0	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	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
Hedging Relationship Effective Gain (Loss) Reclassified to:		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	6	3
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	5	1
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(24)	(15)
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
Hedging Relationship; Gain (Loss) Recognized in AOCL (Effective Portion)	0	0
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		0
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	0	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	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
Hedging Relationship Effective Gain (Loss) Reclassified to:		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	(1)
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
Hedging Relationship Effective Gain (Loss) Reclassified to:		0
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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:	(2)	1
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	$ 0	$ 0

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 Allegheny	Mar. 31, 2011 Allegheny
Income Tax Contingency [Line Items]
Decrease in unrecognized tax benefits			$ 21
Unrecognized tax benefits expected to resolved within the next twelve month	45
Unrecognized benefits (if recognized) affecting effective tax rate	10
Increase in accrued interest				6
Accrued Interest	12	11
Change in effective tax rate as a result of non-deductible portion of merger transaction and integration costs	$ 30

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Segment Information (Details Textuals)	3 Months Ended
	Mar. 31, 2012 Companies Segments
Segment Reporting Information [Line Items]
Reportable Operating Segments	3
Number of existing utility operating companies	10
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	65,000
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	17,000
Unregulated Plants Expected to be Closed by 9/1/2012 | Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatt capacity of plants expected to be closed	2,700

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Commitments, Guarantees and Contingencies (Tables)

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations

As of March 31, 2012, FirstEnergy’s exposure to additional credit contingent contractual obligations was $671 million, as shown below:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade (1)	$	439	$	8	$	59	$	506
Material adverse event (2)	91		60		14		165
Total	$	530	$	68	$	73	$	671

⁽¹⁾  Includes $222 million and $40 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.

⁽²⁾  Includes $42 million that is also considered an acceleration of payment or funding obligation for FES.

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Commitments, Guarantees and Contingencies Commitments, Guarantees and Contingencies (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 671
Credit Rating Downgrade to Below Investment Grade
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	506
Material Adverse Event
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	165
FES
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	530
FES | Credit Rating Downgrade to Below Investment Grade
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	439	[1]
Potential Acceleration Payments or Funding Obligations Due to Credit Rating Downgrade	222
FES | Material Adverse Event
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	91	[2]
Potential Acceleration Payments or Funding Obligations Due to a Material Adverse Event	42
AE Supply
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	68
AE Supply | Credit Rating Downgrade to Below Investment Grade
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	8
AE Supply | Material Adverse Event
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	60
Utilities
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	73
Utilities | Credit Rating Downgrade to Below Investment Grade
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	59	[1]
Potential Acceleration Payments or Funding Obligations Due to Credit Rating Downgrade	40
Utilities | Material Adverse Event
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 14

[1] Includes $222 million and $40 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.

[2] Includes $42 million that is also considered an acceleration of payment or funding obligation for FES.

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Fair Value Measurements (Details 6) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 15,527	$ 15,716
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	17,130	17,165
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	19,321	19,320
FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	2,797	2,799
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	3,674	3,675
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	3,944	3,931
OE
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	1,156	1,155
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	1,157
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	1,469	1,434
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	1,729	1,736
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	1,770	1,777
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	$ 2,071	$ 2,080

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Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2012		Dec. 31, 2011
Non Utility Generation contract
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	$ 57	[1]	$ 122	[1]
Beginning Balance, Derivative Liability	(349)	[1]	(466)	[1]
Beginning Balance, Derivative, Total	(292)	[1]	(344)	[1]
Realized gain (loss), Derivative Asset	0	[1]	0	[1]
Realized gain (loss), Derivative Liability	0	[1]	0	[1]
Realized gain (loss), Derivative Total	0	[1]	0	[1]
Unrealized gain (loss), Derivative Asset	(14)	[1]	(58)	[1]
Unrealized gain (loss), Derivative Liability	(65)	[1]	(144)	[1]
Unrealized gain (loss), Derivative total	(79)	[1]	(202)	[1]
Purchases, Derivative Asset	0	[1]	0	[1]
Purchases, Derivative Liability	0	[1]	0	[1]
Purchases, Derivative Asset and Liability, total	0	[1]	0	[1]
Issuances, Derivative Asset	0	[1]	0	[1]
Issuances, Derivative Liability	0	[1]	0	[1]
Issuances, Derivative Asset and Liability, total	0	[1]	0	[1]
Sales, Derivative Asset	0	[1]	0	[1]
Sales, Derivative Liability	0	[1]	0	[1]
Sales, Derivative Asset and Liability, total	0	[1]	0	[1]
Settlements, Derivative Asset	(1)	[1]	(7)	[1]
Settlements, Derivative Liability	72	[1]	261	[1]
Settlements, Derivative Asset and Liability, total	71	[1]	254	[1]
Transfers into Level 3, Derivative Asset	0	[1]	0	[1]
Transfers into Level 3, Derivative Liability	0	[1]	0	[1]
Transfers into Level 3, Derivative Asset and Liability, total	0	[1]	0	[1]
Ending Balance, Derivative Asset	42	[1]	57	[1]
Ending Balance, Derivative Liability	(342)	[1]	(349)	[1]
Ending Balance, Derivative, Total	(300)	[1]	(292)	[1]
Non Utility Generation contract | JCP&L
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	4	[2]	6	[2]
Beginning Balance, Derivative Liability	(147)	[2]	(233)	[2]
Beginning Balance, Derivative, Total	(143)	[2]	(227)	[2]
Realized gain (loss), Derivative Asset	0	[2]	0	[2]
Realized gain (loss), Derivative Liability	0	[2]	0	[2]
Realized gain (loss), Derivative Total	0	[2]	0	[2]
Unrealized gain (loss), Derivative Asset	0	[2]	(2)	[2]
Unrealized gain (loss), Derivative Liability	(6)	[2]	(11)	[2]
Unrealized gain (loss), Derivative total	(6)	[2]	(13)	[2]
Purchases, Derivative Asset	0	[2]	0	[2]
Purchases, Derivative Liability	0	[2]	0	[2]
Purchases, Derivative Asset and Liability, total	0	[2]	0	[2]
Issuances, Derivative Asset	0	[2]	0	[2]
Issuances, Derivative Liability	0	[2]	0	[2]
Issuances, Derivative Asset and Liability, total	0	[2]	0	[2]
Sales, Derivative Asset	0	[2]	0	[2]
Sales, Derivative Liability	0	[2]	0	[2]
Sales, Derivative Asset and Liability, total	0	[2]	0	[2]
Settlements, Derivative Asset	0	[2]	0	[2]
Settlements, Derivative Liability	17	[2]	97	[2]
Settlements, Derivative Asset and Liability, total	17	[2]	97	[2]
Transfers into Level 3, Derivative Asset	0	[2]	0	[2]
Transfers into Level 3, Derivative Liability	0	[2]	0	[2]
Transfers into Level 3, Derivative Asset and Liability, total	0	[2]	0	[2]
Ending Balance, Derivative Asset	4	[2]	4	[2]
Ending Balance, Derivative Liability	(136)	[2]	(147)	[2]
Ending Balance, Derivative, Total	(132)	[2]	(143)	[2]
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	1	[1]	0	[1]
Beginning Balance, Derivative Liability	(23)	[1]	0	[1]
Beginning Balance, Derivative, Total	(22)	[1]	0	[1]
Realized gain (loss), Derivative Asset	0	[1]	0	[1]
Realized gain (loss), Derivative Liability	0	[1]	0	[1]
Realized gain (loss), Derivative Total	0	[1]	0	[1]
Unrealized gain (loss), Derivative Asset	0	[1]	2	[1]
Unrealized gain (loss), Derivative Liability	(3)	[1]	(27)	[1]
Unrealized gain (loss), Derivative total	(3)	[1]	(25)	[1]
Purchases, Derivative Asset	0	[1]	13	[1]
Purchases, Derivative Liability	0	[1]	(4)	[1]
Purchases, Derivative Asset and Liability, total	0	[1]	9	[1]
Issuances, Derivative Asset	0	[1]	0	[1]
Issuances, Derivative Liability	0	[1]	0	[1]
Issuances, Derivative Asset and Liability, total	0	[1]	0	[1]
Sales, Derivative Asset	0	[1]	0	[1]
Sales, Derivative Liability	0	[1]	0	[1]
Sales, Derivative Asset and Liability, total	0	[1]	0	[1]
Settlements, Derivative Asset	0	[1]	(14)	[1]
Settlements, Derivative Liability	11	[1]	20	[1]
Settlements, Derivative Asset and Liability, total	11	[1]	6	[1]
Transfers into Level 3, Derivative Asset	0	[1]
Transfers into Level 3, Derivative Liability	0	[1]	(12)	[1]
Transfers into Level 3, Derivative Asset and Liability, total	0	[1]	(12)	[1]
Ending Balance, Derivative Asset	1	[1]	1	[1]
Ending Balance, Derivative Liability	(15)	[1]	(23)	[1]
Ending Balance, Derivative, Total	(14)	[1]	(22)	[1]
FTRs | FES
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	1		0
Beginning Balance, Derivative Liability	(7)		0
Beginning Balance, Derivative, Total	(6)		0
Realized gain (loss), Derivative Asset	0		0
Realized gain (loss), Derivative Liability	0		0
Realized gain (loss), Derivative Total	0		0
Unrealized gain (loss), Derivative Asset	0		4
Unrealized gain (loss), Derivative Liability	(1)		(8)
Unrealized gain (loss), Derivative total	(1)		(4)
Purchases, Derivative Asset	0		2
Purchases, Derivative Liability	0		(1)
Purchases, Derivative Asset and Liability, total	0		1
Issuances, Derivative Asset	0		0
Issuances, Derivative Liability	0		0
Issuances, Derivative Asset and Liability, total	0		0
Sales, Derivative Asset	0		0
Sales, Derivative Liability	0		0
Sales, Derivative Asset and Liability, total	0		0
Settlements, Derivative Asset	0		(5)
Settlements, Derivative Liability	4		2
Settlements, Derivative Asset and Liability, total	4		(3)
Transfers into Level 3, Derivative Asset	0		0
Transfers into Level 3, Derivative Liability	0		0
Transfers into Level 3, Derivative Asset and Liability, total	0		0
Ending Balance, Derivative Asset	1		1
Ending Balance, Derivative Liability	(4)		(7)
Ending Balance, Derivative, Total	$ (3)		$ (6)

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

[2] Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

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Supplemental Guarantor Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Consolidating Statements of Income
Revenues	$ 4,078	[1]	$ 3,576	[1]
OPERATING EXPENSES:
Fuel	541		453
Purchased power	1,347		1,186
Other operating expenses	812		993
Provision for depreciation	285		225
General taxes	272		237
Total operating expenses	3,332		3,226
OPERATING INCOME (LOSS)	746		350
OTHER INCOME (EXPENSE):
Investment income	11		21
Interest expense	(246)		(231)
Capitalized interest	17		18
Total other income (expense)	(218)		(192)
INCOME (LOSS) BEFORE INCOME TAXES	528		158
INCOME TAXES (BENEFITS)	222		111
NET INCOME	306		47
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(53)		(44)
Amortized loss on derivative hedges	(2)		(6)
Change in unrealized gain on available-for-sale securities	10		9
Other comprehensive income (loss)	(45)		(41)
Income taxes (benefits) on other comprehensive income (loss)	(24)		(19)
Other comprehensive income (loss), net of tax	(21)		(22)
COMPREHENSIVE INCOME	285		25
FES Corp
Consolidating Statements of Income
Revenues	1,490		1,366
OPERATING EXPENSES:
Fuel	0		1
Other operating expenses	76		162
Provision for depreciation	1		1
General taxes	20		10
Impairment of long-lived assets			0
Total operating expenses	1,549		1,656
OPERATING INCOME (LOSS)	(59)		(290)
OTHER INCOME (EXPENSE):
Investment income	1		1
Miscellaneous income, including net income from equity investees	258		242
Capitalized interest	0		0
Total other income (expense)	232		218
INCOME (LOSS) BEFORE INCOME TAXES	173		(72)
INCOME TAXES (BENEFITS)	51		(117)
NET INCOME	122		45
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5)		(10)
Amortized loss on derivative hedges	(5)		(9)
Change in unrealized gain on available-for-sale securities	10		8
Other comprehensive income (loss)	0		(11)
Income taxes (benefits) on other comprehensive income (loss)	2		(6)
Other comprehensive income (loss), net of tax	(2)		(5)
COMPREHENSIVE INCOME	120		40
FES Corp | Affiliates
OPERATING EXPENSES:
Purchased power	965		1,185
OTHER INCOME (EXPENSE):
Interest expense	(4)		(1)
FES Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	487		297
OTHER INCOME (EXPENSE):
Interest expense	(23)		(24)
FGCO
Consolidating Statements of Income
Revenues	542		743
OPERATING EXPENSES:
Fuel	240		294
Other operating expenses	92		111
Provision for depreciation	30		32
General taxes	10		11
Impairment of long-lived assets			14
Total operating expenses	372		464
OPERATING INCOME (LOSS)	170		279
OTHER INCOME (EXPENSE):
Investment income	4		0
Miscellaneous income, including net income from equity investees	0		1
Capitalized interest	1		5
Total other income (expense)	(22)		(22)
INCOME (LOSS) BEFORE INCOME TAXES	148		257
INCOME TAXES (BENEFITS)	(1)		96
NET INCOME	149		161
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(4)		(4)
Amortized loss on derivative hedges	0		0
Change in unrealized gain on available-for-sale securities	0		0
Other comprehensive income (loss)	(4)		(4)
Income taxes (benefits) on other comprehensive income (loss)	(2)		(2)
Other comprehensive income (loss), net of tax	(2)		(2)
COMPREHENSIVE INCOME	147		159
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power	0		2
OTHER INCOME (EXPENSE):
Interest expense	(1)		0
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0		0
OTHER INCOME (EXPENSE):
Interest expense	(26)		(28)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues	394		469
OPERATING EXPENSES:
Fuel	55		48
Other operating expenses	116		180
Provision for depreciation	34		38
General taxes	7		8
Impairment of long-lived assets			0
Total operating expenses	274		343
OPERATING INCOME (LOSS)	120		126
OTHER INCOME (EXPENSE):
Investment income	5		5
Miscellaneous income, including net income from equity investees	0		0
Capitalized interest	8		5
Total other income (expense)	5		(7)
INCOME (LOSS) BEFORE INCOME TAXES	125		119
INCOME TAXES (BENEFITS)	23		45
NET INCOME	102		74
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	0		(6)
Amortized loss on derivative hedges	0		0
Change in unrealized gain on available-for-sale securities	10		8
Other comprehensive income (loss)	10		2
Income taxes (benefits) on other comprehensive income (loss)	4		1
Other comprehensive income (loss), net of tax	6		1
COMPREHENSIVE INCOME	108		75
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power	62		69
OTHER INCOME (EXPENSE):
Interest expense	(1)		0
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0		0
OTHER INCOME (EXPENSE):
Interest expense	(7)		(17)
Eliminations
Consolidating Statements of Income
Revenues	(910)		(1,187)
OPERATING EXPENSES:
Fuel	0		0
Other operating expenses	11		12
Provision for depreciation	(2)		(2)
General taxes	0		0
Impairment of long-lived assets			0
Total operating expenses	(901)		(1,177)
OPERATING INCOME (LOSS)	(9)		(10)
OTHER INCOME (EXPENSE):
Investment income	(4)		0
Miscellaneous income, including net income from equity investees	(254)		(239)
Capitalized interest	0		0
Total other income (expense)	(239)		(223)
INCOME (LOSS) BEFORE INCOME TAXES	(248)		(233)
INCOME TAXES (BENEFITS)	3		2
NET INCOME	(251)		(235)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	4		10
Amortized loss on derivative hedges	0		0
Change in unrealized gain on available-for-sale securities	(10)		(8)
Other comprehensive income (loss)	(6)		2
Income taxes (benefits) on other comprehensive income (loss)	(2)		1
Other comprehensive income (loss), net of tax	(4)		1
COMPREHENSIVE INCOME	(255)		(234)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power	(910)		(1,187)
OTHER INCOME (EXPENSE):
Interest expense	4		0
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0		0
OTHER INCOME (EXPENSE):
Interest expense	15		16
FES
Consolidating Statements of Income
Revenues	1,516		1,391
OPERATING EXPENSES:
Fuel	295		343
Other operating expenses	295		465
Provision for depreciation	63		69
General taxes	37		29
Impairment of long-lived assets	0		14
Total operating expenses	1,294		1,286
OPERATING INCOME (LOSS)	222		105
OTHER INCOME (EXPENSE):
Investment income	6		6
Miscellaneous income, including net income from equity investees	4		4
Capitalized interest	9		10
Total other income (expense)	(24)		(34)
INCOME (LOSS) BEFORE INCOME TAXES	198		71
INCOME TAXES (BENEFITS)	76		26
NET INCOME	122		45
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5)		(10)
Amortized loss on derivative hedges	(5)		(9)
Change in unrealized gain on available-for-sale securities	10		8
Other comprehensive income (loss)	0		(11)
Income taxes (benefits) on other comprehensive income (loss)	2		(6)
Other comprehensive income (loss), net of tax	(2)		(5)
COMPREHENSIVE INCOME	120		40
FES | Affiliates
OPERATING EXPENSES:
Purchased power	117		69
OTHER INCOME (EXPENSE):
Interest expense	(2)		(1)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	487		297
OTHER INCOME (EXPENSE):
Interest expense	$ (41)		$ (53)

[1] Includes excise tax collections of $121 million and $119 million in the three months ended March 31, 2012 and 2011, respectively.

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Derivative Instruments (Details 3) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (301)	[1]	$ (335)	[1]
Additions/Change in value of existing contracts	(80)	[1]	(89)	[1]
Settled contracts	76	[1]	62	[1]
Outstanding net asset (liability), Ending Balance	(305)	[1]	(362)	[1]
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(293)	[1]	(345)	[1]
Additions/Change in value of existing contracts	(79)	[1]	(89)	[1]
Settled contracts	72	[1]	72	[1]
Outstanding net asset (liability), Ending Balance	(300)	[1]	(362)	[1]
Other
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(8)	[1]	10	[1]
Additions/Change in value of existing contracts	(1)	[1]	0	[1]
Settled contracts	4	[1]	(10)	[1]
Outstanding net asset (liability), Ending Balance	$ (5)	[1]	$ 0	[1]

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

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Earnings Per Share

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

EARNINGS PER SHARE

EARNINGS PER SHARE

Basic earnings per share of common stock are computed using the weighted average number of 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 could result if dilutive securities and other agreements to issue common stock were exercised. The following table reconciles basic and diluted earnings per share of common stock:

	Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2012		2011
	(In millions, except per share amounts)
Weighted average number of basic shares outstanding	418		342
Assumed exercise of dilutive stock options and awards(1)	2		1
Weighted average number of diluted shares outstanding	420		343
Earnings Available to FirstEnergy Corp.	$	306	$	52
Basic earnings per share of common stock	$	0.73	$	0.15
Diluted earnings per share of common stock	$	0.73	$	0.15

⁽¹⁾  The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months endedMarch 31, 2012 and 2011.

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Fair Value Measurements (Details Textuals) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ 2	$ (52)
Cash balance excluded from available for sale securities	160	164
Investments not required to be disclosed	689	693
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	2	(58)
Cash balance excluded from available for sale securities	68	74
OE
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	1	1
Cash balance excluded from available for sale securities	4	2
JCP&L
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income		2
Cash balance excluded from available for sale securities	$ 19	$ 19

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Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
Reconciliation of basic and diluted earnings per share of common stock
Weighted average number of basic shares outstanding	418		342
Assumed exercise of dilutive stock options and awards	2	[1]	1	[1]
Weighted average number of diluted shares outstanding	420		343
Earnings available to FirstEnergy Corp.	$ 306		$ 52
Basic Earnings Per Share of Common Stock	$ 0.73		$ 0.15
Diluted Earnings Per Share of Common Stock	$ 0.73		$ 0.15

[1] The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months ended March 31, 2012 and 2011.

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Organization and Basis of Presentation Organization and Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Increase in income tax expense resulting from purchase accounting adjustment	$ 20
Decrease in goodwill resulting from purchase accounting adjustment	$ (20)

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011		Dec. 31, 2011
Segment Financial Information
External revenues	$ 4,076		$ 3,544
Internal revenues	2		32
Total revenues	4,078	[1]	3,576	[1]
Depreciation and amortization	360		357
Investment income	11		21
Net interest charges	229		213
Income taxes	222		111
Net income	306		47
Total assets	47,691		48,565		47,326
Total goodwill	6,444		6,507		6,441
Property additions	589		449
Regulated Distribution
Segment Financial Information
External revenues	2,383		2,268
Internal revenues	0		0
Total revenues	2,383		2,268
Depreciation and amortization	234		250
Investment income	24		25
Net interest charges	142		131
Income taxes	108		64
Net income	183		109
Total assets	27,551		27,766
Total goodwill	5,551		5,551
Property additions	301		177
Competitive Energy Services
Segment Financial Information
External revenues	1,607		1,254
Internal revenues	268		343
Total revenues	1,875		1,597
Depreciation and amortization	100		88
Investment income	6		6
Net interest charges	54		68
Income taxes	83		9
Net income	141		15
Total assets	17,187		17,399
Total goodwill	893		956
Property additions	243		214
Regulated Independent Transmission
Segment Financial Information
External revenues	109		67
Internal revenues	0		0
Total revenues	109		67
Depreciation and amortization	18		13
Investment income	0		0
Net interest charges	12		9
Income taxes	20		7
Net income	34		12
Total assets	2,452		2,486
Total goodwill	0		0
Property additions	28		27
Other/Corporate
Segment Financial Information
External revenues	(24)		(23)
Internal revenues	0		0
Total revenues	(24)		(23)
Depreciation and amortization	8		6
Investment income	0		0
Net interest charges	21		19
Income taxes	(16)		0
Net income	(28)		(55)
Total assets	501		914
Total goodwill	0		0
Property additions	17		31
Reconciling Adjustments
Segment Financial Information
External revenues	1		(22)
Internal revenues	(266)		(311)
Total revenues	(265)		(333)
Depreciation and amortization	0		0
Investment income	(19)		(10)
Net interest charges	0		(14)
Income taxes	27		31
Net income	(24)		(34)
Total assets	0		0
Total goodwill	0		0
Property additions	$ 0		$ 0

[1] Includes excise tax collections of $121 million and $119 million in the three months ended March 31, 2012 and 2011, respectively.

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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Fair value of commodity derivatives
Economic Hedges Derivative assets	$ 459	$ 321
Economic Hedges Derivative liabilities	(707)	(619)
Power Contracts | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	300	185
Power Contracts | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(282)	(196)
Power Contracts | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	115	79
Power Contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(66)	(51)
FTRs | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	1	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(15)	(22)
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	0
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	0	(1)
NUGs
Fair value of commodity derivatives
Economic Hedges Derivative assets	42	56
Economic Hedges Derivative liabilities	(342)	(349)
Other | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	1	0
Other | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(2)	0
Other | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	0
Other | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	$ 0	$ 0

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Pensions and Other Postemployment Benefits (Details Textuals) (Qualified Pension Plan, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012
Qualified Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer Contribution for qualified Plans	$ 600

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Pensions and Other Postemployment Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pensions
Components of Net Periodic Benefit Costs (Credits)
Service cost	$ 40	$ 29
Interest cost	97	84
Expected return on plan assets	(121)	(102)
Amortization of prior service cost	3	4
Other adjustments (settlements, curtailments, etc)	0	7
Net periodic cost (credit)	19	22
OPEB
Components of Net Periodic Benefit Costs (Credits)
Service cost	3	3
Interest cost	12	11
Expected return on plan assets	(9)	(10)
Amortization of prior service cost	(51)	(48)
Other adjustments (settlements, curtailments, etc)	0	0
Net periodic cost (credit)	$ (45)	$ (44)

XML

Organization and Basis of Presentation

3 Months Ended

Mar. 31, 2012

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION AND BASIS OF PRESENTATION

Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms.

FE is a diversified energy holding 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), JCP&L, ME, PN, FENOC, AE and its principal subsidiaries (AE Supply, AGC, MP, PE, WP and AET), FES and its principal 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. Accordingly, consolidated results of operations for the three months ended March 31, 2011, include just one month of Allegheny results.

The consolidated financial statements of FE, FES, OE and JCP&L include the accounts of entities in which a controlling financial interest is held, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% or the result of an analysis that identifies FE or one of its subsidiaries as the primary beneficiary of a VIE. Investments in which a controlling financial interest is not held are accounted for under the equity or cost method of accounting.

These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These 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, 2011.

The accompanying interim financial statements are unaudited, but reflect all adjustments, consisting of normal recurring adjustments, that, in the opinion of management, are necessary for a fair presentation of the 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.

As described in its Annual Report on Form 10-K for the year ended December 31, 2011, FE's consolidated financial statements for the three months ended March 31, 2011, were revised to reflect a purchase accounting measurement adjustment identified during the fourth quarter of 2011 that decreased goodwill and increased income tax expense by approximately $20 million.

As described in its Annual Report on Form 10-K for the year ended December 31, 2011, during the fourth quarter of 2011, FE elected to change its method of accounting relating to its defined benefit pension and OPEB plans to recognize the change in fair value of plan assets and net actuarial gains and losses immediately, and applied this change retrospectively. Generally, these gains and losses are measured annually as of December 31, and accordingly, will be recorded during the fourth quarter.

Certain prior year amounts have been reclassified to conform to the current year presentation.

New Accounting Pronouncements

New accounting pronouncements not yet effective are not expected to have a material effect on the financial statements of FE or its subsidiaries.

XML

Pensions and Other Postemployment Benefits (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Pensions
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	$ 13	$ 20
Pensions | FES
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	10	7
Pensions | OE
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(1)	(2)
Pensions | JCP&L
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(1)	(2)
OPEB
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(30)	(32)
OPEB | FES
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(8)	(7)
OPEB | OE
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(5)	(6)
OPEB | JCP&L
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	$ (2)	$ (3)

XML

Fair Value Measurements (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
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	$ 251	$ 969
Realized gains	19	100
Realized losses	(17)	(29)
Interest and dividend income	15	24
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	83	216
Realized gains	12	12
Realized losses	(11)	(15)
Interest and dividend income	7	15
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	37	8
Realized gains	0	0
Realized losses	0	0
Interest and dividend income	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	95	217
Realized gains	1	22
Realized losses	(1)	(4)
Interest and dividend income	$ 4	$ 4

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Supplemental Guarantor Information (Details 1) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 74	$ 202	$ 1,101	$ 1,019
Receivables-
Customers	1,449	1,525
Other	286	269
Materials and supplies, at average cost	927	811
Derivatives	346	235
Prepayments and other	182	122
Total current assets	3,477	3,355
PROPERTY, PLANT AND EQUIPMENT:
In service	40,587	40,122
Less - Accumulated provision for depreciation	12,086	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,501	28,283
Construction work in progress	2,065	2,054
Total net property, plant and equipment	30,566	30,337
INVESTMENTS:
Nuclear plant decommissioning trusts		2,112
Other	1,011	1,008
Total other property and investments	3,482	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444	6,441	6,507
Other	1,716	1,641
Total deferred charges and other assets	10,166	10,112
Total assets	47,691	47,326	48,565
CURRENT LIABILITIES:
Currently payable long-term debt	1,772	1,621
Short-term borrowings-
Affiliated companies	1,075	0
Accounts payable-
Accrued Taxes	442	558
Derivatives	299	218
Other	1,009	900
Total current liabilities	5,773	4,855
CAPITALIZATION:
Total equity	13,323	13,280
Long-term debt and other long-term obligations	15,527	15,716
Total capitalization	28,866	29,015
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	917	925
Accumulated deferred income taxes	5,904	5,670
Asset retirement obligations	1,522	1,497
Retirement benefits	2,240	2,823
Other	2,011	2,072
Total noncurrent liabilities	13,052	13,456
Total liabilities and capitalization	47,691	47,326
FES Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	395	424
Affiliated companies	472	476
Other	50	28
Notes receivable from affiliated companies	81	155
Materials and supplies, at average cost	62	60
Derivatives	322	219
Prepayments and other	7	11
Total current assets	1,389	1,373
PROPERTY, PLANT AND EQUIPMENT:
In service	84	84
Less - Accumulated provision for depreciation	29	28
Property, plant and equipment in service net of accumulated provision for depreciation	55	56
Construction work in progress	31	29
Total net property, plant and equipment	86	85
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	5,956	5,716
Other	0	0
Total other property and investments	5,956	5,716
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	10
Customer intangibles	120	123
Goodwill	24	24
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	117	79
Other	123	89
Total deferred charges and other assets	384	325
Total assets	7,815	7,499
CURRENT LIABILITIES:
Currently payable long-term debt	1	1
Accounts payable-
Affiliated companies	663	777
Other	69	99
Accrued Taxes	31	84
Derivatives	281	189
Other	38	62
Total current liabilities	2,496	2,277
CAPITALIZATION:
Total equity	3,695	3,593
Long-term debt and other long-term obligations	1,482	1,483
Total capitalization	5,177	5,076
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	18	12
Asset retirement obligations	0	0
Retirement benefits	31	56
Lease market valuation liability	0	0
Other	93	78
Total noncurrent liabilities	142	146
Total liabilities and capitalization	7,815	7,499
FGCO
CURRENT ASSETS:
Cash and cash equivalents	7	7	7	9
Receivables-
Customers	0	0
Affiliated companies	439	643
Other	19	20
Notes receivable from affiliated companies	1,369	1,346
Materials and supplies, at average cost	283	232
Derivatives	0	0
Prepayments and other	17	26
Total current assets	2,134	2,274
PROPERTY, PLANT AND EQUIPMENT:
In service	5,614	5,573
Less - Accumulated provision for depreciation	1,843	1,813
Property, plant and equipment in service net of accumulated provision for depreciation	3,771	3,760
Construction work in progress	171	195
Total net property, plant and equipment	3,942	3,955
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	7	7
Total other property and investments	7	7
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	274	307
Customer intangibles	0	0
Goodwill	0	0
Property taxes	20	20
Unamortized sale and leaseback costs	21	5
Derivatives	0	0
Other	111	99
Total deferred charges and other assets	426	431
Total assets	6,509	6,667
CURRENT LIABILITIES:
Currently payable long-term debt	411	411
Accounts payable-
Affiliated companies	175	228
Other	121	121
Accrued Taxes	33	42
Derivatives	0	0
Other	111	141
Total current liabilities	920	1,032
CAPITALIZATION:
Total equity	3,244	3,097
Long-term debt and other long-term obligations	1,903	1,905
Total capitalization	5,147	5,002
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	28	28
Retirement benefits	120	300
Lease market valuation liability	160	171
Other	134	134
Total noncurrent liabilities	442	633
Total liabilities and capitalization	6,509	6,667
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	241	262
Other	53	13
Notes receivable from affiliated companies	44	69
Materials and supplies, at average cost	206	200
Derivatives	0	0
Prepayments and other	1	1
Total current assets	545	545
PROPERTY, PLANT AND EQUIPMENT:
In service	5,689	5,711
Less - Accumulated provision for depreciation	2,524	2,449
Property, plant and equipment in service net of accumulated provision for depreciation	3,165	3,262
Construction work in progress	971	790
Total net property, plant and equipment	4,136	4,052
INVESTMENTS:
Nuclear plant decommissioning trusts	1,240	1,223
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,240	1,223
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	23	23
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	2	3
Total deferred charges and other assets	25	26
Total assets	5,946	5,846
CURRENT LIABILITIES:
Currently payable long-term debt	514	513
Accounts payable-
Affiliated companies	256	211
Other	0	0
Accrued Taxes	24	110
Derivatives	0	0
Other	24	16
Total current liabilities	818	882
CAPITALIZATION:
Total equity	2,697	2,587
Long-term debt and other long-term obligations	641	641
Total capitalization	3,338	3,228
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	532	510
Asset retirement obligations	891	876
Retirement benefits	0	0
Lease market valuation liability	0	0
Other	367	350
Total noncurrent liabilities	1,790	1,736
Total liabilities and capitalization	5,946	5,846
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(611)	(781)
Other	0	0
Notes receivable from affiliated companies	(1,482)	(1,187)
Materials and supplies, at average cost	0	0
Derivatives	0	0
Prepayments and other	(1)	0
Total current assets	(2,094)	(1,968)
PROPERTY, PLANT AND EQUIPMENT:
In service	(385)	(385)
Less - Accumulated provision for depreciation	(182)	(180)
Property, plant and equipment in service net of accumulated provision for depreciation	(203)	(205)
Construction work in progress	0	0
Total net property, plant and equipment	(203)	(205)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(5,956)	(5,716)
Other	0	0
Total other property and investments	(5,956)	(5,716)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(274)	(317)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	99	75
Derivatives	0	0
Other	(65)	(62)
Total deferred charges and other assets	(240)	(304)
Total assets	(8,493)	(8,193)
CURRENT LIABILITIES:
Currently payable long-term debt	(21)	(20)
Accounts payable-
Affiliated companies	(611)	(780)
Other	0	0
Accrued Taxes	(13)	(9)
Derivatives	0	0
Other	72	42
Total current liabilities	(2,055)	(1,953)
CAPITALIZATION:
Total equity	(5,941)	(5,700)
Long-term debt and other long-term obligations	(1,229)	(1,230)
Total capitalization	(7,170)	(6,930)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	917	925
Accumulated deferred income taxes	(185)	(236)
Asset retirement obligations	0	0
Retirement benefits	0	0
Lease market valuation liability	0	0
Other	0	1
Total noncurrent liabilities	732	690
Total liabilities and capitalization	(8,493)	(8,193)
FES
CURRENT ASSETS:
Cash and cash equivalents	7	7	7	9
Receivables-
Customers	395	424
Affiliated companies	541	600
Other	122	61
Notes receivable from affiliated companies	12	383
Materials and supplies, at average cost	551	492
Derivatives	322	219
Prepayments and other	24	38
Total current assets	1,974	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	11,002	10,983
Less - Accumulated provision for depreciation	4,214	4,110
Property, plant and equipment in service net of accumulated provision for depreciation	6,788	6,873
Construction work in progress	1,173	1,014
Total net property, plant and equipment	7,961	7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	1,240	1,223
Investment in affiliated companies	0	0
Other	7	7
Total other property and investments	1,247	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	120	123
Goodwill	24	24
Property taxes	43	43
Unamortized sale and leaseback costs	120	80
Derivatives	117	79
Other	171	129
Total deferred charges and other assets	595	478
Total assets	11,777	11,819
CURRENT LIABILITIES:
Currently payable long-term debt	905	905
Accounts payable-
Affiliated companies	483	436
Other	190	220
Accrued Taxes	75	227
Derivatives	281	189
Other	245	261
Total current liabilities	2,179	2,238
CAPITALIZATION:
Total equity	3,695	3,577
Long-term debt and other long-term obligations	2,797	2,799
Total capitalization	6,492	6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	917	925
Accumulated deferred income taxes	365	286
Asset retirement obligations	919	904
Retirement benefits	151	356
Lease market valuation liability	160	171
Other	594	563
Total noncurrent liabilities	3,106	3,205
Total liabilities and capitalization	11,777	11,819
Affiliates [Member] | FES Corp
Short-term borrowings-
Affiliated companies	1,413	1,065
Affiliates [Member] | FGCO
Short-term borrowings-
Affiliated companies	69	89
Affiliates [Member] | Nuclear Generation Corp
Short-term borrowings-
Affiliated companies	0	32
Affiliates [Member] | Eliminations
Short-term borrowings-
Affiliated companies	(1,482)	(1,186)
Affiliates [Member] | FES
Short-term borrowings-
Affiliated companies	$ 0	$ 0

XML

Consolidated Statements of Income (Unaudited) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2012		Mar. 31, 2011
REVENUES:
Electric utilities	$ 2,554		$ 2,332
Unregulated businesses	1,524		1,244
Excise and gross receipts tax collections	121		119
Total revenues	4,078	[1]	3,576	[1]
OPERATING EXPENSES:
Fuel	541		453
Purchased power	1,347		1,186
Other operating expenses	812		993
Provision for depreciation	285		225
Amortization of regulatory assets, net	75		132
General taxes	272		237
Total operating expenses	3,332		3,226
OPERATING INCOME (LOSS)	746		350
OTHER INCOME (EXPENSE):
Investment income	11		21
Interest expense	(246)		(231)
Capitalized interest	17		18
Total other income (expense)	(218)		(192)
INCOME BEFORE INCOME TAXES	528		158
INCOME TAXES (BENEFITS)	222		111
NET INCOME	306		47
Loss attributable to noncontrolling interest	0		(5)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	306		52
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$ 0.73		$ 0.15
Diluted	$ 0.73		$ 0.15
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	418		342
Diluted	420		343
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$ 0.55		$ 0.55
FES
REVENUES:
Other	63		86
Total revenues	1,516		1,391
OPERATING EXPENSES:
Fuel	295		343
Other operating expenses	295		465
Provision for depreciation	63		69
General taxes	37		29
Impairment of long-lived assets	0		14
Total operating expenses	1,294		1,286
OPERATING INCOME (LOSS)	222		105
OTHER INCOME (EXPENSE):
Investment income	6		6
Miscellaneous income	4		4
Capitalized interest	9		10
Total other income (expense)	(24)		(34)
INCOME BEFORE INCOME TAXES	198		71
INCOME TAXES (BENEFITS)	76		26
NET INCOME	122		45
FES | Affiliates
REVENUES:
Unregulated businesses	121		261
OPERATING EXPENSES:
Purchased power	117		69
OTHER INCOME (EXPENSE):
Interest expense	(2)		(1)
FES | Non-Affiliates
REVENUES:
Unregulated businesses	1,332		1,044
OPERATING EXPENSES:
Purchased power	487		297
OTHER INCOME (EXPENSE):
Interest expense	(41)		(53)
OE
REVENUES:
Electric utilities	359		364
Excise and gross receipts tax collections	27		28
Total revenues	386		392
OPERATING EXPENSES:
Other operating expenses	121		96
Provision for depreciation	24		23
Amortization of regulatory assets, net	0		1
General taxes	50		50
Total operating expenses	317		323
OPERATING INCOME (LOSS)	69		69
OTHER INCOME (EXPENSE):
Investment income	4		5
Interest expense	(22)		(22)
Capitalized interest	1		0
Total other income (expense)	(17)		(17)
INCOME BEFORE INCOME TAXES	52		52
INCOME TAXES (BENEFITS)	21		20
NET INCOME	31		32
OE | Affiliates
OPERATING EXPENSES:
Purchased power	52		93
OE | Non-Affiliates
OPERATING EXPENSES:
Purchased power	70		60
JCP&L
REVENUES:
Electric utilities	478		634
Excise and gross receipts tax collections	10		13
Total revenues	488		647
OPERATING EXPENSES:
Purchased power	264		370
Other operating expenses	81		80
Provision for depreciation	30		26
Amortization of regulatory assets, net	20		82
General taxes	15		18
Total operating expenses	410		576
OPERATING INCOME (LOSS)	78		71
OTHER INCOME (EXPENSE):
Miscellaneous income	1		2
Interest expense	(31)		(30)
Total other income (expense)	(30)		(28)
INCOME BEFORE INCOME TAXES	48		43
INCOME TAXES (BENEFITS)	22		20
NET INCOME	$ 26		$ 23

[1] Includes excise tax collections of $121 million and $119 million in the three months ended March 31, 2012 and 2011, respectively.

XML

Derivative Instruments (Details 1)	Mar. 31, 2012 MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases	33,000,000
Sales	47,000,000
Net	(14,000,000)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases	17,000,000
Sales	0
Net	17,000,000
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases	23,000,000
Sales	0
Net	23,000,000
Natural Gas Futures
Volume of First Energy's outstanding derivative transactions
Purchases	11,000,000
Sales	0
Net	11,000,000

XML

Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Common stockholders' equity-
Common stock, par value	$ 0.1	$ 0.1
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	418,216,437	418,216,437
Customer [Member]
Receivables-
Allowance for uncollectible accounts	$ 35	$ 37
Other [Member]
Receivables-
Allowance for uncollectible accounts	8	3
FES
Common stockholders' equity-
Common Stock, No Par Value
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7
FES | Customer [Member]
Receivables-
Allowance for uncollectible accounts	16	16
FES | Other [Member]
Receivables-
Allowance for uncollectible accounts	3	3
OE
Common stockholders' equity-
Common Stock, No Par Value
Common stock, shares authorized	175,000,000	175,000,000
Common stock, shares outstanding	60	60
OE | Customer [Member]
Receivables-
Allowance for uncollectible accounts	4	4
JCP&L
Common stockholders' equity-
Common stock, par value	$ 10	$ 10
Common stock, shares authorized	16,000,000	16,000,000
Common stock, shares outstanding	13,628,447	13,628,447
JCP&L | Customer [Member]
Receivables-
Allowance for uncollectible accounts	$ 3	$ 4

XML

Variable Interest Entities (Details Textuals) (USD $)	3 Months Ended														3 Months Ended
	Mar. 31, 2012 contracts	Mar. 31, 2012 entities	Mar. 31, 2011	Mar. 31, 2012 Power Purchase Agreements agreements	Mar. 31, 2012 JCP&L contracts	Mar. 31, 2011 JCP&L	Mar. 31, 2012 JCP&L Power Purchase Agreements	Mar. 31, 2011 JCP&L Power Purchase Agreements	Mar. 31, 2012 PE Power Purchase Agreements	Mar. 31, 2011 PE Power Purchase Agreements	Mar. 31, 2012 WP Power Purchase Agreements	Mar. 31, 2011 WP Power Purchase Agreements	Mar. 31, 2012 Signal Peak FEV	Oct. 18, 2011 Signal Peak FEV	Mar. 31, 2012 Variable Interest Entity, Not Primary Beneficiary	Mar. 31, 2012 PATH-WV	Mar. 31, 2012 PATH-WV Allegheny	Mar. 31, 2012 Oyster Creek Nuclear Generating Station
Variable Interest Entities (Textuals) [Abstract]
Bondable stranded costs																		$ 270,000,000
Environmental control bond	504,000,000	504,000,000
Distributions to owners															3,000,000
Joint venture, ownership percentage by parent														50.00%
Ownership interest													33.33%
Percentage of high-voltage transmission line project owned by subsidiary of AE on the Allegheny Series																100.00%
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series																50.00%
Maximum Exposure																	30,000,000
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities				22
Number of contracts that may contain variable interest	3	3			4
Equity or debt invested in non-VIE NUG entities	0	0
Purchased power		1,347,000,000	1,186,000,000		264,000,000	370,000,000	12,000,000	65,000,000	32,000,000	11,000,000	16,000,000	5,000,000
Reserve for adverse purchase power commitment											51,000,000
Current liability included in adverse purchase power commitment											11,000,000
Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments	$ 1,600,000,000	$ 1,600,000,000

XML

Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2012

Variable Interest Entities [Abstract]

Net exposure to loss based upon the casualty value provisions

The following table discloses each company’s net exposure to loss based upon the casualty value provisions mentioned above as of March 31, 2012:

	Maximum Exposure	Discounted Lease Payments, net(1)	Net Exposure
	(In millions)
FES	1,384	1,179	205
OE	583	426	157
Other FE Subsidiaries	643	383	260

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

XML

Fair Value Measurements (Details) (Recurring, USD $) In Millions, unless otherwise specified	Mar. 31, 2012		Dec. 31, 2011
Assets
Fair value, assets	$ 2,981		$ 2,863
Liabilities
Fair value, liabilities	(706)		(619)
Net assets (liabilities)	2,275	[1]	2,244	[1]
FES
Assets
Fair value, assets	1,631		1,530
Liabilities
Fair value, liabilities	(347)		(241)
Net assets (liabilities)	1,284	[2]	1,289	[2]
JCP&L
Assets
Fair value, assets	424		414
Liabilities
Fair value, liabilities	(136)		(147)
Net assets (liabilities)	288	[3]	267	[3]
OE
Assets
Fair value, assets	136	[4]	137	[4]
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(349)		(247)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(342)		(234)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(15)		(23)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(5)		(7)
Non Utility Generation contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(342)	[5]	(349)	[5]
Non Utility Generation contract | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	(136)	[6]	(147)	[6]
Corporate debt securities
Assets
Fair value, assets	1,561		1,544
Corporate debt securities | FES
Assets
Fair value, assets	1,017		1,010
Corporate debt securities | JCP&L
Assets
Fair value, assets	148		144
Corporate debt securities | OE
Assets
Fair value, assets	0		3
Commodity contracts | Derivative Assets
Assets
Fair value, assets	416		264
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	392		248
FTRs | Derivative Assets
Assets
Fair value, assets	1		1
FTRs | Derivative Assets | FES
Assets
Fair value, assets	1		1
Non Utility Generation contract | Derivative Assets
Assets
Fair value, assets	42	[5]	56	[5]
Non Utility Generation contract | Derivative Assets | JCP&L
Assets
Fair value, assets	4	[6]	4	[6]
Equity securities
Assets
Fair value, assets	289	[7]	259	[7]
Equity securities | FES
Assets
Fair value, assets	150	[8]	124	[8]
Equity securities | JCP&L
Assets
Fair value, assets	31	[7]	30	[7]
Foreign government debt securities
Assets
Fair value, assets	0		3
Foreign government debt securities | FES
Assets
Fair value, assets	0		3
U.S. government debt securities
Assets
Fair value, assets	138		148
U.S. government debt securities | FES
Assets
Fair value, assets	5		7
U.S. government debt securities | JCP&L
Assets
Fair value, assets	0		2
U.S. government debt securities | OE
Assets
Fair value, assets	133		132
U.S. state debt securities
Assets
Fair value, assets	313		314
U.S. state debt securities | FES
Assets
Fair value, assets	0		5
U.S. state debt securities | JCP&L
Assets
Fair value, assets	225		219
Other
Assets
Fair value, assets	221	[9]	274	[9]
Other | FES
Assets
Fair value, assets	66	[9]	132	[9]
Other | JCP&L
Assets
Fair value, assets	16	[9]	15	[9]
Other | OE
Assets
Fair value, assets	3	[9]	2	[9]
Level 1
Assets
Fair value, assets	344		308
Liabilities
Fair value, liabilities	(2)		0
Net assets (liabilities)	342	[1]	308	[1]
Level 1 | FES
Assets
Fair value, assets	151		124
Liabilities
Fair value, liabilities	(2)		0
Net assets (liabilities)	149	[2]	124	[2]
Level 1 | JCP&L
Assets
Fair value, assets	31		30
Liabilities
Fair value, liabilities	0		0
Net assets (liabilities)	31	[3]	30	[3]
Level 1 | OE
Assets
Fair value, assets	0	[4]	0	[4]
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(2)		0
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(2)		0
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0		0
Level 1 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0		0
Level 1 | Non Utility Generation contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[5]	0	[5]
Level 1 | Non Utility Generation contract | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	0	[6]	0	[6]
Level 1 | Corporate debt securities
Assets
Fair value, assets	0		0
Level 1 | Corporate debt securities | FES
Assets
Fair value, assets	0		0
Level 1 | Corporate debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 1 | Corporate debt securities | OE
Assets
Fair value, assets	0		0
Level 1 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	1		0
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	1		0
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0		0
Level 1 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0		0
Level 1 | Non Utility Generation contract | Derivative Assets
Assets
Fair value, assets	0	[5]	0	[5]
Level 1 | Non Utility Generation contract | Derivative Assets | JCP&L
Assets
Fair value, assets	0	[6]	0	[6]
Level 1 | Equity securities
Assets
Fair value, assets	289	[7]	259	[7]
Level 1 | Equity securities | FES
Assets
Fair value, assets	150	[8]	124	[8]
Level 1 | Equity securities | JCP&L
Assets
Fair value, assets	31	[7]	30	[7]
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0		0
Level 1 | Foreign government debt securities | FES
Assets
Fair value, assets	0		0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0		0
Level 1 | U.S. government debt securities | FES
Assets
Fair value, assets	0		0
Level 1 | U.S. government debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 1 | U.S. government debt securities | OE
Assets
Fair value, assets	0		0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0		0
Level 1 | U.S. state debt securities | FES
Assets
Fair value, assets	0		0
Level 1 | U.S. state debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 1 | Other
Assets
Fair value, assets	54	[9]	49	[9]
Level 1 | Other | FES
Assets
Fair value, assets	0	[9]	0	[9]
Level 1 | Other | JCP&L
Assets
Fair value, assets	0	[9]	0	[9]
Level 1 | Other | OE
Assets
Fair value, assets	0	[9]	0	[9]
Level 2
Assets
Fair value, assets	2,594		2,498
Liabilities
Fair value, liabilities	(347)		(247)
Net assets (liabilities)	2,247	[1]	2,251	[1]
Level 2 | FES
Assets
Fair value, assets	1,479		1,405
Liabilities
Fair value, liabilities	(340)		(234)
Net assets (liabilities)	1,139	[2]	1,171	[2]
Level 2 | JCP&L
Assets
Fair value, assets	389		380
Liabilities
Fair value, liabilities	0		0
Net assets (liabilities)	389	[3]	380	[3]
Level 2 | OE
Assets
Fair value, assets	136	[4]	137	[4]
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(347)		(247)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(340)		(234)
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0		0
Level 2 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0		0
Level 2 | Non Utility Generation contract | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[5]	0	[5]
Level 2 | Non Utility Generation contract | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	0	[6]	0	[6]
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,561		1,544
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	1,017		1,010
Level 2 | Corporate debt securities | JCP&L
Assets
Fair value, assets	148		144
Level 2 | Corporate debt securities | OE
Assets
Fair value, assets	0		3
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	415		264
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	391		248
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0		0
Level 2 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	0		0
Level 2 | Non Utility Generation contract | Derivative Assets
Assets
Fair value, assets	0	[5]	0	[5]
Level 2 | Non Utility Generation contract | Derivative Assets | JCP&L
Assets
Fair value, assets	0	[6]	0	[6]
Level 2 | Equity securities
Assets
Fair value, assets	0	[7]	0	[7]
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	[8]	0	[8]
Level 2 | Equity securities | JCP&L
Assets
Fair value, assets	0	[7]	0	[7]
Level 2 | Foreign government debt securities
Assets
Fair value, assets	0		3
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	0		3
Level 2 | U.S. government debt securities
Assets
Fair value, assets	138		148
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	5		7
Level 2 | U.S. government debt securities | JCP&L
Assets
Fair value, assets	0		2
Level 2 | U.S. government debt securities | OE
Assets
Fair value, assets	133		132
Level 2 | U.S. state debt securities
Assets
Fair value, assets	313		314
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	0		5
Level 2 | U.S. state debt securities | JCP&L
Assets
Fair value, assets	225		219
Level 2 | Other
Assets
Fair value, assets	167	[9]	225	[9]
Level 2 | Other | FES
Assets
Fair value, assets	66	[9]	132	[9]
Level 2 | Other | JCP&L
Assets
Fair value, assets	16	[9]	15	[9]
Level 2 | Other | OE
Assets
Fair value, assets	3	[9]	2	[9]
Level 3
Assets
Fair value, assets	43		57
Liabilities
Fair value, liabilities	(357)		(372)
Net assets (liabilities)	(314)	[1]	(315)	[1]
Level 3 | FES
Assets
Fair value, assets	1		1
Liabilities
Fair value, liabilities	(5)		(7)
Net assets (liabilities)	(4)	[2]	(6)	[2]
Level 3 | JCP&L
Assets
Fair value, assets	4		4
Liabilities
Fair value, liabilities	(136)		(147)
Net assets (liabilities)	(132)	[3]	(143)	[3]
Level 3 | OE
Assets
Fair value, assets	0	[4]	0	[4]
Level 3 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0		0
Level 3 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0		0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(15)		(23)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(5)		(7)
Level 3 | Non Utility Generation contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(342)	[5]	(349)	[5]
Level 3 | Non Utility Generation contract | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	(136)	[6]	(147)	[6]
Level 3 | Corporate debt securities
Assets
Fair value, assets	0		0
Level 3 | Corporate debt securities | FES
Assets
Fair value, assets	0		0
Level 3 | Corporate debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 3 | Corporate debt securities | OE
Assets
Fair value, assets	0		0
Level 3 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0		0
Level 3 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0		0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	1		1
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	1		1
Level 3 | Non Utility Generation contract | Derivative Assets
Assets
Fair value, assets	42	[5]	56	[5]
Level 3 | Non Utility Generation contract | Derivative Assets | JCP&L
Assets
Fair value, assets	4	[6]	4	[6]
Level 3 | Equity securities
Assets
Fair value, assets	0	[7]	0	[7]
Level 3 | Equity securities | FES
Assets
Fair value, assets	0	[8]	0	[8]
Level 3 | Equity securities | JCP&L
Assets
Fair value, assets	0	[7]	0	[7]
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0		0
Level 3 | Foreign government debt securities | FES
Assets
Fair value, assets	0		0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0		0
Level 3 | U.S. government debt securities | FES
Assets
Fair value, assets	0		0
Level 3 | U.S. government debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 3 | U.S. government debt securities | OE
Assets
Fair value, assets	0		0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0		0
Level 3 | U.S. state debt securities | FES
Assets
Fair value, assets	0		0
Level 3 | U.S. state debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 3 | Other
Assets
Fair value, assets	0	[9]	0	[9]
Level 3 | Other | FES
Assets
Fair value, assets	0	[9]	0	[9]
Level 3 | Other | JCP&L
Assets
Fair value, assets	0	[9]	0	[9]
Level 3 | Other | OE
Assets
Fair value, assets	$ 0	[9]	$ 0	[9]

[1] Excludes $2 million and $(52) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

[2] Excludes $2 million and $(58) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

[3] Excludes $2 million as of December 31, 2011 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

[4] Excludes $1 million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

[5] NUG contracts are generally subject to regulatory accounting and do not impact earnings.

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

[7] NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

[8] NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.

[9] Primarily consists of short-term cash investments.

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivatives instruments

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

Derivatives not designated as hedging instruments:
Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	March 31, 2012		December 31, 2011			March 31, 2012			December 31, 2011
	(In millions)					(In millions)
Power Contracts					Power Contracts
Current Assets	$	300	$	185	Current Liabilities	$	(282	)	$	(196	)
Noncurrent Assets	115		79		Noncurrent Liabilities	(66		)	(51		)
FTRs					FTRs
Current Assets	1		1		Current Liabilities	(15		)	(22		)
Noncurrent Assets	—		—		Noncurrent Liabilities	—			(1		)
NUGs	42		56		NUGs	(342		)	(349		)
Other					Other
Current Assets	1		—		Current Liabilities	(2		)	—
Noncurrent Assets	—		—		Noncurrent Liabilities	—			—
Total Derivatives Assets	$	459	$	321	Total Derivatives Liabilities	$	(707	)	$	(619	)

Volume of First Energy's outstanding derivative transactions

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2012:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	33	47	(14	)	MWH
FTRs	17	—	17		MWH
NUGs	23	—	23		MWH
Natural Gas Futures	11	—	11		Million British Thermal Units

Effect of derivative instruments on statements of income and comprehensive income

The effect of derivative instruments on the Consolidated Statements of Income during the three months ended March 31, 2012 and 2011, are summarized in the following tables:

	Three Months Ended March 31
	Power Contracts			FTRs			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(5	)	$	—		$	—		$	(5	)
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(9	)	$	—		$	—		$	(9	)
Effective Gain (Loss) Reclassified to:
Purchased Power Expense	16			—			—			16
Revenues	(12		)	—			—			(12		)
Fuel Expense	—			—			—			—
Derivatives Not in a Hedging Relationship
2012
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	—		$	—		$	—		$	—
Other Operating Expense	55			5			(2		)	58
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(117		)	—			—			(117		)
Revenues	112			6			—			118
Other Operating Expense	—			(24		)	—			(24		)
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	29		$	—		$	—		$	29
Other Operating Expense	(20		)	1			1			(18		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(37		)	—			—			(37		)
Revenue	10			3			(1		)	12
Other Operating Expense	—			(15		)	—			(15		)

Reconciliation of changes in the fair value of certain contracts that are deferred

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2012	$	(293	)	$	(8	)	$	(301	)
Additions/Change in value of existing contracts	(79		)	(1		)	(80		)
Settled contracts	72			4			76
Outstanding net asset (liability) as of March 31, 2012	$	(300	)	$	(5	)	$	(305	)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts	(89		)	—			(89		)
Settled contracts	72			(10		)	62
Outstanding net asset (liability) as of March 31, 2011	$	(362	)	$	—		$	(362	)

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

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Consolidated Statements of Cash Flows (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 306	$ 47
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	285	225
Amortization of regulatory assets, net	75	132
Nuclear fuel and lease amortization	58	47
Deferred purchased power and other costs	(107)	(58)
Deferred income taxes and investment tax credits, net	265	204
Deferred rents and lease market valuation liability	(23)	(15)
Stock based compensation	(29)	(9)
Accrued compensation and retirement benefits	(162)	(53)
Commodity derivative transactions, net	(64)	(25)
Pension trust contribution	(600)	(157)
Asset impairments	4	31
Cash collateral, net	(28)	(28)
Decrease (increase) in operating assets-
Receivables	59	164
Materials and supplies	(118)	40
Prepayments and other current assets	(19)	118
Increase (decrease) in operating liabilities-
Accounts payable	(256)	(90)
Accrued taxes	(116)	(182)
Accrued interest	70	76
Other	(13)	24
Net cash provided from (used for) operating activities	(413)	491
New financing-
Long-term debt	0	217
Short-term borrowings, net	1,075	0
Redemptions and Repayments-
Long-term debt	(16)	(359)
Short-term borrowings, net	0	(214)
Common stock dividend payments	(230)	(190)
Other	(10)	(4)
Net cash provided from (used for) financing activities	819	(550)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(589)	(449)
Sales of investment securities held in trusts	251	969
Purchases of investment securities held in trusts	(266)	(993)
Cash investments	78	47
Cash received in Allegheny merger	0	590
Other	(8)	(23)
Net cash provided from (used for) investing activities	(534)	141
Net change in cash and cash equivalents	(128)	82
Cash and cash equivalents at beginning of period	202	1,019
Cash and cash equivalents at end of period	74	1,101
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: merger with Allegheny, common stock issued	0	4,354
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	122	45
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	63	69
Nuclear fuel and lease amortization	57	47
Deferred income taxes and investment tax credits, net	83	67
Deferred rents and lease market valuation liability	(47)	(39)
Accrued compensation and retirement benefits	(10)	(16)
Commodity derivative transactions, net	(52)	(35)
Pension trust contribution	(209)	0
Asset impairments	3	19
Cash collateral, net	(25)	(27)
Decrease (increase) in operating assets-
Receivables	28	(76)
Materials and supplies	(59)	61
Prepayments and other current assets	14	8
Increase (decrease) in operating liabilities-
Accounts payable	17	(18)
Accrued taxes	(155)	(3)
Other	(8)	(8)
Net cash provided from (used for) operating activities	(178)	94
New financing-
Long-term debt	0	150
Short-term borrowings, net	0	350
Redemptions and Repayments-
Long-term debt	0	(332)
Short-term borrowings, net	0
Other	(3)	(1)
Net cash provided from (used for) financing activities	(3)	167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(181)	(159)
Sales of investment securities held in trusts	83	216
Purchases of investment securities held in trusts	(90)	(231)
Customer acquisition costs		0
Loans to affiliated companies, net	371	(82)
Other	(2)	(7)
Net cash provided from (used for) investing activities	181	(263)
Net change in cash and cash equivalents	0	(2)
Cash and cash equivalents at beginning of period	7	9
Cash and cash equivalents at end of period	7	7
OE
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	31	32
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	24	23
Amortization of regulatory assets, net	0	1
Deferred income taxes and investment tax credits, net	11	29
Accrued compensation and retirement benefits	(17)	(13)
Amortization of lease costs	33	33
Pension trust contribution	0	(27)
Cash collateral, net	(2)	0
Decrease (increase) in operating assets-
Receivables	27	82
Prepayments and other current assets	7	(23)
Increase (decrease) in operating liabilities-
Accounts payable	(10)	(20)
Accrued taxes	1	(10)
Other	(5)	(3)
Net cash provided from (used for) operating activities	100	104
Redemptions and Repayments-
Short-term borrowings, net	0	(39)
Common stock dividend payments	0	(100)
Other	(1)	0
Net cash provided from (used for) financing activities	(1)	(139)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(43)	(37)
Sales of investment securities held in trusts	37	8
Purchases of investment securities held in trusts	(38)	(9)
Loans to affiliated companies, net	(78)	0
Other	(3)	(2)
Net cash provided from (used for) investing activities	(125)	(40)
Net change in cash and cash equivalents	(26)	(75)
Cash and cash equivalents at beginning of period	26	420
Cash and cash equivalents at end of period	0	345
JCP&L
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	26	23
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	30	26
Amortization of regulatory assets, net	20	82
Deferred purchased power and other costs	(69)	(27)
Deferred income taxes and investment tax credits, net	52	28
Accrued compensation and retirement benefits	(22)	(11)
Cash collateral, net	6	0
Decrease (increase) in operating assets-
Receivables	(2)	86
Prepaid taxes	(6)	(2)
Increase (decrease) in operating liabilities-
Accounts payable	(22)	(62)
Accrued taxes	(5)	13
Accrued interest	12	12
Other	9	14
Net cash provided from (used for) operating activities	29	182
New financing-
Short-term borrowings, net	40	0
Redemptions and Repayments-
Long-term debt	(8)	(7)
Net cash provided from (used for) financing activities	32	(7)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(56)	(47)
Sales of investment securities held in trusts	95	217
Purchases of investment securities held in trusts	(99)	(222)
Loans to affiliated companies, net	0	(121)
Other	(1)	(2)
Net cash provided from (used for) investing activities	(61)	(175)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	$ 0	$ 0

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Consolidated Statements of Income (Unaudited) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
Income Statement [Abstract]
Excise tax collections included in Revenue	$ 121	$ 119

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Supplemental Guarantor Information

3 Months Ended

Mar. 31, 2012

Supplemental Guarantor Information [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

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 and Comprehensive Income for the three months endedMarch 31, 2012 and 2011, Consolidating Balance Sheets as of March 31, 2012 and December 31, 2011 and Consolidating Statements of Cash Flows for the three months ended March 31, 2012 and 2011 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 AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,490		$	542		$	394		$	(910	)	$	1,516
OPERATING EXPENSES:
Fuel	—			240			55			—			295
Purchased power from affiliates	965			—			62			(910		)	117
Purchased power from non-affiliates	487			—			—			—			487
Other operating expenses	76			92			116			11			295
Provision for depreciation	1			30			34			(2		)	63
General taxes	20			10			7			—			37
Total operating expenses	1,549			372			274			(901		)	1,294
OPERATING INCOME (LOSS)	(59		)	170			120			(9		)	222
OTHER INCOME (EXPENSE):
Investment income	1			4			5			(4		)	6
Miscellaneous income, including net income from equity investees	258			—			—			(254		)	4
Interest expense — affiliates	(4		)	(1		)	(1		)	4			(2		)
Interest expense — other	(23		)	(26		)	(7		)	15			(41		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	232			(22		)	5			(239		)	(24		)
INCOME BEFORE INCOME TAXES	173			148			125			(248		)	198
INCOME TAXES (BENEFITS)	51			(1		)	23			3			76
NET INCOME	$	122		$	149		$	102		$	(251	)	$	122
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	122		$	149		$	102		$	(251	)	$	122
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized loss on derivative hedges	(5		)	—			—			—			(5		)
Change in unrealized gain on available for sale securities	10			—			10			(10		)	10
Other comprehensive income (loss)	—			(4		)	10			(6		)	—
Income taxes (benefits) on other comprehensive income (loss)	2			(2		)	4			(2		)	2
Other comprehensive income (loss), net of tax	(2		)	(2		)	6			(4		)	(2		)
COMPREHENSIVE INCOME	$	120		$	147		$	108		$	(255	)	$	120

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,366		$	743		$	469		$	(1,187	)	$	1,391
OPERATING EXPENSES:
Fuel	1			294			48			—			343
Purchased power from affiliates	1,185			2			69			(1,187		)	69
Purchased power from non-affiliates	297			—			—			—			297
Other operating expenses	162			111			180			12			465
Provision for depreciation	1			32			38			(2		)	69
General taxes	10			11			8			—			29
Impairment of long-lived assets	—			14			—			—			14
Total operating expenses	1,656			464			343			(1,177		)	1,286
OPERATING INCOME (LOSS)	(290		)	279			126			(10		)	105
OTHER INCOME (EXPENSE):
Investment income	1			—			5			—			6
Miscellaneous income, including net income from equity investees	242			1			—			(239		)	4
Interest expense — affiliates	(1		)	—			—			—			(1		)
Interest expense — other	(24		)	(28		)	(17		)	16			(53		)
Capitalized interest	—			5			5			—			10
Total other income (expense)	218			(22		)	(7		)	(223		)	(34		)
INCOME (LOSS) BEFORE INCOME TAXES	(72		)	257			119			(233		)	71
INCOME TAXES (BENEFITS)	(117		)	96			45			2			26
NET INCOME	$	45		$	161		$	74		$	(235	)	$	45
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	45		$	161		$	74		$	(235	)	$	45
OTHER COMPREHENSIVE INCOME
Pensions and OPEB prior service costs	(10		)	(4		)	(6		)	10			(10		)
Amortized loss on derivative hedges	(9		)	—			—			—			(9		)
Change in unrealized gain on available for sale securities	8			—			8			(8		)	8
Other comprehensive income (loss)	(11		)	(4		)	2			2			(11		)
Income taxes (benefits) on other comprehensive income (loss)	(6		)	(2		)	1			1			(6		)
Other comprehensive income (loss), net of tax	(5		)	(2		)	1			1			(5		)
COMPREHENSIVE INCOME	$	40		$	159		$	75		$	(234	)	$	40

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of March 31, 2012	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	395		—		—		—			395
Affiliated companies	472		439		241		(611		)	541
Other	50		19		53		—			122
Notes receivable from affiliated companies	81		1,369		44		(1,482		)	12
Materials and supplies, at average cost	62		283		206		—			551
Derivatives	322		—		—		—			322
Prepayments and other	7		17		1		(1		)	24
	1,389		2,134		545		(2,094		)	1,974
PROPERTY, PLANT AND EQUIPMENT:
In service	84		5,614		5,689		(385		)	11,002
Less — Accumulated provision for depreciation	29		1,843		2,524		(182		)	4,214
	55		3,771		3,165		(203		)	6,788
Construction work in progress	31		171		971		—			1,173
	86		3,942		4,136		(203		)	7,961
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,240		—			1,240
Investment in affiliated companies	5,956		—		—		(5,956		)	—
Other	—		7		—		—			7
	5,956		7		1,240		(5,956		)	1,247
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		274		—		(274		)	—
Customer intangibles	120		—		—		—			120
Goodwill	24		—		—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		21		—		99			120
Derivatives	117		—		—		—			117
Other	123		111		2		(65		)	171
	384		426		25		(240		)	595
	$	7,815	$	6,509	$	5,946	$	(8,493	)	$	11,777
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	411	$	514	$	(21	)	$	905
Short-term borrowings-
Affiliated companies	1,413		69		—		(1,482		)	—
Accounts payable-
Affiliated companies	663		175		256		(611		)	483
Other	69		121		—		—			190
Accrued Taxes	31		33		24		(13		)	75
Derivatives	281		—		—		—			281
Other	38		111		24		72			245
	2,496		920		818		(2,055		)	2,179
CAPITALIZATION:
Total equity	3,695		3,244		2,697		(5,941		)	3,695
Long-term debt and other long-term obligations	1,482		1,903		641		(1,229		)	2,797
	5,177		5,147		3,338		(7,170		)	6,492
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		917			917
Accumulated deferred income taxes	18		—		532		(185		)	365
Asset retirement obligations	—		28		891		—			919
Retirement benefits	31		120		—		—			151
Lease market valuation liability	—		160		—		—			160
Other	93		134		367		—			594
	142		442		1,790		732			3,106
	$	7,815	$	6,509	$	5,946	$	(8,493	)	$	11,777

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2011	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	424		—		—		—			424
Affiliated companies	476		643		262		(781		)	600
Other	28		20		13		—			61
Notes receivable from affiliated companies	155		1,346		69		(1,187		)	383
Materials and supplies, at average cost	60		232		200		—			492
Derivatives	219		—		—		—			219
Prepayments and other	11		26		1		—			38
	1,373		2,274		545		(1,968		)	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	84		5,573		5,711		(385		)	10,983
Less — Accumulated provision for depreciation	28		1,813		2,449		(180		)	4,110
	56		3,760		3,262		(205		)	6,873
Construction work in progress	29		195		790		—			1,014
	85		3,955		4,052		(205		)	7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,223		—			1,223
Investment in affiliated companies	5,716		—		—		(5,716		)	—
Other	—		7		—		—			7
	5,716		7		1,223		(5,716		)	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	10		307		—		(317		)	—
Customer intangibles	123		—		—		—			123
Goodwill	24		—		—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		5		—		75			80
Derivatives	79		—		—		—			79
Other	89		99		3		(62		)	129
	325		431		26		(304		)	478
	$	7,499	$	6,667	$	5,846	$	(8,193	)	$	11,819
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	411	$	513	$	(20	)	$	905
Short-term borrowings-
Affiliated companies	1,065		89		32		(1,186		)	—
Accounts payable-
Affiliated companies	777		228		211		(780		)	436
Other	99		121		—		—			220
Accrued Taxes	84		42		110		(9		)	227
Derivatives	189		—		—		—			189
Other	62		141		16		42			261
	2,277		1,032		882		(1,953		)	2,238
CAPITALIZATION:
Common stockholder’s equity	3,593		3,097		2,587		(5,700		)	3,577
Long-term debt and other long-term obligations	1,483		1,905		641		(1,230		)	2,799
	5,076		5,002		3,228		(6,930		)	6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		925			925
Accumulated deferred income taxes	12		—		510		(236		)	286
Asset retirement obligations	—		28		876		—			904
Retirement benefits	56		300		—		—			356
Lease market valuation liability	—		171		—		—			171
Other	78		134		350		1			563
	146		633		1,736		690			3,205
	$	7,499	$	6,667	$	5,846	$	(8,193	)	$	11,819

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(419	)	$	66		$	175		$	—		$	(178	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	347			—			—			(347		)	—
Redemptions and Repayments-
Short-term borrowings, net	—			(20		)	(32		)	52			—
Other	—			(2		)	(1		)	—			(3		)
Net cash provided from (used for) financing activities	347			(22		)	(33		)	(295		)	(3		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(18		)	(161		)	—			(181		)
Sales of investment securities held in trusts	—			—			83			—			83
Purchases of investment securities held in trusts	—			—			(90		)	—			(90		)
Loans to affiliated companies, net	74			(23		)	25			295			371
Other	—			(3		)	1			—			(2		)
Net cash provided from (used for) investing activities	72			(44		)	(142		)	295			181
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—		$	7

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2011	FES			FGCO			NGC			Eliminations		Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(215	)	$	267		$	42		$	—	$	94
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			90			60			—		150
Short-term borrowings, net	322			28			—			—		350
Redemptions and Repayments-
Long-term debt	(131		)	(141		)	(60		)	—		(332		)
Other	(1		)	—			—			—		(1		)
Net cash used for financing activities	190			(23		)	—			—		167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(3		)	(40		)	(116		)	—		(159		)
Sales of investment securities held in trusts	—			—			216			—		216
Purchases of investment securities held in trusts	—			—			(231		)	—		(231		)
Loans to affiliated companies, net	28			(200		)	90			—		(82		)
Customer acquisition costs	—			—			—			—		—
Other	—			(6		)	(1		)	—		(7		)
Net cash provided from (used for) investing activities	25			(246		)	(42		)	—		(263		)
Net change in cash and cash equivalents	—			(2		)	—			—		(2		)
Cash and cash equivalents at beginning of period	—			9			—			—		9
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—	$	7

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2012	Apr. 30, 2012
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	0001031296
Document Type	10-Q
Document Period End Date	Mar. 31, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q1
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
JCP&L
Entity Common Stock Shares Outstanding		13,628,447

XML

Segment Information

3 Months Ended

Mar. 31, 2012

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

FirstEnergy has three reportable operating segments — Regulated Distribution, Regulated Independent Transmission and Competitive Energy Services.

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below, which includes financial results for Allegheny subsidiaries beginning February 25, 2011. FES, OE and JCP&L 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 65,000 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, ME, PN, 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. Its results reflect the commodity costs of securing electric generation 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 formulaic rates that recover costs and provide 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 revenues from operating a portion of the FirstEnergy transmission system. Its results reflect the net transmission expenses related to the delivery of the respective generation loads.

The Competitive Energy Services segment, through FES and AE Supply, supplies electricity to end-use customers through retail and wholesale arrangements, including competitive retail sales to customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland and the provision of partial POLR and default service for some utilities in Ohio, Pennsylvania and Maryland, including the Utilities. This business segment controls approximately 17,000 MWs of capacity (excluding approximately 2,700 MWs from unregulated plants expected to be closed by September 1, 2012 (see Note 8, Regulatory Matters of the Combined Notes to Consolidated Financial Statements) and also purchases electricity to meet sales obligations. The segment’s net income is primarily derived from 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.

Other/Corporate contains corporate items and other businesses that are below the quantifiable threshold for separate disclosure as a reportable segment. Reconciling adjustments primarily consist of elimination of intersegment transactions.

Segment Financial Information

Three Months Ended	Regulated Distribution		Competitive Energy Services		Regulated Independent Transmission		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
March 31, 2012
External revenues	$	2,383	$	1,607	$	109	$	(24	)	$	1		$	4,076
Internal revenues	—		268		—		—			(266		)	2
Total revenues	2,383		1,875		109		(24		)	(265		)	4,078
Depreciation and amortization	234		100		18		8			—			360
Investment income	24		6		—		—			(19		)	11
Net interest charges	142		54		12		21			—			229
Income taxes	108		83		20		(16		)	27			222
Net income	183		141		34		(28		)	(24		)	306
Total assets	27,551		17,187		2,452		501			—			47,691
Total goodwill	5,551		893		—		—			—			6,444
Property additions	301		243		28		17			—			589
March 31, 2011
External revenues	$	2,268	$	1,254	$	67	$	(23	)	$	(22	)	$	3,544
Internal revenues	—		343		—		—			(311		)	32
Total revenues	2,268		1,597		67		(23		)	(333		)	3,576
Depreciation and amortization	250		88		13		6			—			357
Investment income	25		6		—		—			(10		)	21
Net interest charges	131		68		9		19			(14		)	213
Income taxes	64		9		7		—			31			111
Net income	109		15		12		(55		)	(34		)	47
Total assets	27,766		17,399		2,486		914			—			48,565
Total goodwill	5,551		956		—		—			—			6,507
Property additions	177		214		27		31			—			449

XML

Consolidated Statements of Comprehensive Income (Unaudited) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2012	Mar. 31, 2011
NET INCOME	$ 306	$ 47
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(53)	(44)
Amortized losses on derivative hedges	(2)	(6)
Change in unrealized gain on available-for-sale securities	10	9
Other comprehensive loss	(45)	(41)
Income taxes (benefits) on other comprehensive income (loss)	(24)	(19)
Other comprehensive loss, net of tax	(21)	(22)
COMPREHENSIVE INCOME	285	25
Comprehensive loss attributable to noncontrolling interest	0	(5)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	285	30
FES
NET INCOME	122	45
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5)	(10)
Amortized losses on derivative hedges	(5)	(9)
Change in unrealized gain on available-for-sale securities	10	8
Other comprehensive loss	0	(11)
Income taxes (benefits) on other comprehensive income (loss)	2	(6)
Other comprehensive loss, net of tax	(2)	(5)
COMPREHENSIVE INCOME	120	40
OE
NET INCOME	31	32
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(10)	(7)
Other comprehensive loss	(10)	(7)
Income taxes (benefits) on other comprehensive income (loss)	(5)	(4)
Other comprehensive loss, net of tax	(5)	(3)
COMPREHENSIVE INCOME	26	29
JCP&L
NET INCOME	26	23
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(6)	(6)
Other comprehensive loss	(6)	(6)
Income taxes (benefits) on other comprehensive income (loss)	(4)	(3)
Other comprehensive loss, net of tax	(2)	(3)
COMPREHENSIVE INCOME	$ 24	$ 20

XML

Variable Interest Entities

3 Months Ended

Mar. 31, 2012

Variable Interest Entities [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary

VIEs included in FirstEnergy’s consolidated financial statements for the first quarter of 2012 are: the PNBV and Shippingport capital trusts that were created to refinance debt originally issued in connection with sale and leaseback transactions; 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 and JCP&L's supply of BGS, of which $270 million was outstanding as of March 31, 2012; and special purpose limited liabilities companies of MP and PE created to issue environmental control bonds that were used to construct environmental control facilities, of which $504 million was outstanding as of March 31, 2012.

The caption noncontrolling interest within the consolidated financial statements is used to reflect the portion of the VIE that FirstEnergy consolidates, but does not wholly own. The change in noncontrolling interest within the Consolidated Balance Sheets during the three months endedMarch 31, 2012, was primarily due to a $3 million distribution to owners.

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.

Mining Operations

On October 18, 2011, a subsidiary of Gunvor Group, Ltd. purchased a one-third interest in the Signal Peak joint venture in which FEV held a 50% interest. FEV retained a 33-1/3% equity ownership in the joint venture. Prior to the sale, FirstEnergy consolidated this joint venture since FEV was determined to be the primary beneficiary of the VIE. As a result of the sale, FEV was no longer determined to be the primary beneficiary and its retained 33-1/3% interest is subsequently accounted for using the equity method of accounting.

PATH-WV

PATH 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 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 (PATH-Allegheny) 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 $30 million as of March 31, 2012.

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 applicable utilities if the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy, through its subsidiaries JCP&L, ME, PN, PE, WP and MP, maintains 22 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 three 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 three entities; however, FirstEnergy applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. One of JCP&L's NUG contracts, to which the scope exception was applied, expired during 2011.

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 three contracts that may contain a variable interest that were held by FirstEnergy subsidiaries during the three months endedMarch 31, 2012, were $12 million, $32 million and $16 million for JCP&L, PE and WP, respectively. Purchased power costs related to the four contracts that may contain a variable interest that were held by JCP&L, PE and WP, respectively, during the three months endedMarch 31, 2011 were $65 million, $11 million, and $5 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 wherein WP may hold a variable interest, for which WP has taken the scope exception. As of March 31, 2012, WP’s reserve for this adverse purchase power commitment was $51 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, OE and other FE subsidiaries 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 March 31, 2012:

	Maximum Exposure	Discounted Lease Payments, net(1)	Net Exposure
	(In millions)
FES	1,384	1,179	205
OE	583	426	157
Other FE Subsidiaries	643	383	260

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

XML

Income Taxes

3 Months Ended

Mar. 31, 2012

Income Tax Disclosure [Abstract]

INCOME TAXES

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. During the first quarter of 2012, the federal government issued further guidance related to the tax accounting of costs to repair and maintain fixed assets. This guidance provided a safe harbor method of tax accounting for AE companies and allowed these companies to reduce their amount of unrecognized tax benefits by $21 million, with a corresponding adjustment to accumulated deferred income taxes for this temporary tax item, with no resulting impact to FirstEnergy's effective tax rate in the first quarter of 2012. There were no other material changes to FirstEnergy's unrecognized income tax benefits during the first quarter of 2012 or 2011.

As of March 31, 2012, it is reasonably possible that approximately $45 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $10 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. During the first quarter of 2012 and 2011, there were no material changes to the amount of accrued interest, except for a $6 million increase in accrued interest from the merger with AE in the first quarter of 2011. The net amount of interest accrued as of March 31, 2012 was $12 million, compared with $11 million as of December 31, 2011.

As a result of the non-deductible portion of merger transaction costs, FirstEnergy's effective tax rate was unfavorably impacted by $30 million in the first three months of 2011.

FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS (2008-2010) and state tax authorities. FirstEnergy's tax returns for all state jurisdictions are open from 2008-2010, and additionally 2005-2007 for New Jersey. The IRS completed its audits of tax year 2008 in July 2010 and tax year 2009 in April 2011, with both tax years having one open item. Tax years 2010-2011 are under review by the IRS. Allegheny is currently under audit by the IRS for tax years 2007 and 2008. Allegheny has filed its 2009 and 2010 federal returns and such filings are subject to review. State tax returns for tax years 2008 through 2010 remain subject to review in Pennsylvania, West Virginia, Maryland and Virginia for certain subsidiaries of AE. 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, results of operations, cash flow or liquidity.

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2012

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FE CONSOLIDATED
Recurring Fair Value Measurements	March 31, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,561		$	—		1,561			$	—	$	1,544		$	—		$	1,544
Derivative assets - commodity contracts	1			415			—			416			—		264			—			264
Derivative assets - FTRs	—			—			1			1			—		—			1			1
Derivative assets - NUG contracts(1)	—			—			42			42			—		—			56			56
Equity securities(2)	289			—			—			289			259		—			—			259
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			138			—			138			—		148			—			148
U.S. state debt securities	—			313			—			313			—		314			—			314
Other(3)	54			167			—			221			49		225			—			274
Total assets	344			2,594			43			2,981			308		2,498			57			2,863
Liabilities
Derivative liabilities - commodity contracts	(2		)	(347		)	—			(349		)	—		(247		)	—			(247		)
Derivative liabilities - FTRs	—			—			(15		)	(15		)	—		—			(23		)	(23		)
Derivative liabilities - NUG contracts(1)	—			—			(342		)	(342		)	—		—			(349		)	(349		)
Total liabilities	(2		)	(347		)	(357		)	(706		)	—		(247		)	(372		)	(619		)
Net assets (liabilities)(4)	$	342		$	2,247		$	(314	)	$	2,275		$	308	$	2,251		$	(315	)	$	2,244

⁽¹⁾  NUG contracts are generally subject to regulatory accounting and do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

⁽³⁾  Primarily consists of short-term cash investments.

⁽⁴⁾  Excludes $2 million and $(52) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

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 for the periods ended March 31, 2012 and December 31, 2011:

	NUG Contracts									FTRs
	Derivative Assets(1)			Derivative Liabilities(1)			Net(1)			Derivative Assets(1)			Derivative Liabilities(1)			Net(1)
										(In millions)
January 1, 2011 Balance	$	122		$	(466	)	$	(344	)	$	—		$	—		$	—
Realized gain (loss)	—			—			—			—			—			—
Unrealized gain (loss)	(58		)	(144		)	(202		)	2			(27		)	(25		)
Purchases	—			—			—			13			(4		)	9
Issuances	—			—			—			—			—			—
Sales	—			—			—			—			—			—
Settlements	(7		)	261			254			(14		)	20			6
Transfers in (out) of Level 3	—			—			—						(12		)	(12		)
December 31, 2011 Balance	$	57		$	(349	)	$	(292	)	$	1		$	(23	)	$	(22	)
Realized gain (loss)	—			—			—			—			—			—
Unrealized gain (loss)	(14		)	(65		)	(79		)	—			(3		)	(3		)
Purchases	—			—			—			—			—			—
Issuances	—			—			—			—			—			—
Sales	—			—			—			—			—			—
Settlements	(1		)	72			71			—			11			11
Transfers in (out) of Level 3	—			—			—			—			—			—
March 31, 2012 Balance	$	42		$	(342	)	$	(300	)	$	1		$	(15	)	$	(14	)

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

Quantitative information for level 3 valuation

The following table provides quantitative information for NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	(14	)	Model	RTO auction clearing prices	($4.18) to $9.81	$	1.51	Dollars/MWH
NUG Contracts	$	(300	)	Model	Generation Power regional prices	500 to 6,809,000 $58.71 to $84.92	2,547,000 $66.77		MWH Dollars/MWH

Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities

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 March 31, 2012 and December 31, 2011:

	March 31, 2012(1)				December 31, 2011(2)
	Cost Basis	Unrealized Gains	Unrealized Losses	Fair Value	Cost Basis	Unrealized Gains		Unrealized Losses		Fair Value
	(In millions)
Debt securities
FE Consolidated	1,967	42	—	2,009	1,980	25	25	—	—	2,005
FES	1,001	21	—	1,022	1,012	13		—		1,025
OE	133	—	—	133	134	—		—		134
JCP&L	359	12	—	371	356	7		—		363
Equity securities
FE Consolidated	246	42	—	288	222	36		—		258
FES	127	23	—	150	104	20		—		124
JCP&L	27	4	—	31	27	3		—		30

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $160 million; FES - $68 million; OE - $4 million; JCP&L - $19 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $164 million; FES - $74 million; OE - $2 million; JCP&L - $19 million.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales and interest and dividend income for the three months ended March 31, 2012 and 2011 were as follows:

March 31, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	251	$	19	$	(17	)	$	15
FES	83		12		(11		)	7
OE	37		—		—			1
JCP&L	95		1		(1		)	4
March 31, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	969	$	100	$	(29	)	$	24
FES	216		12		(15		)	15
OE	8		—		—			1
JCP&L	217		22		(4		)	4

Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities

The following table provides the amortized cost basis, unrealized gains and approximate fair values of investments in held-to-maturity securities as of March 31, 2012 and December 31, 2011:

	March 31, 2012			December 31, 2011
	Cost Basis	Unrealized Gains	Fair Value	Cost Basis	Unrealized Gains	Fair Value
	(In millions)
Debt Securities
FE Consolidated	336	41	377	402	50	452
OE	162	19	181	163	21	184

Fair value and related carrying amounts of long-term debt and other long-term obligations

The following table provides the approximate fair value and related carrying amounts of long-term debt and other long-term obligations, excluding capital lease obligations and net unamortized premiums and discounts, as of March 31, 2012 and December 31, 2011:

	March 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FE Consolidated	$	17,130	$	19,321	$	17,165	$	19,320
FES	3,674		3,944		3,675		3,931
OE	1,158		1,469		1,157		1,434
JCP&L	1,770		2,071		1,777		2,080

FES

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FES
Recurring Fair Value Measurements	March 31, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,017		$	—		$	1,017		$	—	$	1,010		$	—		$	1,010
Derivative assets - commodity contracts	1			391			—			392			—		248			—			248
Derivative assets - FTRs	—			—			1			1			—		—			1			1
Equity securities(1)	150			—			—			150			124		—			—			124
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			5			—			5			—		7			—			7
U.S. state debt securities	—			—			—			—			—		5			—			5
Other(2)	—			66			—			66			—		132			—			132
Total assets	151			1,479			1			1,631			124		1,405			1			1,530
Liabilities
Derivative liabilities - commodity contracts	(2		)	(340		)	—			(342		)	—		(234		)	—			(234		)
Derivative liabilities - FTRs	—			—			(5		)	(5		)	—		—			(7		)	(7		)
Total liabilities	(2		)	(340		)	(5		)	(347		)	—		(234		)	(7		)	(241		)
Net assets (liabilities)(3)	$	149		$	1,139		$	(4	)	$	1,284		$	124	$	1,171		$	(6	)	$	1,289

⁽¹⁾  NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.

⁽²⁾  Primarily consists of short-term cash investments.

⁽³⁾  Excludes $2 million and $(58) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, 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

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 for the periods ended March 31, 2012 and December 31, 2011:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2011 Balance	$	—		$	—		$	—
Realized gain (loss)	—			—			—
Unrealized gain (loss)	4			(8		)	(4		)
Purchases	2			(1		)	1
Issuances	—			—			—
Sales	—			—			—
Settlements	(5		)	2			(3		)
Transfers in (out) of Level 3	—			—			—
December 31, 2011 Balance	$	1		$	(7	)	$	(6	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(1		)	(1		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			4			4
Transfers in (out) of Level 3	—			—			—
March 31, 2012 Balance	$	1		$	(4	)	$	(3	)

Quantitative information for level 3 valuation

The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	(3	)	Model	RTO auction clearing prices	($4.18) to $8.03	$	0.76	Dollars/MWH

OE

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

OE
Recurring Fair Value Measurements	March 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets	(In millions)
Corporate debt securities	$	—	$	—	$	—	$	—		$	—	$	3	$	—	$	3
U.S. government debt securities	—		133		—		133			—		132		—		132
Other(1)	—		3		—		3			—		2		—		2
Total assets(2)	$	—	$	136	$	—	$	136		$	—	$	137	$	—	$	137

⁽¹⁾  Primarily consists of short-term cash investments.

⁽²⁾  Excludes $1 million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

JCP&L

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

JCP&L
Recurring Fair Value Measurements	March 31, 2012										December 31, 2011
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	148	$	—		$	148		$	—	$	144	$	—		$	144
Derivative assets - NUG contracts(1)	—		—		4			4			—		—		4			4
Equity securities(2)	31		—		—			31			30		—		—			30
U.S. government debt securities	—		—		—			—			—		2		—			2
U.S. state debt securities	—		225		—			225			—		219		—			219
Other(3)	—		16		—			16			—		15		—			15
Total assets	31		389		4			424			30		380		4			414
Liabilities
Derivative liabilities - NUG contracts(1)	—		—		(136		)	(136		)	—		—		(147		)	(147		)
Total liabilities	—		—		(136		)	(136		)	—		—		(147		)	(147		)
Net assets (liabilities)(4)	$	31	$	389	$	(132	)	$	288		$	30	$	380	$	(143	)	$	267

⁽¹⁾  NUG contracts are subject to regulatory accounting and do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

⁽³⁾  Primarily consists of short-term cash investments.

⁽⁴⁾  Excludes $2 million as of December 31, 2011 of receivables, payables, 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

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 for the periods ended March 31, 2012 and December 31, 2011:

	Derivative Asset NUG Contracts(1)			Derivative Liability NUG Contracts(1)			Net NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	6		(233		)	(227		)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(2		)	(11		)	(13		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			97			97
Transfers in (out) of Level 3	—			—			—
December 31, 2011	$	4		$	(147	)	$	(143	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(6		)	(6		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			17			17
Transfers in (out) of Level 3	—			—			—
March 31, 2012	$	4		$	(136	)	$	(132	)

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

Quantitative information for level 3 valuation

The following table provides quantitative information for NUG contracts held by JCP&L that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
NUG Contracts	$	(132	)	Model	Generation Power regional prices	69,000 to 736,000 $58.71 to $84.92	157,000 $68.65	MWH Dollars/MWH

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Significant Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2012

Significant Accounting Policies [Abstract]

Earnings Per Share, Policy [Policy Text Block]

Basic earnings per share of common stock are computed using the weighted average number of 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 could result if dilutive securities and other agreements to issue common stock were exercised.

Pension and Other Postretirement Plans, Policy [Policy Text Block]

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. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pensions and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. 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.

Consolidation, Variable Interest Entity, Policy [Policy Text Block]

FirstEnergy performs qualitative analyses to determine whether a variable interest gives FirstEnergy 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary

XML

Regulatory Matters

3 Months Ended

Mar. 31, 2012

Regulated Operations [Abstract]

REGULATORY MATTERS

REGULATORY MATTERS

STATE REGULATION

Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility.

MARYLAND

PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions overseen by the MDPSC and a third party monitor. The settlements with respect to residential SOS for PE customers expire on December 31, 2012, but by statute service will continue in the same manner unless changed by order of the MDPSC. The settlement provisions relating to non-residential service have expired but, by MDPSC order, the terms of service remain in place unless PE requests or the MDPSC orders a change. PE recovers its costs plus a return for providing SOS.

On September 29, 2009, the MDPSC opened a 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 December 2010, the MDPSC issued an order soliciting comments on a model RFP for solicitation of long-term energy commitments by Maryland electric utilities. PE and numerous other parties filed comments, and subsequently the MDPSC issued an order requiring the utilities to issue the RFP crafted by the MDPSC. The RFPs were issued by the utilities as ordered by the MDPSC. The order, as amended, indicated that bids were due by January 20, 2012, and that the MDPSC would be the entity evaluating all bids.On April 12, 2012, the MDPSC issued an order requiring certain Maryland electric utilities, but not PE, to enter into a contract for differences, an electricity hedging arrangement, with respect to a 661 MW natural gas-fired combined cycle generation plant to be built in Charles County, Maryland.

The Maryland legislature in 2008 adopted a statute codifying the EmPOWER Maryland goals to reduce electric consumption by10%and reduce electricity demand by15%, in each case by 2015. 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 millionfor the PE programs for the period of 2009 to 2015 and would be recovered over thatsix-year period. Maryland law only allows for the utility to recover lost distribution revenue attributable to the energy efficiency or demand reduction programs through a base rate case proceeding, and to date such recovery has not been sought or obtained by PE. Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, PE's plans for additional and improved programs for the period 2012-2014 were filed on August 31, 2011. The MDPSC held hearings on PE and the other utilities' plans in October 2011, and on December 22, 2011, issued an order approving PE's plan with various modifications and follow-up assignments.

Pursuant to a bill passed by the Maryland legislature, the MDPSC proposed rules, based on the product of a working group of utilities, regulators, and other interested stakeholders, that create specific requirements related to a utility's obligation to address service interruptions, downed wire response, customer communication, vegetation management, equipment inspection, and annual reporting. The bill requires that the MDPSC 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 required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day per violation.Further comments were filed regarding the proposed rules on March 26, 2012, and at a hearing on April 17, 2012, the MDPSC approved re-publication of the rules as final.

NEW JERSEY

JCP&L currently provides BGS for retail customers that do not choose a third party electric generation supplier and for customers of third party electric generation suppliers, that fail to provide the contracted service. The supply for BGS, which is comprised of two components, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component and auction, reflecting hourly real time energy prices, is available for larger commercial and industrial customers. The other BGS component and auction, providing a fixed price service, is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. The most recent BGS auction results, for supply commencing June 1, 2012, were approved by the NJBPU on February 9, 2012.

On September 8, 2011, the Division of Rate Counsel filed a Petition with the NJBPU asserting that it has reason to believe that JCP&L is earning an unreasonable return on its New Jersey jurisdictional rate base. The Division of Rate Counsel requested that the NJBPU order JCP&L to file a base rate case petition so that the NJBPU may determine whether JCP&L's current rates for electric service are just and reasonable. JCP&L filed an answer to the Petition stating, inter alia, that the Division of Rate Counsel analysis upon which it premises its Petition contains errors and inaccuracies, that JCP&L's achieved return on equity is currently within a reasonable range, and that there is no reason for the NJBPU to require JCP&L to file a base rate case at this time. On November 30, 2011, the NJBPU ordered that the matter be assigned to the NJBPU President to act as presiding officer to, among other things, set and modify the schedule, decide upon motions, and otherwise control the conduct of this case, subject to subsequent NJBPU ratification.The schedule in the proceeding provides for briefs to be filed by the parties, the initial brief was filed by the parties on April 26, 2012. A decision is expected to be issued in June 2012. JCP&L is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held to solicit comments regarding the state of preparedness and responsiveness of the EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011. Additionally, the NJBPU accepted written comments through October 31, 2011 related to this inquiry. On December 14, 2011, the NJBPU Staff filed a report of its preliminary findings and recommendations with respect to the electric utility companies' planning and response to Hurricane Irene and the October 2011 snowstorm. The NJBPU selected a consultant to further review and evaluate the New Jersey EDCs' preparation and restoration efforts with respect to Hurricane Irene and the October 2011 snowstorm, and the report of the consultant is due to be submitted to the NJBPU in July 2012.The NJBPU has not indicated what additional action, if any, may be taken as a result of information obtained through this process.

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;

• a load cap of no less than80%, so that no single supplier is awarded more than80%of the tranches, which also applies to tranches assigned post-auction;

• a6%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, 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, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 milliondependent 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.

The Ohio Companies filed an application with the PUCO to essentially extend their current ESP for two more years. The Ohio Companies requested PUCO approval by May 2, 2012, so that they may bid megawatts of PJM-qualified energy efficiency and demand response resources into the May 7, 2012, PJM capacity auction for the 2015-2016 planning year or in the alternate by June 20, 2012, which would allow adequate time to implement changes to the bidding schedule to capture a greater amount of generation at historically lower prices for the benefit of customers. The PUCO has set an evidentiary hearing for May 21, 2012; therefore approval by May 2, 2012, is not expected.

As proposed, the extended ESP would maintain the substantial benefits from the current ESP including:

• Freezing current base distribution rates through May 31, 2016;

• Continuing to provide economic development and assistance to low-income customers for the two-year extension period at the levels established in the existing ESP;

• Providing Percentage of Income Payment Plan customers with a 6 percent generation rate discount;

• Continuing to provide capacity to shopping and non-shopping customers at a market-based price set through an auction process; and

• Continuing Rider DCR that allows continued investment in the distribution system for the benefit of customers.

As proposed, the extended ESP would provide additional new benefits, including:

• Securing generation supply over a longer period of time to mitigate any potential price spikes for FirstEnergy Ohio utility customers who do not switch to a competitive generation supplier; and

• Extending the recovery period for costs associated with purchasing renewable energy credits mandated by SB 221 through the end of the new ESP period. This will reduce the monthly renewable energy charge for all FirstEnergy Ohio utility customers.

The filing is supported by19parties including: Industrial Energy Users, Ohio Energy Group, PUCO Staff, the City of Akron, Ohio Manufacturers Association, Ohio Partners for Affordable Energy, and the Council of Smaller Enterprises (COSE).

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately166,000MWH in 2009,290,000MWH in 2010,410,000MWH in 2011,470,000MWH in 2012 and530,000MWH in 2013, with additional savings required through 2025. Utilities were also required to reduce peak demand in 2009 by1%, with an additional0.75% reduction each year thereafter through 2018.

In December 2009, the Ohio Companies filed theirthree-year portfolio plan, as required by SB221, seeking approval for the programs they intend to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. The PUCO issued an Opinion and Order generally approving the Ohio Companies'three-year plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies are in the process of implementing those programs included in the plan, and requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks. On May 19, 2011, the PUCO granted the request to reduce the 2010 energy efficiency and peak demand reductions to the level achieved in 2010 for OE, while finding that the issue was moot for CEI and TE. The Ohio Companies filed an application for rehearing, which was later denied. Failure to comply with the benchmarks or to obtain such an amendment may subject the Ohio Companies to an assessment of a penalty by the PUCO. Applications for Rehearing were filed by the Ohio Companies, Ohio Energy Group and Nucor Steel Marion, Inc. on April 22, 2011, regarding portions of the PUCO's decision related to the Ohio Companies'threeyear portfolio plan, including the method for calculating savings and certain changes made by the PUCO to specific programs. The PUCO denied those applications for rehearing, and in that entry included a new standard for compliance with the statutory energy efficiency benchmarks by requiring electric distribution companies to offer “all available cost effective energy efficiency opportunities” regardless of their level of compliance with the benchmarks as set forth in the statute. The Ohio Companies, the Industrial Energy Users - Ohio, and the Ohio Energy Group filed applications for rehearing, arguing that the PUCO's new standard is unlawful. The Ohio Companies also asked the PUCO to withdraw its amendment of CEI's and TE's 2010 energy efficiency benchmarks. The PUCO did not rule on the Applications for Rehearing within thirty days, thus denying them by operation of law. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, challenging the PUCO's new standard. On March 2, 2012, the PUCO moved to dismiss the Companies' appeal. The Companies filed their Memorandum in Opposition to the PUCO's Motion, along with their merit brief on March 9, 2012. The PUCO filed its brief on April 27, 2012. The Company now has twenty days to file its reply brief. Oral arguments have not yet been scheduled.

Additionally, under SB221, electric utilities and electric service companies are required to serve part of their load in 2011 from renewable energy resources equivalent to1.00%of the average of the KWH they served in 2008-2010; in 2012 from renewable energy resources equivalent to1.50%of the average of the KWH they served in 2009-2011; and in 2013 from renewable energy resources equivalent to2.00%of the average of the KWH they served in 2010-2012. In August and October 2009, the Ohio Companies conducted RFPs to secure RECs. The RECs acquired through thesetwoRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conducted two RFP processes to obtain RECs to meet the statutory benchmarks for 2011 and beyond. On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider. The PUCO selected auditors to perform a financial and a management audit, and final audit reports are currently scheduled to be filed with the PUCO by May 15, 2012. In March 2012, the Ohio Companies conducted an RFP process to obtain SRECs to help meet the statutory benchmarks for 2012 and beyond. With the successful completion of this RFP, the Ohio Companies have achieved their in-state solar compliance requirements for 2012.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative electric generation supplier or for customers of alternative electric generation suppliers that fail to provide the contracted service. The default service supply is currently provided by wholesale suppliers through a mix of long-term and short-term contracts procured through descending clock auctions, competitive requests for proposals and spot market purchases. On November 17, 2011, ME, PN, Penn and WP filed a Joint Petition for Approval of their DSP that will provide the method by which the Pennsylvania Companies will procure the supply for their default service obligations for the period June 1, 2013 through May 31, 2015. A final order must be entered by the PPUC by August 17, 2012.

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, and directed ME and PN to submit a new tariff or tariff supplement reflecting the removal of marginal transmission losses from the TSC. Pursuant to a plan approved by the PPUC, ME and PN began to refund those amounts to customers in January 2011, and the refunds are continuing over a 29 month period until the full amounts previously recovered for marginal transmission losses are refunded. In April 2010, ME and PN 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 millionin marginal transmission losses and associated carrying charges for the period prior to January 1, 2011, are not recoverable under ME and PN TSC riders. ME and PN filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court and also a complaint seeking relief in the U.S. District Court for the Eastern District of Pennsylvania, which was subsequently amended. The PPUC filed a Motion to Dismiss ME and PN Amended Complaint on September 15, 2011 to which ME and PN responded and which remains pending.On February 28, 2012, the Supreme Court of Pennsylvania denied the Petition for Allowance of Appeal.

In each of May 2008, 2009 and 2010, the PPUC approved ME's and PN'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 transmission 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 ME's customers to provide for full recovery by December 31, 2010. Although the ultimate outcome of this matter cannot be determined at this time, ME and PN believe that they should ultimately prevail through the judicial process and therefore expect to fully recover the approximately$254 millionin marginal transmission losses for the period prior to January 1, 2011.

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 (EE&C Plan) by July 1, 2009, setting forth the utilities' plans to reduce energy consumption by a minimum of1%and3%by May 31, 2011 and May 31, 2013, respectively, and to reduce peak demand by a minimum of4.5%by May 31, 2013. Act 129 provides for potentially significant financial penalties to be assessed upon utilities that fail to achieve the required reductions in consumption and peak demand. The Pennsylvania Companies submitted a final report on November 15, 2011, in which they reported on their compliance with statutory May 31, 2011, energy efficiency benchmarks. ME, PN and Penn achieved the 2011 benchmarks; however WP has been unable to provide final results because several customers are still accumulating necessary documentation for projects that may qualify for inclusion in the final results. Preliminary numbers indicate that WP did not achieve its 2011 benchmark and it is not known at this time whether WP will be subject to a fine for failure to achieve the benchmark. WP is unable to predict the outcome of this matter or estimate any possible loss or range of loss.

On August 9, 2011, WP filed a petition to approve its Second Amended EE&C Plan. The proposed Second Revised Plan includes measures and a new program and implementation strategies consistent with the successful EE&C programs of ME, PN and Penn that are designed to enable WP to achieve the post-2011 Act 129 EE&C requirements. On January 6, 2012, a Joint Petition for Settlement of all issues was filed by the parties to the proceeding, and the ALJ's Recommended Decision was issued on April 19, 2012, recommending that the Joint Settlement be adopted as filed.

In addition, Act 129 required utilities to file a SMIP with the PPUC. 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 its previously approved smart meter deployment plan and certain smart meter dependent aspects of the EE&C Plan. WP proposed to decelerate its previously contemplated smart meter deployment schedule and to target the installation of approximately25,000smart meters in support of its EE&C Plan, based on customer requests, by mid-2012. WP also proposed to take advantage of the30-month grace period authorized by the PPUC to continue WP's efforts to re-evaluate full-scale smart meter deployment plans. 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. A joint settlement with all parties based on these terms, with one party retaining the ability to challenge the recovery of amounts spent on WP's original smart meter implementation plan, was approved by the PPUC on June 30, 2011. 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 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 concerning retail markets in Pennsylvania to investigate both intermediate and long term plans that could be adopted to further foster the competitive markets, and to explore the future of default service in Pennsylvania following the expiration of the upcoming DSPs on May 31, 2015. Following the issuance of a Tentative Order and comments filed by numerous parties, the PPUC entered a final order on December 16, 2011, providing recommendations for components to be included in upcoming DSPs, including: the duration of the programs and the length of associated energy contracts; a customer referral program; a retail opt-in auction; time-of-use rate options provided through contracts with electric generation suppliers; and periodic rate adjustments.Following the issuance of a Tentative Order and comments filed by various parties, the PPUC entered a final order on March 2, 2012 outlining an intermediate work plan. Several suggested models for long-range default service have been presented and were the topic of a March 2012 en banc hearing. It is expected that a tentative order will be issued for comment with a final long-range proposal.

The PPUC issued a Proposed Rulemaking Order on August 25, 2011, which proposed a number of substantial modifications to the current Code of Conduct regulations that were promulgated to provide competitive safeguards to the competitive retail electric market in Pennsylvania. The proposed changes include, but are not limited to: an EGS may not have the same or substantially similar name as the EDC or its corporate parent; EDCs and EGSs would not be permitted to share office space and would need to occupy different buildings; EDCs and affiliated EGSs could not share employees or services, except certain corporate support, emergency, or tariff services (the definition of "corporate support services" excludes items such as information systems, electronic data interchange, strategic management and planning, regulatory services, legal services, or commodities that have been included in regulated rates at less than market value); and an EGS must enter into a trademark agreement with the EDC before using its trademark or service mark. The Proposed Rulemaking Order was published on February 11, 2012, and comments were filed by ME, PN, Penn, WP and FES on March 27, 2012. If implemented these rules could require a significant change in the ways FES, ME, PN, Penn and WP do business in Pennsylvania, and could possibly have an adverse impact on their results of operations and financial condition.

WEST VIRGINIA

In April 2010, MP and PE filed with the WVPSC a Joint Stipulation and Agreement of Settlement reached with the other parties in a proceeding for an annual increase in retail rates that provided for:

• $40 millionannualized base rate increases effective June 29, 2010;

• Deferral of February 2010 storm restoration expenses over a maximumfive-year period;

• Additional$20 millionannualized base rate increase effective in January 2011;

• Decrease of$20 millionin ENEC rates effective January 2011, providing for deferral of related costs for later recovery in 2012; and

• 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 January 2011, MP and PE filed an application with the WVPSC seeking to certifythreefacilities as Qualified Energy Resource Facilities for purposes of compliance with their approved plan pursuant to AREPA. The application was approved and thethreefacilities are capable of generating renewable credits which will assist the companies in meeting their combined requirements under the AREPA. 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 andthreeNUG facilities in West Virginia. The City of New Martinsville and Morgantown Energy Associates, each the owner of one of the contracted resources, have participated in the case in opposition to the petition. The WVPSC issued an order granting ownership of all RECs produced by the facilities to MP. The WVPSC order was appealed, and the order was stayed pending the outcome of the appeal. Oral arguments were heard at the West Virginia Supreme Court on April 10, 2012. Should MP be unsuccessful in the appeal, it will have to procure the requisite RECs to comply with AREPA from other sources. MP expects to recover such costs from customers.

The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC. On April 24, 2012, the FERC ruled that the FERC-jurisdictional contracts are intended to pay only for electric energy and capacity (and not for RECs), and that state law controlled on the issues of determining which entity owns RECs and how they are transferred between entities. The FERC declined to act on the complaints and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court. MP is evaluating whether to seek rehearing of the FERC's order.

RELIABILITY MATTERS

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, FES, AE Supply, FGCO, FENOC, ATSI and TrAIL. The NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC 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 RFC.

FirstEnergy believes that it 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 RFC. Moreover, it is clear that the NERC, RFC 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. 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, 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.On March 22, 2012, NERC concluded the investigation of the matter and forwarded it to NCEA for further review. NCEA is currently evaluating the findings of the investigation. JCP&L is not able to predict what actions, if any, NERC may take with respect to this matter.

In 2011, RFC performed routine compliance audits of parts of FirstEnergy's bulk-power system and generally found the audited systems and processes to be in full compliance with all audited reliability standards. RFC will perform additional audits in 2012.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities - the matter is contentious because costs for facilities built in one transmission zone often are allocated to customers in other transmission zones. During recent years, the debate has focused on the question of the methodology for determining the transmission zones and customers who benefit from a given facility and, if so, whether the methodology can determine the pro rata share of each zone's benefit. While FirstEnergy and other parties argue for a traditional "beneficiary pays" approach, others advocate for “socializing” the costs on a load-ratio share basis - each customer in the zone would pay based on its total usage of energy within PJM. This debate is framed by regulatory and court decisions.In 2007, the U.S. Court of Appeals for the Seventh Circuit found that FERC had not supported a prior FERC decision to allocate costs for new500kV and higher voltage facilities on a load ratio share basis and, based on that finding, remanded the rate design issue to FERC. In an order dated January 21, 2010, FERC set this matter for a “paper hearing” and requested parties to submit written comments. FERC identifiednineseparate issues for comment and directed PJM to file the first round of comments. PJM filed certain studies with FERC on April 13, 2010, which demonstrated that allocation of the cost of high voltage transmission facilities on a beneficiary pays basis results in certain load serving entities in PJM bearing the majority of the costs. Subsequently, 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 utility commissions supported the use of the beneficiary pays approach for cost allocation for high voltage transmission facilities. Other utilities and state utility commissions supported continued socialization of these costs on a load ratio share basis.On March 30, 2012, FERC issued an order on remand reaffirming its prior decision that costs for new transmission facilities that are rated at500kV 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 and concluding that such methodology is just and reasonable and not unduly discriminatory or preferential. On April 30, 2012, FirstEnergy requested rehearing of FERC's March 30, 2012 order.

RTO Realignment

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to 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. While most of the matters involved with the move have been resolved, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed; the details of which dispute are discussed below in the "MISO Multi-Value Project Rule Proposal." In addition, FERC denied certain exit fees of ATSI's transmission rate until such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move. ATSI has asked for rehearing of FERC's orders that address the Michigan Thumb transmission project, and the exit fee issue.

ATSI's filings and requests for rehearing on these matters, as well as the pleadings submitted by parties that oppose ATSI's position are currently pending before FERC. Finally, a negotiated agreement that requires ATSI to pay a one-time charge of$1.8 millionfor long term firm transmission rights that - according to the MISO - were payable upon ATSI's exit, is pending before FERC.

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 (not including ATSI or First Energy) jointly filed with FERC a 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 the MISO's MTEP process. Under MISO's proposal, the costs of “Michigan Thumb” MVP projects that were 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 and charged to ATSI. MISO estimated that approximately$15 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction.

FirstEnergy has filed pleadings in opposition to the MISO's efforts to “socialize” the costs of the Michigan Thumb Project onto ATSI or onto ATSI's customers that assert legal, factual and policy arguments.To date, FERC has responded in a series of orders that require ATSI to absorb the charges for the Michigan Thumb Project.

On October 31, 2011, FirstEnergy filed a Petition of Review of certain of the FERC's orders with the U.S. Court of Appeals for the D.C. Circuit. Other parties also filed appeals of those orders and, in November 2011, the cases were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit.

On February 27, 2012, FERC issued its most recent order (February 2012 Order) regarding the Michigan Thumb Project, in which FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI. MISO's Schedule 39 tariff is the vehicle through which the MISO plans to charge the Michigan Thumb project costs to ATSI.In the February 2012 Order, FERC directed that settlement negotiations occur. On March 28, 2012, FirstEnergy filed for clarification and rehearing of the February 2012 Order, and such request is pending before the FERC.

FirstEnergy cannot predict the outcome of these proceedings or estimate the possible loss or range of loss.

PJM Underfunding FTR Complaint

On December 28, 2011, FES and AE Supply filed a complaint with FERC against PJM challenging the ongoing underfunding of FTR contracts, which exist to hedge against transmission congestion in the day-ahead markets. The underfunding is a result of PJM's practice of using the funds that are intended to pay the holders of FTR contracts to pay instead for congestion costs that occur in the real time markets. Underfunding of the FTR contracts resulted in losses of approximately$35 millionto FES and AE Supply in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year, through March 31, 2012, are estimated to be approximately$6 million.

On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue. Many parties also filed comments supporting FES' and AE Supply's position. Other parties, generally representatives of end-use customers who will have to pay the charges, filed in opposition to the complaint. On March 2, 2012, FERC dismissed the complaint without prejudice, pending PJM's publication for stakeholder review and discussion, a report on the causes of the FTR underfunding and potential improvements, including modeling, which could be made to minimize the revenue inadequacy. On March 30, 2012, FES and AE Supply requested rehearing and reconsideration of the March 2, 2012 order, arguing that FERC erred in dismissing the complaint because the root cause of the FTR underfunding is irrelevant to the relief requested in the complaint. That request remains pending before FERC.

FTR Allocation Complaint

On March 26, 2012, FES and AE Supply filed a complaint with FERC against PJM challenging PJM's FTR allocation rules. PJM allocates FTRs to load-serving entities in an annual allocation process, up to each LSE's peak load, based on the expected transmission capability for the upcoming planning year. If a transmission facility is scheduled to be out of service for a significant part of the year, it can result in LSEs' FTR allocations being reduced in the annual allocation. When these transmission facilities return to service during the year PJM will create monthly FTRs to reflect the increased transmission capability during that month. However, instead of allocating these new monthly FTRs to the LSEs that were unable to obtain their full allocation of FTRs in the annual allocation process, PJM's rules instead require PJM to auction off these new monthly FTRs in the market. The complaint seeks a change to the PJM rules such that the new FTRs created each month by transmission lines returning to service would first be allocated to those LSEs that were denied a full allocation of their FTR entitlement in the annual allocation process before they are auctioned off in the market. On April 16, 2012, PJM filed its answer to the complaint. Also, on that date, Exelon Corporation filed a protest to, and several parties filed comments on, FES' and AE Supply's complaint, which remains pending before FERC. On April 30, 2012, FES and AE Supply filed a motion for leave to answer and answer to the various pleadings filed on April 16, 2012.

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 CDWR during 2001. The settlement proposal claims that CDWR is owed approximately$190 millionfor 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 remandedoneof 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). 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. On June 3, 2011, the California parties requested rehearing of the May 4, 2011 order. The request for rehearing remains pending.

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. That request for rehearing also remains pending. FirstEnergy cannot predict the outcome of either of the above matters or estimate the possible loss or range of loss.

PATH Transmission Project

The PATH Project is comprised of a765kV 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 the WVPSC, the VSCC and MDPSC. Withdrawal was deemed effective upon filing the notice with the MDPSC. The WVPSC and VSCC have granted the motions to withdraw.

Yards Creek

The Yards Creek Pumped Storage Project is a400MW hydroelectric project located in Warren County, New Jersey. JCP&L owns an undivided50%interest in the project, and operates the project. PSEG Fossil, LLC, a subsidiary of Public Service Enterprise Group, owns the remaining interest in the plant. The project was constructed in the early 1960s, and became operational in 1965. FERC issued a license for authorization to operate the project. The existing license expires on February 28, 2013.

In February 2011, JCP&L and PSEG filed a joint application with FERC to renew the license for an additional forty years. The companies are pursuing relicensure through FERC's ILP. Under the ILP, FERC will assess the license applications, issue draft and final Environmental Assessments/Environmental Impact Studies (as required by NEPA), and provide opportunities for intervention and protests by affected third parties. FERC may hold hearings during the five-year ILP licensure process. FirstEnergy expects FERC to issue the new license before February 28, 2013. To the extent, however, that the license proceedings extend beyond the February 28, 2013 expiration date for the current license, the current license will be extended yearly as necessary to permit FERC to issue the new license.

Seneca

The Seneca Pumped Storage Project is a451MW 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 related documents in the license docket.

On November 30, 2010, the Seneca Nation filed its notice of intent to relicense and related documents necessary for the Seneca Nation 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.

On September 12, 2011, FirstEnergy and the Seneca Nation each filed “Revised Study Plan” documents. These documents describe the parties' respective proposals for the scope of the environmental studies that should be performed as part of the relicensing process. On October 11, 2011, FERC Staff issued a letter order that addressed the Revised Study Plans. In the order, FERC Staff approved FirstEnergy's Revised Study Plan, subject to a finding that the Project is located on “aboriginal lands” of the Seneca Nation. Based on this finding, FERC Staff directed FirstEnergy to consult with the Seneca Nation and other parties about the data set, methodology and modeling of the hydrological impacts of project operations.In March of 2012, FirstEnergy hosted a meeting as part of the consultation process. In that meeting, FirstEnergy reviewed its proposed methodology for conducting the hydrological impacts study and answered questions from third parties about the methodology. On April 11, 2012, the Seneca Nation and other parties filed comments on the proposed hydrologic impacts study.The study processes, including the discrete hydrological impacts study, will extend through approximately November 2013.

FirstEnergy cannot predict the outcome of this matter or estimate the possible loss or range of loss.

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Fair Value Measurements

3 Months Ended

Mar. 31, 2012

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

RECURRING AND NONRECURRING FAIR VALUE MEASUREMENTS

On January 1, 2012, FirstEnergy adopted an amendment to the authoritative accounting guidance regarding fair value measurements. The amendment was applied prospectively and expanded disclosure requirements for fair value measurements, particularly for Level 3 measurements, among other changes.

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 and a description of the valuation techniques for Level 2 and Level 3 are as follows:

Level 1	-	Quoted prices for identical instruments in active market
Level 2	-	Quoted prices for similar instruments in active market
	-	Quoted prices for identical or similar instruments in markets that are not active
	-	Model-derived valuations for which all significant inputs are observable market data

Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures.

Level 3 - Valuation inputs are unobservable and significant to the fair value measurement

FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast, which has been reviewed and approved by the Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs and NUGs are as follows.

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are subsequently adjusted to fair value using a mark-to-model methodology on a monthly basis, which approximates market. The primary inputs into the model, that are generally less observable from objective sources, are the most recent RTO auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement. See Note 7, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.

NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value using a mark-to-model methodology on a monthly basis, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Monthly pricing for the NUG contracts is a combination of market prices for the current year and next three years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on IntercontinentalExchange quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Generally, significant increases or decreases in inputs in isolation could result in a higher or lower fair value measurement.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2012 and December 31, 2011. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

Transfers between levels are recognized at the end of the reporting period. There were no significant transfers between levels during the 2012 and 2011 periods. The following tables set forth the recurring and nonrecurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy.

FE CONSOLIDATED
Recurring Fair Value Measurements	March 31, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,561		$	—		1,561			$	—	$	1,544		$	—		$	1,544
Derivative assets - commodity contracts	1			415			—			416			—		264			—			264
Derivative assets - FTRs	—			—			1			1			—		—			1			1
Derivative assets - NUG contracts(1)	—			—			42			42			—		—			56			56
Equity securities(2)	289			—			—			289			259		—			—			259
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			138			—			138			—		148			—			148
U.S. state debt securities	—			313			—			313			—		314			—			314
Other(3)	54			167			—			221			49		225			—			274
Total assets	344			2,594			43			2,981			308		2,498			57			2,863
Liabilities
Derivative liabilities - commodity contracts	(2		)	(347		)	—			(349		)	—		(247		)	—			(247		)
Derivative liabilities - FTRs	—			—			(15		)	(15		)	—		—			(23		)	(23		)
Derivative liabilities - NUG contracts(1)	—			—			(342		)	(342		)	—		—			(349		)	(349		)
Total liabilities	(2		)	(347		)	(357		)	(706		)	—		(247		)	(372		)	(619		)
Net assets (liabilities)(4)	$	342		$	2,247		$	(314	)	$	2,275		$	308	$	2,251		$	(315	)	$	2,244

⁽¹⁾  NUG contracts are generally subject to regulatory accounting and do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

⁽³⁾  Primarily consists of short-term cash investments.

⁽⁴⁾  Excludes $2 million and $(52) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with 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 the Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2012 and December 31, 2011:

	NUG Contracts									FTRs
	Derivative Assets(1)			Derivative Liabilities(1)			Net(1)			Derivative Assets(1)			Derivative Liabilities(1)			Net(1)
										(In millions)
January 1, 2011 Balance	$	122		$	(466	)	$	(344	)	$	—		$	—		$	—
Realized gain (loss)	—			—			—			—			—			—
Unrealized gain (loss)	(58		)	(144		)	(202		)	2			(27		)	(25		)
Purchases	—			—			—			13			(4		)	9
Issuances	—			—			—			—			—			—
Sales	—			—			—			—			—			—
Settlements	(7		)	261			254			(14		)	20			6
Transfers in (out) of Level 3	—			—			—						(12		)	(12		)
December 31, 2011 Balance	$	57		$	(349	)	$	(292	)	$	1		$	(23	)	$	(22	)
Realized gain (loss)	—			—			—			—			—			—
Unrealized gain (loss)	(14		)	(65		)	(79		)	—			(3		)	(3		)
Purchases	—			—			—			—			—			—
Issuances	—			—			—			—			—			—
Sales	—			—			—			—			—			—
Settlements	(1		)	72			71			—			11			11
Transfers in (out) of Level 3	—			—			—			—			—			—
March 31, 2012 Balance	$	42		$	(342	)	$	(300	)	$	1		$	(15	)	$	(14	)

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

Level 3 Quantitative Information

The following table provides quantitative information for NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	(14	)	Model	RTO auction clearing prices	($4.18) to $9.81	$	1.51	Dollars/MWH
NUG Contracts	$	(300	)	Model	Generation Power regional prices	500 to 6,809,000 $58.71 to $84.92	2,547,000 $66.77		MWH Dollars/MWH

FES
Recurring Fair Value Measurements	March 31, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,017		$	—		$	1,017		$	—	$	1,010		$	—		$	1,010
Derivative assets - commodity contracts	1			391			—			392			—		248			—			248
Derivative assets - FTRs	—			—			1			1			—		—			1			1
Equity securities(1)	150			—			—			150			124		—			—			124
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			5			—			5			—		7			—			7
U.S. state debt securities	—			—			—			—			—		5			—			5
Other(2)	—			66			—			66			—		132			—			132
Total assets	151			1,479			1			1,631			124		1,405			1			1,530
Liabilities
Derivative liabilities - commodity contracts	(2		)	(340		)	—			(342		)	—		(234		)	—			(234		)
Derivative liabilities - FTRs	—			—			(5		)	(5		)	—		—			(7		)	(7		)
Total liabilities	(2		)	(340		)	(5		)	(347		)	—		(234		)	(7		)	(241		)
Net assets (liabilities)(3)	$	149		$	1,139		$	(4	)	$	1,284		$	124	$	1,171		$	(6	)	$	1,289

⁽¹⁾  NDT funds hold equity portfolios whose performance of which is benchmarked against the Alerian MLP Index.

⁽²⁾  Primarily consists of short-term cash investments.

⁽³⁾  Excludes $2 million and $(58) million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, 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 FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2012 and December 31, 2011:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2011 Balance	$	—		$	—		$	—
Realized gain (loss)	—			—			—
Unrealized gain (loss)	4			(8		)	(4		)
Purchases	2			(1		)	1
Issuances	—			—			—
Sales	—			—			—
Settlements	(5		)	2			(3		)
Transfers in (out) of Level 3	—			—			—
December 31, 2011 Balance	$	1		$	(7	)	$	(6	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(1		)	(1		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			4			4
Transfers in (out) of Level 3	—			—			—
March 31, 2012 Balance	$	1		$	(4	)	$	(3	)

Level 3 Quantitative Information

The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	(3	)	Model	RTO auction clearing prices	($4.18) to $8.03	$	0.76	Dollars/MWH

OE
Recurring Fair Value Measurements	March 31, 2012								December 31, 2011
	Level 1		Level 2		Level 3		Total			Level 1		Level 2		Level 3		Total
Assets	(In millions)
Corporate debt securities	$	—	$	—	$	—	$	—		$	—	$	3	$	—	$	3
U.S. government debt securities	—		133		—		133			—		132		—		132
Other(1)	—		3		—		3			—		2		—		2
Total assets(2)	$	—	$	136	$	—	$	136		$	—	$	137	$	—	$	137

⁽¹⁾  Primarily consists of short-term cash investments.

⁽²⁾  Excludes $1 million as of March 31, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

JCP&L
Recurring Fair Value Measurements	March 31, 2012										December 31, 2011
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	148	$	—		$	148		$	—	$	144	$	—		$	144
Derivative assets - NUG contracts(1)	—		—		4			4			—		—		4			4
Equity securities(2)	31		—		—			31			30		—		—			30
U.S. government debt securities	—		—		—			—			—		2		—			2
U.S. state debt securities	—		225		—			225			—		219		—			219
Other(3)	—		16		—			16			—		15		—			15
Total assets	31		389		4			424			30		380		4			414
Liabilities
Derivative liabilities - NUG contracts(1)	—		—		(136		)	(136		)	—		—		(147		)	(147		)
Total liabilities	—		—		(136		)	(136		)	—		—		(147		)	(147		)
Net assets (liabilities)(4)	$	31	$	389	$	(132	)	$	288		$	30	$	380	$	(143	)	$	267

⁽¹⁾  NUG contracts are subject to regulatory accounting and do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

⁽³⁾  Primarily consists of short-term cash investments.

⁽⁴⁾  Excludes $2 million as of December 31, 2011 of receivables, payables, 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 for the periods ended March 31, 2012 and December 31, 2011:

	Derivative Asset NUG Contracts(1)			Derivative Liability NUG Contracts(1)			Net NUG Contracts(1)
	(In millions)
January 1, 2011 Balance	$	6		(233		)	(227		)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	(2		)	(11		)	(13		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			97			97
Transfers in (out) of Level 3	—			—			—
December 31, 2011	$	4		$	(147	)	$	(143	)
Realized gain (loss)	—			—			—
Unrealized gain (loss)	—			(6		)	(6		)
Purchases	—			—			—
Issuances	—			—			—
Sales	—			—			—
Settlements	—			17			17
Transfers in (out) of Level 3	—			—			—
March 31, 2012	$	4		$	(136	)	$	(132	)

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

Level 3 Quantitative Information

The following table provides quantitative information for NUG contracts held by JCP&L that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2012:

	Fair Value as of March 31, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
NUG Contracts	$	(132	)	Model	Generation Power regional prices	69,000 to 736,000 $58.71 to $84.92	157,000 $68.65	MWH Dollars/MWH

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 and available-for-sale securities.

FE and its subsidiaries 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, FE and its subsidiaries 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 and OE 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 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 NDT 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, OE and JCP&L hold debt and equity securities within their NDT, nuclear fuel disposal trusts and NUG trusts. These trust investments are considered available-for-sale securities at fair market value. FES, OE and JCP&L 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 March 31, 2012 and December 31, 2011:

	March 31, 2012(1)				December 31, 2011(2)
	Cost Basis	Unrealized Gains	Unrealized Losses	Fair Value	Cost Basis	Unrealized Gains		Unrealized Losses		Fair Value
	(In millions)
Debt securities
FE Consolidated	1,967	42	—	2,009	1,980	25	25	—	—	2,005
FES	1,001	21	—	1,022	1,012	13		—		1,025
OE	133	—	—	133	134	—		—		134
JCP&L	359	12	—	371	356	7		—		363
Equity securities
FE Consolidated	246	42	—	288	222	36		—		258
FES	127	23	—	150	104	20		—		124
JCP&L	27	4	—	31	27	3		—		30

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $160 million; FES - $68 million; OE - $4 million; JCP&L - $19 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $164 million; FES - $74 million; OE - $2 million; JCP&L - $19 million.

Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales and interest and dividend income for the three months ended March 31, 2012 and 2011 were as follows:

March 31, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	251	$	19	$	(17	)	$	15
FES	83		12		(11		)	7
OE	37		—		—			1
JCP&L	95		1		(1		)	4
March 31, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	969	$	100	$	(29	)	$	24
FES	216		12		(15		)	15
OE	8		—		—			1
JCP&L	217		22		(4		)	4

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains and approximate fair values of investments in held-to-maturity securities as of March 31, 2012 and December 31, 2011:

	March 31, 2012			December 31, 2011
	Cost Basis	Unrealized Gains	Fair Value	Cost Basis	Unrealized Gains	Fair Value
	(In millions)
Debt Securities
FE Consolidated	336	41	377	402	50	452
OE	162	19	181	163	21	184

Investments in emission allowances, employee benefit trusts and cost and equity method investments totaling $689 million as of March 31, 2012, and $693 million as of December 31, 2011, are excluded from the amounts reported above.

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, excluding capital lease obligations and net unamortized premiums and discounts, as of March 31, 2012 and December 31, 2011:

	March 31, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FE Consolidated	$	17,130	$	19,321	$	17,165	$	19,320
FES	3,674		3,944		3,675		3,931
OE	1,158		1,469		1,157		1,434
JCP&L	1,770		2,071		1,777		2,080

The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy and its subsidiaries listed above. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of March 31, 2012 and December 31, 2011.

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Derivative Instruments

3 Months Ended

Mar. 31, 2012

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

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 Risk Policy 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.

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 qualified and were designated as cash flow hedge instruments are recorded in AOCI. 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 these 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 a derivative contract are reported as a component of AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

In February 2011, FirstEnergy elected to dedesignate all outstanding cash flow hedge relationships, therefore, as of March 31, 2012 and December 31, 2011, there were no commodity derivative contracts designated in cash flow hedging relationships. Total net unamortized gains included in AOCI associated with dedesignated cash flow hedges totaled $14 million and $19 million as of March 31, 2012 and December 31, 2011, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Reclassifications from AOCI into other operating expenses were $5 million of income and $5 million of loss during the three months ended March 31, 2012 and 2011, respectively. Approximately $7 million is expected to be amortized to income 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 March 31, 2012, no forward starting swap agreements were outstanding. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $77 million as of March 31, 2012. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months. Reclassifications from AOCI into interest expense totaled $2 million and $3 million during the three months ended March 31, 2012 and 2011, respectively.

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 March 31, 2012, 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 $96 million as of March 31, 2012. Based on current estimates, approximately $23 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 $5 million during the three months ended March 31, 2012 and 2011, 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 for use 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.

As of March 31, 2012, FirstEnergy’s net asset position under commodity derivative contracts was $66 million, which related to FES and AE Supply positions. Under these commodity derivative contracts, FES posted $44 million and AE Supply posted $1 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $16 million and AE Supply to post $3 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on commodity derivative contracts held as of March 31, 2012, an adverse 10% change in commodity prices would decrease net income by approximately $2 million 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 on FirstEnergy’s Consolidated Balance Sheets:

Derivatives not designated as hedging instruments:
Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	March 31, 2012		December 31, 2011			March 31, 2012			December 31, 2011
	(In millions)					(In millions)
Power Contracts					Power Contracts
Current Assets	$	300	$	185	Current Liabilities	$	(282	)	$	(196	)
Noncurrent Assets	115		79		Noncurrent Liabilities	(66		)	(51		)
FTRs					FTRs
Current Assets	1		1		Current Liabilities	(15		)	(22		)
Noncurrent Assets	—		—		Noncurrent Liabilities	—			(1		)
NUGs	42		56		NUGs	(342		)	(349		)
Other					Other
Current Assets	1		—		Current Liabilities	(2		)	—
Noncurrent Assets	—		—		Noncurrent Liabilities	—			—
Total Derivatives Assets	$	459	$	321	Total Derivatives Liabilities	$	(707	)	$	(619	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2012:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	33	47	(14	)	MWH
FTRs	17	—	17		MWH
NUGs	23	—	23		MWH
Natural Gas Futures	11	—	11		Million British Thermal Units

The effect of derivative instruments on the Consolidated Statements of Income during the three months ended March 31, 2012 and 2011, are summarized in the following tables:

	Three Months Ended March 31
	Power Contracts			FTRs			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(5	)	$	—		$	—		$	(5	)
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(9	)	$	—		$	—		$	(9	)
Effective Gain (Loss) Reclassified to:
Purchased Power Expense	16			—			—			16
Revenues	(12		)	—			—			(12		)
Fuel Expense	—			—			—			—
Derivatives Not in a Hedging Relationship
2012
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	—		$	—		$	—		$	—
Other Operating Expense	55			5			(2		)	58
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(117		)	—			—			(117		)
Revenues	112			6			—			118
Other Operating Expense	—			(24		)	—			(24		)
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	29		$	—		$	—		$	29
Other Operating Expense	(20		)	1			1			(18		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	(37		)	—			—			(37		)
Revenue	10			3			(1		)	12
Other Operating Expense	—			(15		)	—			(15		)

The unrealized and realized gains (losses) on FirstEnergy’s NUG contracts and regulated FTRs not in a hedging relationship for the three months ended March 31, 2012 were ($7) million and $3 million, respectively. The unrealized and realized gains (losses) on FirstEnergy’s NUG contracts and other derivative contracts not in a hedging relationship for the three months ended March 31, 2011 were ($17) million and ($10) million, respectively. These unrealized and realized gains (losses) on NUG contracts and regulated FTRs are subject to regulatory accounting and do not impact earnings.

The following table provides a reconciliation of changes in the fair value of certain contracts that are deferred for future recovery from (or credit to) customers during the three months ended March 31, 2012 and 2011:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2012	$	(293	)	$	(8	)	$	(301	)
Additions/Change in value of existing contracts	(79		)	(1		)	(80		)
Settled contracts	72			4			76
Outstanding net asset (liability) as of March 31, 2012	$	(300	)	$	(5	)	$	(305	)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	10		$	(335	)
Additions/Change in value of existing contracts	(89		)	—			(89		)
Settled contracts	72			(10		)	62
Outstanding net asset (liability) as of March 31, 2011	$	(362	)	$	—		$	(362	)

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

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Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2012

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

COMMITMENTS, GUARANTEES AND CONTINGENCIES

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. 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 credit support to various providers for the financing or refinancing by subsidiaries of costs related to the acquisition of property, plant and equipment. These agreements include provisions for parent guarantees, surety bonds and/or LOCs to be issued by FirstEnergy on behalf of one or more of its subsidiaries. Additionally, certain contracts may contain collateral provisions that are contingent upon either FirstEnergy's or its subsidiaries’ credit ratings.

As of March 31, 2012, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting of parental guarantees ($0.9 billion), subsidiaries' guarantees ($2.5 billion), and other guarantees ($0.7 billion).

Most of FirstEnergy’s surety bonds are backed by various indemnities common within the insurance industry. Surety bonds and related guarantees of $151 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.

While the types of guarantees discussed above are normally parental commitments for the future payment of subsidiary obligations, subsequent to the occurrence of a senior unsecured credit rating downgrade to below S&P's BBB- and Moody's Baa3 and lower, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of the subsidiary. As of March 31, 2012, FirstEnergy’s exposure to additional credit contingent contractual obligations was $671 million, as shown below:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Credit rating downgrade to below investment grade (1)	$	439	$	8	$	59	$	506
Material adverse event (2)	91		60		14		165
Total	$	530	$	68	$	73	$	671

⁽¹⁾  Includes $222 million and $40 million that are also considered accelerations of payment or funding obligations for FES and the Utilities, respectively.

⁽²⁾  Includes $42 million that is also considered an acceleration of payment or funding obligation for FES.

Certain bilateral non-affiliate contracts entered into by the Competitive Energy Services segment contain margining provisions that require posting of collateral. Based on FES' and AE Supply's power portfolio exposures as of March 31, 2012, FES and AE Supply have posted collateral of $84 million and $1 million, respectively. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

Not included in the preceding information is potential collateral arising from the PSAs between FES or AE Supply and affiliated utilities in the Regulated Distribution Segment. As of March 31, 2012, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post $54 million and $18 million, respectively.

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 originally shared ownership in the borrowers with FEV, have provided a guaranty of the borrowers' obligations under the facility. Following the sale of a portion of FEV's ownership interest in Signal Peak and Global Rail in the fourth quarter of 2011, FirstEnergy, WMB Loan Ventures, LLC and WMB Loan Ventures II, LLC, together with Global Mining Group, LLC and Global Holding, continue to guarantee the borrowers' obligations until either the facility is replaced with non-recourse financing (no later than June 30, 2012) or replaced with appropriate recourse financing no earlier than September 4, 2012, that provides for separate guarantees from each owner in proportion with each equity owner's percentage ownership in the joint venture. In addition, FEV, Global Mining Group, LLC and Global Holding, the entities that own direct and indirect equity interests in the borrowers, have pledged those interests to the lenders under the current facility as collateral. In March 2012, after an evaluation of its current operations, business plan and market conditions, the Global Rail Board of Managers opted to focus first on extending its current senior secured term loan facility due in October 2012, before replacing that facility with non-recourse financing. There can be no assurance that the term loan facility will be extended on satisfactory terms or at all.

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 SO₂and NOx emissions regulations under the CAA. FirstEnergy complies with SO₂and 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 or non-emitting plants and/or using emission allowances.

In July 2008,threecomplaints representing multiple plaintiffs were filed against FGCO in the U.S. District Court for the Western District of Pennsylvania seeking damages based on air emissions from the coal-fired Bruce Mansfield Plant.Twoof these complaints also seek to enjoin the Bruce Mansfield Plant from operating except in a “safe, responsible, prudent and proper manner.” One complaint was filed on behalf oftwenty-oneindividuals and the other is a class action complaint seeking certification as a class with theeightnamed plaintiffs as the class representatives. FGCO believes the claims are without merit and intends to defend itself against the allegations made in these complaints.

In December 2007, the states of New Jersey and Connecticut filed CAA citizen suits in the U.S. District Court for the Eastern District of Pennsylvania alleging NSR violations at the coal-fired 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 ME in 1999) and ME. 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. The Court dismissed New Jersey's and Connecticut's claims for injunctive relief against ME, but denied ME's motion to dismiss the claims for civil penalties. The parties dispute the scope of ME's indemnity obligation to and from Sithe Energy. In February 2012, GenOn announced its plans to retire the Portland Station in January 2015 citing EPA emissions limits and compliance schedules to reduce SO₂air emissions by approximately81%at the Portland Station by January 6, 2015. FirstEnergy is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In January 2009, the EPA issued a NOV to GenOn Energy, Inc. alleging NSR violations at the coal-fired Portland Generation Station based on “modifications” dating back to 1986. The NOV also alleged NSR violations at the Keystone and Shawville coal-fired plants based on “modifications” dating back to 1984. ME, JCP&L and PN, as former owners of the facilities, are unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In January 2011, the U.S. DOJ filed a complaint against PN in the U.S. District Court for the Western District of Pennsylvania seeking injunctive relief against PN based on alleged “modifications” at the coal-fired Homer City generating plant 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, NYSEG, and various current owners of Homer City, including EME Homer City Generation L.P. and affiliated companies, including Edison International. 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. In October 2011, the Court dismissed all of the claims with prejudice of the U.S. and the Commonwealth of Pennsylvania and the states of New Jersey and New York against all of the defendants, including PN. In December 2011, the U.S., the Commonwealth of Pennsylvania and the states of New Jersey and New York all filed notices appealing to the Third Circuit Court of Appeals. PN believes the claims are without merit and intends to defend itself against the allegations made in these complaints, but, at this time, is unable to predict the outcome of this matter or estimate the loss or possible range of loss. The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.

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 during maintenance outages dating back to 1990 triggered the pre-construction permitting requirements under the PSD and NNSR programs. 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. FGCO intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the possible loss or range of loss.

In August 2000, AE received an information request pursuant to section 114(a) of the CAA from the EPA requesting that it provide information and documentation relevant to the operation and maintenance of the followingtencoal-fired plants, which collectively include22electric generation units: Albright, Armstrong, Fort Martin, Harrison, Hatfield's Ferry, Mitchell, Pleasants, Rivesville, R. Paul Smith and Willow Island to determine compliance with the NSR provisions under the CAA, which can require the installation of additional air emission control equipment when a major modification of an existing facility results in an increase in emissions. In September 2007, AE 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 coal-fired Hatfield's Ferry and Armstrong plants in Pennsylvania and the coal-fired Fort Martin and Willow Island plants in West Virginia. FirstEnergy intends to vigorously defend against these CAA matters, but cannot predict their outcomes or estimate the possible loss or range of loss.

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 U.S. District Court for the Western District of Pennsylvania alleging, among other things, that Allegheny performed major modifications in violation of the PSD provisions of the CAA and the Pennsylvania Air Pollution Control Act at the coal-fired Hatfield's Ferry, Armstrong and Mitchell Plants in Pennsylvania. A non-jury trial on liability only was held in September 2010. The parties are awaiting a decision from the District Court, but there is no deadline for that decision. FirstEnergy is unable to predict the outcome or estimate the possible loss or range of loss.

National Ambient Air Quality Standards

The EPA's CAIR requires reductions of NOx and SO₂emissions intwophases (2009/2010 and 2015), ultimately capping SO₂emissions in affected states to2.5 milliontons annually and NOx emissions to1.3 milliontons annually. In 2008, the U.S. Court of Appeals for the District of Columbia decided that CAIR violated the CAA but 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 decision. In July 2011, the EPA finalized CSAPR, to replace CAIR, requiring reductions of NOx and SO₂emissions intwophases (2012 and 2014), ultimately capping SO₂emissions in affected states to2.4 milliontons annually and NOx emissions to1.2 milliontons annually. CSAPR allows trading of NOx and SO₂emission allowances between power plants located in the same state and interstate trading of NOx and SO₂emission allowances with some restrictions. On February 21, 2012, the EPA revised certain CASPR state budgets (for Florida, Louisiana, Michigan, Mississippi, Nebraska, New Jersey, New York, Texas, and Wisconsin and new unit set-asides in Arkansas and Texas), certain generating unit allocations (for some units in Alabama, Indiana, Kansas, Kentucky, Ohio and Tennessee) for NOx and SO₂emissions and delayed from 2012 to 2014 certain allowance penalties that could apply with respect to interstate trading of NOx and SO₂emission allowances. On December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit pending a decision on legal challenges argued before the Court on April 13, 2012. The Court ordered EPA to continue administration of CAIR until the Court resolves the CSAPR appeals. Depending on the outcome of these proceedings and how any final rules are ultimately implemented, FGCO's and AE Supply's future cost of compliance may be substantial and changes to FirstEnergy's operations may result.

Hazardous Air Pollutant Emissions

On December 21, 2011, the EPA finalized the MATS imposing emission limits for mercury, PM, and HCL for all existing and new coal-fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant. Under the CAA, state permitting authorities can grant an additional compliance year through April 2016, as needed, including instances when necessary to maintain reliability where electric generating units are being closed. In addition, an EPA enforcement policy document contemplates up to an additional year to achieve compliance, through April 2017, under certain circumstances for reliability critical units. On January 26, 2012 and February 8, 2012, FGCO, MP and AE Supply announced the retirement by September 1, 2012 (subject to a reliability review by PJM) ofninecoal-fired power plants (Albright, Armstrong, Ashtabula, Bay Shore except for generating unit 1, Eastlake, Lake Shore, R. Paul Smith, Rivesville and Willow Island) with a total capacity of3,349MW (generating, on average, approximatelytenpercent of the electricity produced by the companies over the past three years) due to MATS and other environmental regulations. Depending on how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS may be substantial and other changes to FirstEnergy's operations may result.

On March 8, 2012, FGCO filed an application for a feasibility study with PJM to install and interconnect to the transmission system approximately 800 megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant retirements and requested Reliability Must-Run arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18. During the three months ended March 31, 2012, FirstEnergy recognized pre-tax severance expense of approximately$7 million (including$4 million by FES) as a result of the closures.

On March 9, 2012, to assist the WVPSC with inquiries from public officials and the public, MP provided information to the WVPSC in the form of a closed entry filing in the ENEC case related to the plant deactivations. On April 2, 2012, the WVPSC issued an order requesting additional information from MP related to the Albright, Rivesville and Willow Island plant deactiviation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations. We anticipate deactivating these units by September 1, 2012.

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. 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 and report GHG emissions commencing in 2010. 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 NSR preconstruction permits would be required including an emissions applicability threshold of75,000tons per year of CO₂equivalents for existing facilities under the CAA's PSD program.

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 belowtwodegrees Celsius; includes a commitment by developed countries to provide funds, approaching$30 billionover three years with a goal of increasing to$100 billionby 2020; and establishes the “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. A December 2011 U.N. Climate Change Conference in Durban, Africa, established a negotiating process to develop a new post-2020 climate change protocol, called the “Durban Platform for Enhanced Action”. This negotiating process contemplates developed countries, as well as developing countries such as China, India, Brazil, and South Africa, to undertake legally binding commitments post-2020. In addition, certain countries agreed to extend the Kyoto Protocol for a second commitment period, commencing in 2013 and expiring in 2018 or 2020.

FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations. The CO₂emissions 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-CO₂emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA 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 CWA 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 CWA 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 CWA to reduce fish impingement to a12%annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities. On July 19, 2011, the EPA extended the public comment period for the new proposed Section 316(b) regulation by30days 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. 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 CWA 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. On February 1, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil liability claims for those petroleum spills to July 31, 2012. FGCO does not anticipate any losses resulting from this matter to be material.

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 coal-fired Hatfield's Ferry Plant. These criteria are reflected in the NPDES water discharge permit issued by PA DEP for that project. In January 2009, AE Supply appealed the PA DEP's permitting decision to the EHB, due to estimated costs in excess of$150 million in order to install technology to meet TDS and sulfate limits in the NPDES permit. Environmental Integrity Project and Citizens Coal Council also appealed the NPDES permit seeking to impose more stringent technology-based effluent limitations. In April 2012, a joint motion was filed by the parties informing the EHB of a proposed settlement and seeking the lifting of a portion of the EHB's stay of certain terms of the Hatfield's Ferry Plant's NPDES permit. The joint motion was granted by the EHB on April 27, 2012. The parties intend to memorialize the settlement in a Consent Decree to be lodged with the Commonwealth Court of Pennsylvania. The Consent Decree, if entered by the Commonwealth Court of Pennsylvania, will resolve the disputes concerning the Hatfield's Ferry Plant NPDES permit, including TDS and sulphate limits.

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 would apply only if the EPA has not promulgated TDS effluent limitation guidelines applicable to such units.

In December 2010, PA DEP submitted its CWA 303(d) list to the EPA with a recommended sulfate impairment designation for an approximately68mile 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 approximatelyfiveyears. Based on the stringency of the TMDL, FirstEnergy may incur significant costs to reduce sulfate discharges into the Monongahela River from the coal-fired Hatfield's Ferry and Mitchell Plants in Pennsylvania and the coal-fired Fort Martin Plant in West Virginia.

In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin Plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES 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 NPDES permit. MP has appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require 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, which technology may also meet certain of the other effluent limits. Additional technology may be needed to meet certain other limits in the Fort Martin NPDES permit. MP intends to vigorously pursue these issues but cannot predict the outcome of these appeals or estimate the possible loss or range of loss.

In May 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club filed a CWA citizen suit in the U.S. District Court for the Northern District of West Virginia alleging violations of arsenic limits in the NPDES water discharge permit for the fly ash impoundments at the Albright Station seeking unspecified civil penalties and injunctive relief. The MP filed an answer on July 11, 2011, and a motion to stay the proceedings on July 13, 2011. On January 3, 2012, the Court denied MP's motion to dismiss or stay the CWA citizen suit but without prejudice to re-filing in the future. In April 2012, the parties reached a settlement requiring MP to resolve these CWA citizen suit claims for an immaterial amount. If approved by the Court, a Consent Decree will be entered by the Court to resolve these claims. 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 a60-day Notice of Intent required prior to filing a citizen suit under the CWA for alleged failure to obtain a permit to construct the fly ash impoundments at the Albright Plant.

FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the possible loss or range of loss.

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 December 2009, in an advance 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 proposedtwooptions 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. The LBR CCB impoundment is expected to run out of disposal capacity for disposal of CCBs from the BMP between 2016 and 2018. BMP is pursuing several CCB disposal options.

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. Compliance with those regulations could have an adverse impact on FirstEnergy's results of operations and financial condition.

Certain of our utilities have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. 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 ofMarch 31, 2012, based on estimates of the total costs of cleanup, FE's and its subsidiaries' proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay.Total liabilities of approximately$106 million(including$70 millionapplicable to JCP&L) have been accrued throughMarch 31, 2012. Included in the total are accrued liabilities of approximately$63 millionfor 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.FirstEnergy or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the possible losses or range of losses cannot be determined or reasonably estimated at this time.

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofMarch 31, 2012, 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. FirstEnergy Corp. currently maintains a $95 millionparental guaranty in support of the decommissioning of nuclear facilities.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years, until 2037. By an order dated April 26, 2011, a NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners. The NRC subsequently narrowed the scope of admitted contentions in this proceeding to a challenge to the computer code used to model source terms in FENOC's Severe Accident Mitigation Alternatives analysis. On January 10, 2012, intervenors petitioned the ASLB for a new contention on the cracking of the Davis-Besse shield building discussed below.The ASLB scheduled a May 18, 2012, oral argument on the petitioner's request for a new contention, but has yet to rule on the admission of this contention.

On October 1, 2011, Davis-Besse was safely shut down for a scheduled outage to install a new reactor vessel head and complete other maintenance activities. The new reactor head, which replaced a head installed in 2002, enhances safety and reliability, and features control rod nozzles made of material less susceptible to cracking. On October 10, 2011, following opening of the building for installation of the new reactor head, a sub-surface hairline crack was identified in one of the exterior architectural elements on the shield building. These elements serve as architectural features and do not have structural significance. During investigation of the crack at the shield building opening, concrete samples and electronic testing found similar sub-surface hairline cracks in most of the building's architectural elements. FENOC's investigation also identified other indications. Included among them were sub-surface hairline cracks in the upper portion of the shield building (above elevation 780') and in the vicinity of the main steam line penetrations. A team of industry-recognized structural concrete experts and Davis-Besse engineers has determined these conditions do not affect the facility's structural integrity or safety.

On December 2, 2011, the NRC issued a CAL which concluded that FENOC provided "reasonable assurance that the shield building remains capable of performing its safety functions." The CAL imposed a number of commitments from FENOC including, submitting a root cause evaluation and corrective actions to the NRC by February 28, 2012, and further evaluations of the shield building. On February 27, 2012, FENOC sent the root cause evaluation to the NRC. Finally, the CAL also stated that the NRC was still evaluating whether the current condition of the shield building conforms to the plant's licensing basis. On December 6, 2011, the Davis-Besse plant returned to service.

By letter dated August 25, 2011, the NRC made a final significance determination (white) associated with a violation that occurred during the retraction of a source range monitor from the Perry reactor vessel. The NRC also placed Perry in the degraded cornerstone column (Column 3) of the NRC's Action Matrix governing the oversight of commercial nuclear reactors. As a result, the NRC staff will conduct several supplemental inspections, culminating in an inspection using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues are understood, the extent of condition has been identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.

On March 12, 2012, the NRC Staff issued orders requiring safety enhancements at U.S. reactors based on recommendations from the lessons learned Task Force review of the accident at Japan's Fukushima Daiichi nuclear power plant. These orders require additional mitigation strategies for beyond-design-basis external events, and enhanced equipment for monitoring water levels in spent fuel pools. The NRC also requested that licensees including FENOC: re-analyze earthquake and flooding risks using the latest information available; conduct earthquake and flooding hazard walkdowns at their nuclear plants; assess the ability of current communications systems and equipment to perform under a prolonged loss of onsite and offsite electrical power; and assess plant staffing levels needed to fill emergency positions. These and other NRC requirements adopted as a result of the accident at Fukushima Daiichi are likely to result in additional material costs from plant modifications and upgrades at FENOC's nuclear facilities.

On February 16, 2012, the NRC issued a request for information to the licensed operators of11nuclear power plants, including Beaver Valley Power Station Units 1 and 2, with respect to the modeling of fuel performance as it relates to "thermal conductivity degradation," which is the potential in higher burn up fuel for reduced capacity to transfer heat that could potentially change its performance during various accident scenarios, including loss of coolant accidents. The request for information indicated that this phenomenon has not been accounted for adequately in performance models for the fuel developed by the fuel manufacturer and that the NRC might consider imposing restrictions on reactor operating limits.On March 16, 2012, FENOC submitted its response to the NRC demonstrating that the NRC requirements are being met. FENOC also agreed to submit to the NRC revised large break loss of coolant accident analyses by December 15, 2016, that further consider the effects of fuel pellet thermal conductivity degradation.

ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against ICG, Anker WV, and 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 millionin damages for replacement coal purchased through the end of 2010 and will incur additional damages in excess of$150 millionfor 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 millionin future damages and$14 million for replacement coal / interest). On August 25, 2011, the Allegheny County Court denied all Motions for Post-Trial relief and the May 2, 2011 verdict became final. On August 26, 2011, ICG posted bond and filed a Notice of Appeal.Briefing on the Appeal is concluded with oral argument scheduled for May 16, 2012. AE Supply and MP intend to vigorously pursue this matter through appeal.

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 had been approved by the PUCO. In March 2010, the named-defendant companies filed a motion to dismiss the case due to the lack of jurisdiction. The court granted the motion to dismiss and the plaintiffs appealed the decision to the Court of Appeals of Ohio. The Court of Appeals affirmed the dismissal of the Complaint by the Court of Common Pleas on all counts except for one relating to an allegation of fraud which it remanded to the trial court. The Companies timely filed a notice of appeal with the Supreme Court of Ohio on December 5, 2011, challenging this one aspect of the Court of Appeals opinion. The Supreme Court of Ohio agreed to hear the appeal.

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 under Note 8, Regulatory Matters to the Combined Notes to the Consolidated Financial Statements.

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. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss and if such estimate can be made. If it were ultimately determined that FirstEnergy or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, 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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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,384
Discounted Lease Payments, net	1,179	[1]
Variable Interest Entities Net Exposure	205
OE
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	583
Discounted Lease Payments, net	426	[1]
Variable Interest Entities Net Exposure	157
Other First Energy Subsidiaries
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	643
Discounted Lease Payments, net	383	[1]
Variable Interest Entities Net Exposure	$ 260

[1] The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.6 billion.

XML

Commitments, Guarantees and Contingencies (Details Textuals) (USD $)	3 Months Ended							3 Months Ended			3 Months Ended			12 Months Ended	3 Months Ended		3 Months Ended		3 Months Ended		3 Months Ended						3 Months Ended					3 Months Ended
	Mar. 31, 2012	Dec. 31, 2011	Mar. 31, 2012 FES	Dec. 31, 2011 FES	Mar. 31, 2012 JCP&L	Dec. 31, 2011 JCP&L	Mar. 31, 2012 AE Supply	Mar. 31, 2012 Signal Peak and Global Rail	Mar. 31, 2012 FGCO	Dec. 31, 2011 FGCO	Mar. 31, 2012 CAIR phases	Mar. 31, 2012 CSAPR phases	Mar. 31, 2012 Clean Water Act	Dec. 31, 2010 Clean Water Act Miles	Mar. 31, 2012 Regulation of Waste Disposal options	Mar. 31, 2012 Regulation of Waste Disposal JCP&L	Mar. 31, 2012 Nuclear Plant Matters	Dec. 31, 2011 Nuclear Plant Matters	Mar. 31, 2012 ICG Litigation AE Supply	May 02, 2011 ICG Litigation AE Supply and MP	Mar. 31, 2012 Caa Compliance ElectricGenerationUnits CoalFiredPlants	Mar. 31, 2012 Caa Compliance FGCO Complaints plantiffs IndividualsInAComplaint	Mar. 31, 2012 National Ambient Air Quality Standards T	Mar. 31, 2012 Hazardous Air Pollutant Emissions MW	Mar. 31, 2012 Hazardous Air Pollutant Emissions FES	Mar. 08, 2012 Hazardous Air Pollutant Emissions FGCO MW	Mar. 31, 2012 Climate Change celsius	Jan. 02, 2011 Climate Change T	Mar. 31, 2012 Parental Guarantees	Mar. 31, 2012 Subsidiaries' Guarantees	Mar. 31, 2012 Other Guarantees	Mar. 31, 2012 Year 2020 Climate Change Increase in funding
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	$ 4,100,000,000																												$ 900,000,000	$ 2,500,000,000	$ 700,000,000
Surety bonds and related guarantees	151,000,000
Maximum exposure under collateral provisions	671,000,000		530,000,000				68,000,000
Company Posted Collateral Related To Net Liability Positions			84,000,000				1,000,000
Potential Collateral Posted Related to Net Liability Positions			54,000,000				18,000,000
Signal Peak and Global Rail entered into a syndicated two-year senior secured term loan facility								350,000,000
Senior Secured Term Loan Facility, Term, Years								2 years
Number of complaints filed against FGCO																						3
Number of complaints seek enjoin plant																						2
Number of individuals behalf of which complaint filed																						21
Number of named plaintiffs as class representatives																						8
Reduction in air emissions and compliance																					81.00%
Number of electric generation facilities																					10
Number of generation units																					22
Number of phases under the EPA’s CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides											2	2
Capping of SO2 emissions (In Tons)																							2,500,000
Capping of NOx emissions (In Tons)																							1,300,000
Capping of SO2 Emissions Under CSAPR																							2,400,000
Capping of NOx emissions under CSAPR																							1,200,000
Number of retired coal-fired plants being retired																								9
Megwatt Capacity for Retired Coal-Fired Power Plants																								3,349
Average percentage of power generation of retired coal-fired power plants																								10.00%
Measurement period for power generation of retired coal-fired power plants																								3 years
Megawatt capacity for proposed combusion turbine																										800
Pre-tax severance expense related to closures																								7,000,000	4,000,000
Upper threshold limit for carbon dioxide emission (Tons per Year)																												75,000
Increase (Decrease) in Global Temperature																											2
Funds provided for Copenhagen Green Climate Fund																											30,000,000,000					100,000,000,000
Annual percentage that fish impingement should be reduced to, per CWA													12.00%
Extension of comment period													30 days
Maximum Capital Investment Required To Install Technology To Meet Tds And Sulfate Limits													150,000,000
Portion of Monongahela River subject to CWA 303(d)														68
TMDL Limit Development Period													5 years
Number of days required prior to the filing of a citizen suit under notice													60 days
Options proposed by EPA for additional regulation of coal combustion residuals															2
Total environmental liabilities															106,000,000	70,000,000
Environmental Liabilities Former Gas Facilities															63,000,000
Decommissioning Fund Investments		2,112,000,000	1,240,000,000	1,223,000,000	195,000,000	193,000,000			0	0							2,135,000,000
Parental guarantee associated with the funding of decommissioning costs																	95,000,000
Request For Information from Number of Nuclear Power Plants, Total																		11
Renewal length of operating license for Davis-Besse Nuclear Power Station																	20 years
Loss incurred in damages for replacement coal purchased																			80,000,000
Additional damages incurred for future shortfalls																			150,000,000
Verdict in Favor																				104,000,000
Amount for which verdict entered for future damages																				90,000,000
Amount for replacement coal and interest																				$ 14,000,000
Commitment Period by Developed Countries to Provide Funds, Years	3 years
Potential MATS Extension Period																								1 year

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Pensions and Other Postemployment Benefits (Tables)

3 Months Ended

Mar. 31, 2012

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Costs

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2012			2011			2012			2011
	(In millions)
Service cost	$	40		$	29		$	3		$	3
Interest cost	97			84			12			11
Expected return on plan assets	(121		)	(102		)	(9		)	(10		)
Amortization of prior service cost	3			4			(51		)	(48		)
Other adjustments (settlements, curtailments, etc)	—			7			—			—
Net periodic costs (credits)	$	19		$	22		$	(45	)	$	(44	)

Components of Net Periodic Benefit Costs Allocated to subsidiaries

Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and its subsidiaries were as follows:

Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	13		$	20		$	(30	)	$	(32	)
FES	10			7			(8		)	(7		)
OE	(1		)	(2		)	(5		)	(6		)
JCP&L	(1		)	(2		)	(2		)	(3		)

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Supplemental Guarantor Information (Tables)

3 Months Ended

Mar. 31, 2012

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Statements of Income and Comprehensive Income

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,490		$	542		$	394		$	(910	)	$	1,516
OPERATING EXPENSES:
Fuel	—			240			55			—			295
Purchased power from affiliates	965			—			62			(910		)	117
Purchased power from non-affiliates	487			—			—			—			487
Other operating expenses	76			92			116			11			295
Provision for depreciation	1			30			34			(2		)	63
General taxes	20			10			7			—			37
Total operating expenses	1,549			372			274			(901		)	1,294
OPERATING INCOME (LOSS)	(59		)	170			120			(9		)	222
OTHER INCOME (EXPENSE):
Investment income	1			4			5			(4		)	6
Miscellaneous income, including net income from equity investees	258			—			—			(254		)	4
Interest expense — affiliates	(4		)	(1		)	(1		)	4			(2		)
Interest expense — other	(23		)	(26		)	(7		)	15			(41		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	232			(22		)	5			(239		)	(24		)
INCOME BEFORE INCOME TAXES	173			148			125			(248		)	198
INCOME TAXES (BENEFITS)	51			(1		)	23			3			76
NET INCOME	$	122		$	149		$	102		$	(251	)	$	122
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	122		$	149		$	102		$	(251	)	$	122
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized loss on derivative hedges	(5		)	—			—			—			(5		)
Change in unrealized gain on available for sale securities	10			—			10			(10		)	10
Other comprehensive income (loss)	—			(4		)	10			(6		)	—
Income taxes (benefits) on other comprehensive income (loss)	2			(2		)	4			(2		)	2
Other comprehensive income (loss), net of tax	(2		)	(2		)	6			(4		)	(2		)
COMPREHENSIVE INCOME	$	120		$	147		$	108		$	(255	)	$	120

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,366		$	743		$	469		$	(1,187	)	$	1,391
OPERATING EXPENSES:
Fuel	1			294			48			—			343
Purchased power from affiliates	1,185			2			69			(1,187		)	69
Purchased power from non-affiliates	297			—			—			—			297
Other operating expenses	162			111			180			12			465
Provision for depreciation	1			32			38			(2		)	69
General taxes	10			11			8			—			29
Impairment of long-lived assets	—			14			—			—			14
Total operating expenses	1,656			464			343			(1,177		)	1,286
OPERATING INCOME (LOSS)	(290		)	279			126			(10		)	105
OTHER INCOME (EXPENSE):
Investment income	1			—			5			—			6
Miscellaneous income, including net income from equity investees	242			1			—			(239		)	4
Interest expense — affiliates	(1		)	—			—			—			(1		)
Interest expense — other	(24		)	(28		)	(17		)	16			(53		)
Capitalized interest	—			5			5			—			10
Total other income (expense)	218			(22		)	(7		)	(223		)	(34		)
INCOME (LOSS) BEFORE INCOME TAXES	(72		)	257			119			(233		)	71
INCOME TAXES (BENEFITS)	(117		)	96			45			2			26
NET INCOME	$	45		$	161		$	74		$	(235	)	$	45
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	45		$	161		$	74		$	(235	)	$	45
OTHER COMPREHENSIVE INCOME
Pensions and OPEB prior service costs	(10		)	(4		)	(6		)	10			(10		)
Amortized loss on derivative hedges	(9		)	—			—			—			(9		)
Change in unrealized gain on available for sale securities	8			—			8			(8		)	8
Other comprehensive income (loss)	(11		)	(4		)	2			2			(11		)
Income taxes (benefits) on other comprehensive income (loss)	(6		)	(2		)	1			1			(6		)
Other comprehensive income (loss), net of tax	(5		)	(2		)	1			1			(5		)
COMPREHENSIVE INCOME	$	40		$	159		$	75		$	(234	)	$	40

Condensed Consolidating Balance Sheets

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of March 31, 2012	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	395		—		—		—			395
Affiliated companies	472		439		241		(611		)	541
Other	50		19		53		—			122
Notes receivable from affiliated companies	81		1,369		44		(1,482		)	12
Materials and supplies, at average cost	62		283		206		—			551
Derivatives	322		—		—		—			322
Prepayments and other	7		17		1		(1		)	24
	1,389		2,134		545		(2,094		)	1,974
PROPERTY, PLANT AND EQUIPMENT:
In service	84		5,614		5,689		(385		)	11,002
Less — Accumulated provision for depreciation	29		1,843		2,524		(182		)	4,214
	55		3,771		3,165		(203		)	6,788
Construction work in progress	31		171		971		—			1,173
	86		3,942		4,136		(203		)	7,961
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,240		—			1,240
Investment in affiliated companies	5,956		—		—		(5,956		)	—
Other	—		7		—		—			7
	5,956		7		1,240		(5,956		)	1,247
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		274		—		(274		)	—
Customer intangibles	120		—		—		—			120
Goodwill	24		—		—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		21		—		99			120
Derivatives	117		—		—		—			117
Other	123		111		2		(65		)	171
	384		426		25		(240		)	595
	$	7,815	$	6,509	$	5,946	$	(8,493	)	$	11,777
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	411	$	514	$	(21	)	$	905
Short-term borrowings-
Affiliated companies	1,413		69		—		(1,482		)	—
Accounts payable-
Affiliated companies	663		175		256		(611		)	483
Other	69		121		—		—			190
Accrued Taxes	31		33		24		(13		)	75
Derivatives	281		—		—		—			281
Other	38		111		24		72			245
	2,496		920		818		(2,055		)	2,179
CAPITALIZATION:
Total equity	3,695		3,244		2,697		(5,941		)	3,695
Long-term debt and other long-term obligations	1,482		1,903		641		(1,229		)	2,797
	5,177		5,147		3,338		(7,170		)	6,492
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		917			917
Accumulated deferred income taxes	18		—		532		(185		)	365
Asset retirement obligations	—		28		891		—			919
Retirement benefits	31		120		—		—			151
Lease market valuation liability	—		160		—		—			160
Other	93		134		367		—			594
	142		442		1,790		732			3,106
	$	7,815	$	6,509	$	5,946	$	(8,493	)	$	11,777

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2011	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	424		—		—		—			424
Affiliated companies	476		643		262		(781		)	600
Other	28		20		13		—			61
Notes receivable from affiliated companies	155		1,346		69		(1,187		)	383
Materials and supplies, at average cost	60		232		200		—			492
Derivatives	219		—		—		—			219
Prepayments and other	11		26		1		—			38
	1,373		2,274		545		(1,968		)	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	84		5,573		5,711		(385		)	10,983
Less — Accumulated provision for depreciation	28		1,813		2,449		(180		)	4,110
	56		3,760		3,262		(205		)	6,873
Construction work in progress	29		195		790		—			1,014
	85		3,955		4,052		(205		)	7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,223		—			1,223
Investment in affiliated companies	5,716		—		—		(5,716		)	—
Other	—		7		—		—			7
	5,716		7		1,223		(5,716		)	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	10		307		—		(317		)	—
Customer intangibles	123		—		—		—			123
Goodwill	24		—		—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		5		—		75			80
Derivatives	79		—		—		—			79
Other	89		99		3		(62		)	129
	325		431		26		(304		)	478
	$	7,499	$	6,667	$	5,846	$	(8,193	)	$	11,819
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	411	$	513	$	(20	)	$	905
Short-term borrowings-
Affiliated companies	1,065		89		32		(1,186		)	—
Accounts payable-
Affiliated companies	777		228		211		(780		)	436
Other	99		121		—		—			220
Accrued Taxes	84		42		110		(9		)	227
Derivatives	189		—		—		—			189
Other	62		141		16		42			261
	2,277		1,032		882		(1,953		)	2,238
CAPITALIZATION:
Common stockholder’s equity	3,593		3,097		2,587		(5,700		)	3,577
Long-term debt and other long-term obligations	1,483		1,905		641		(1,230		)	2,799
	5,076		5,002		3,228		(6,930		)	6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		925			925
Accumulated deferred income taxes	12		—		510		(236		)	286
Asset retirement obligations	—		28		876		—			904
Retirement benefits	56		300		—		—			356
Lease market valuation liability	—		171		—		—			171
Other	78		134		350		1			563
	146		633		1,736		690			3,205
	$	7,499	$	6,667	$	5,846	$	(8,193	)	$	11,819

Condensed Consolidating Statements of Cash Flows

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(419	)	$	66		$	175		$	—		$	(178	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	347			—			—			(347		)	—
Redemptions and Repayments-
Short-term borrowings, net	—			(20		)	(32		)	52			—
Other	—			(2		)	(1		)	—			(3		)
Net cash provided from (used for) financing activities	347			(22		)	(33		)	(295		)	(3		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(18		)	(161		)	—			(181		)
Sales of investment securities held in trusts	—			—			83			—			83
Purchases of investment securities held in trusts	—			—			(90		)	—			(90		)
Loans to affiliated companies, net	74			(23		)	25			295			371
Other	—			(3		)	1			—			(2		)
Net cash provided from (used for) investing activities	72			(44		)	(142		)	295			181
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—		$	7

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2011	FES			FGCO			NGC			Eliminations		Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(215	)	$	267		$	42		$	—	$	94
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			90			60			—		150
Short-term borrowings, net	322			28			—			—		350
Redemptions and Repayments-
Long-term debt	(131		)	(141		)	(60		)	—		(332		)
Other	(1		)	—			—			—		(1		)
Net cash used for financing activities	190			(23		)	—			—		167
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(3		)	(40		)	(116		)	—		(159		)
Sales of investment securities held in trusts	—			—			216			—		216
Purchases of investment securities held in trusts	—			—			(231		)	—		(231		)
Loans to affiliated companies, net	28			(200		)	90			—		(82		)
Customer acquisition costs	—			—			—			—		—
Other	—			(6		)	(1		)	—		(7		)
Net cash provided from (used for) investing activities	25			(246		)	(42		)	—		(263		)
Net change in cash and cash equivalents	—			(2		)	—			—		(2		)
Cash and cash equivalents at beginning of period	—			9			—			—		9
Cash and cash equivalents at end of period	$	—		$	7		$	—		$	—	$	7

XML

Regulatory Matters (Details) (USD $)	0 Months Ended	3 Months Ended	1 Months Ended	3 Months Ended		3 Months Ended			3 Months Ended	0 Months Ended	1 Months Ended	3 Months Ended		12 Months Ended			27 Months Ended	36 Months Ended		3 Months Ended		1 Months Ended	3 Months Ended	12 Months Ended				1 Months Ended			1 Months Ended			3 Months Ended				12 Months Ended	3 Months Ended		0 Months Ended
	Dec. 09, 2009	Mar. 31, 2012 entities	Apr. 30, 2007 FERC kv	Mar. 31, 2012 FERC	Jan. 21, 2010 FERC issues	Mar. 31, 2012 FERC PATH kv	Mar. 31, 2012 FERC PJM Calculation Error	Dec. 28, 2011 FERC PJM Calculation Error	Jun. 30, 2011 The Seneca Pumped Storage Project Relicensing	Apr. 22, 2011 OHIO	Aug. 31, 2011 OHIO proposals	Mar. 31, 2012 OHIO Party	Oct. 31, 2009 OHIO proposals	Dec. 31, 2011 OHIO MWh	Dec. 31, 2010 OHIO MWh	Dec. 31, 2009 OHIO MWh	Mar. 31, 2012 OHIO	Dec. 31, 2011 OHIO	Dec. 31, 2010 OHIO	Mar. 31, 2012 MARYLAND	Oct. 06, 2009 MARYLAND	Oct. 31, 2010 PENNSYLVANIA	Mar. 31, 2012 PENNSYLVANIA	Dec. 31, 2010 PENNSYLVANIA	Aug. 29, 2011 PENNSYLVANIA questions	Jun. 30, 2011 PENNSYLVANIA Party	May 31, 2011 PENNSYLVANIA	Feb. 29, 2012 WEST VIRGINIA Facilities	Apr. 30, 2010 WEST VIRGINIA	Jan. 31, 2012 WEST VIRGINIA Facilities	Feb. 29, 2012 WEST VIRGINIA City of New Martinsville entities	Feb. 29, 2012 WEST VIRGINIA Morgantown Energy entities	Oct. 31, 2006 California Claims Matters FERC Proceedings	Mar. 31, 2012 California Claims Matters FERC	Mar. 31, 2012 Yards Creek Pumped Storage Project FERC MW	Mar. 31, 2012 Yards Creek Pumped Storage Project FERC JCP&L	Mar. 31, 2012 The Seneca Pumped Storage Project FERC MW	Dec. 31, 2012 Year 2012 OHIO MWh	Mar. 31, 2012 Year 2013 OHIO MWh	Mar. 31, 2012 Year 2013 PENNSYLVANIA	Apr. 27, 2012 Pending Litigation OHIO
Regulatory Matters [Line Items]
Proposed electric consumption reduction percentage																				10.00%
Proposed electric demand reduction percentage																				15.00%
Expenditures for cost recovery program																					$ 101,000,000
Maximum Amount Of Penalty Assessed Per Day Per Violation																				25,000
Recovery period for expenditures for cost recovery program																					6 years
Load cap percentage minimum												80.00%
Maximum trance award to a single supplier												80.00%
Generation discount for low income customers												6.00%
Costs avoided by customers, integration period												5 years
Costs avoided by customers												360,000,000
Fund to assist low income customers												12,000,000
Legal Parties												19
ESP extension term												2 years
Annual energy savings														410,000	290,000	166,000																						470,000	530,000
Utilities required to reduce peak demand																1.00%
Utilities required to additionally reduce peak demand												0.75%
Period of the portfolio plans filed seeking approval for the program																3 years
Reply Period in the Event of Motion Denial																																									20 days
Application for Rehearing, Ruling Period										30 days
Load served from renewable energy resources																	2.00%	1.50%	1.00%
Request for proposals conducted											2		2
Marginal transmission refund period																							29 months
Marginal transmission losses																								254,000,000
Minimum reduction in Utilities reduce energy consumption																											1.00%													3.00%
Minimum reduction in Utilities peak demand																																								4.50%
Target installation smart meter																							25,000
Grace period		30 months																				30 months
Expenditure amortization period																							10 years
Parties Able to Challenge Recovery Amounts																										1
Directed Questions for Investigation																									11
Annualized base rate increase																													40,000,000
Storm restoration deferral period																													5 years
Additional base rate increase																													20,000,000
Decrease in ENEC rates																													20,000,000
Facilities Seeking Certification As Qualified Energy Resource Facilities																														3
Number of electric generation facilities																												3
Number of electric generation facilities, owned by third party																															1	1
Power threshold for cost methodology			500
Identified issues for written comments					9
One time payment, ATSI agreed to MISO				1,800,000
Annual Revenue requirements in Zone				15,000,000
Losses incurred due to underfunding of contracts							6,000,000	35,000,000
Settlement proposal claims																																		$ 190,000,000
Court proceedings from filed claims																																	1
New Voltage transmission facilities across PJM and a zonal transmission rate (In KV)						765
Hydroelectric project																																			400		451
Ownership interest																																				50.00%
Renewal length of operating license																																				40 years
ILP licensure period																																				5 years
Period of cycle									5 years
Regional Enforcement Entities		8
Customer Power Loss Period	P11H

XML

Fair Value Measurements (Details 5) (Debt Securities, USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 336	$ 402
Unrealized Gains	41	50
Fair Value	377	452
OE
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	162	163
Unrealized Gains	19	21
Fair Value	$ 181	$ 184

XML

Consolidated Balance Sheets (Unaudited) (USD $) In Millions, unless otherwise specified	Mar. 31, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 74	$ 202
Receivables-
Customers, net of allowance for uncollectible accounts	1,449	1,525
Other, net of allowance for uncollectible accounts	286	269
Materials and supplies	927	811
Prepaid taxes	213	191
Derivatives	346	235
Prepayments and other	182	122
Total current assets	3,477	3,355
PROPERTY, PLANT AND EQUIPMENT:
In service	40,587	40,122
Less - Accumulated provision for depreciation	12,086	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,501	28,283
Construction work in progress	2,065	2,054
Total net property, plant and equipment	30,566	30,337
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts		2,112
Investments in lease obligation bonds	336	402
Other	1,011	1,008
Total other property and investments	3,482	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444	6,441
Regulatory assets	2,006	2,030
Other	1,716	1,641
Total deferred charges and other assets	10,166	10,112
Total assets	47,691	47,326
CURRENT LIABILITIES:
Currently payable long-term debt	1,772	1,621
Short-term borrowings-
Short-term borrowings	1,075	0
Accounts payable-
Accounts payable	918	1,174
Accrued taxes	442	558
Accrued compensation and benefits	258	384
Derivatives	299	218
Other	1,009	900
Total current liabilities	5,773	4,855
Common stockholders' equity-
Common stock	42	42
Other paid-in capital	9,754	9,765
Accumulated other comprehensive income	405	426
Retained earnings (Accumulated deficit)	3,122	3,047
Total common stockholders' equity	13,323	13,280
Noncontrolling interest	16	19
Total equity	13,339	13,299
Long-term debt and other long-term obligations	15,527	15,716
Total capitalization	28,866	29,015
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	5,904	5,670
Retirement benefits	2,240	2,823
Asset retirement obligations	1,522	1,497
Deferred gain on sale and leaseback transaction	917	925
Adverse power contract liability	458	469
Other	2,011	2,072
Total noncurrent liabilities	13,052	13,456
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	47,691	47,326
FES
CURRENT ASSETS:
Cash and cash equivalents	7	7
Receivables-
Customers, net of allowance for uncollectible accounts	395	424
Affiliated companies	541	600
Other, net of allowance for uncollectible accounts	122	61
Notes receivable from affiliated companies	12	383
Materials and supplies	551	492
Derivatives	322	219
Prepayments and other	24	38
Total current assets	1,974	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	11,002	10,983
Less - Accumulated provision for depreciation	4,214	4,110
Property, plant and equipment in service net of accumulated provision for depreciation	6,788	6,873
Construction work in progress	1,173	1,014
Total net property, plant and equipment	7,961	7,887
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts	1,240	1,223
Other	7	7
Total other property and investments	1,247	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	120	123
Goodwill	24	24
Property taxes	43	43
Unamortized sale and leaseback costs	120	80
Derivatives	117	79
Other	171	129
Total deferred charges and other assets	595	478
Total assets	11,777	11,819
CURRENT LIABILITIES:
Currently payable long-term debt	905	905
Accounts payable-
Affiliated companies	483	436
Other	190	220
Accrued taxes	75	227
Derivatives	281	189
Other	245	261
Total current liabilities	2,179	2,238
Common stockholders' equity-
Common stock	1,568	1,570
Accumulated other comprehensive income	74	76
Retained earnings (Accumulated deficit)	2,053	1,931
Total common stockholders' equity	3,695	3,577
Long-term debt and other long-term obligations	2,797	2,799
Total capitalization	6,492	6,376
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	365	286
Retirement benefits	151	356
Asset retirement obligations	919	904
Deferred gain on sale and leaseback transaction	917	925
Lease market valuation liability	160	171
Other	594	563
Total noncurrent liabilities	3,106	3,205
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	11,777	11,819
FES | Affiliates [Member]
Short-term borrowings-
Short-term borrowings	0	0
OE
CURRENT ASSETS:
Cash and cash equivalents	0	26
Receivables-
Customers, net of allowance for uncollectible accounts	154	163
Affiliated companies	72	86
Other, net of allowance for uncollectible accounts	37	41
Notes receivable from affiliated companies	259	181
Prepayments and other	11	17
Total current assets	533	514
PROPERTY, PLANT AND EQUIPMENT:
In service	3,405	3,358
Less - Accumulated provision for depreciation	1,280	1,267
Property, plant and equipment in service net of accumulated provision for depreciation	2,125	2,091
Construction work in progress	85	91
Total net property, plant and equipment	2,210	2,182
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts	137	137
Investments in lease obligation bonds	162	163
Other	92	90
Total other property and investments	391	390
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	362	363
Pension assets	6	5
Property taxes	80	81
Unamortized sale and leaseback costs	24	25
Other	16	14
Total deferred charges and other assets	488	488
Total assets	3,622	3,574
CURRENT LIABILITIES:
Currently payable long-term debt	3	2
Accounts payable-
Affiliated companies	110	119
Other	34	35
Accrued taxes	88	88
Accrued interest	25	25
Other	102	79
Total current liabilities	362	348
Common stockholders' equity-
Common stock	747	747
Accumulated other comprehensive income	49	54
Retained earnings (Accumulated deficit)	(53)	(84)
Total common stockholders' equity	743	717
Noncontrolling interest	5	5
Total equity	748	722
Long-term debt and other long-term obligations	1,156	1,155
Total capitalization	1,904	1,877
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	791	787
Retirement benefits	213	213
Asset retirement obligations	73	71
Accumulated deferred investment tax credits	8	9
Other	271	269
Total noncurrent liabilities	1,356	1,349
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	3,622	3,574
JCP&L
CURRENT ASSETS:
Cash and cash equivalents	0	0
Receivables-
Customers, net of allowance for uncollectible accounts	202	235
Affiliated companies	35	0
Other, net of allowance for uncollectible accounts	16	17
Prepaid taxes	39	33
Prepayments and other	24	19
Total current assets	316	304
PROPERTY, PLANT AND EQUIPMENT:
In service	5,022	4,872
Less - Accumulated provision for depreciation	1,759	1,743
Property, plant and equipment in service net of accumulated provision for depreciation	3,263	3,129
Construction work in progress	119	227
Total net property, plant and equipment	3,382	3,356
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts	195	193
Nuclear fuel disposal trust	225	219
Other	2	2
Total other property and investments	422	414
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	1,811	1,811
Regulatory assets	384	408
Other	32	32
Total deferred charges and other assets	2,227	2,251
Total assets	6,347	6,325
CURRENT LIABILITIES:
Currently payable long-term debt	34	34
Accounts payable-
Affiliated companies	3	19
Other	94	101
Accrued interest	30	18
Accrued compensation and benefits	33	41
Customer deposits	24	24
Other	41	36
Total current liabilities	559	532
Common stockholders' equity-
Common stock	136	136
Other paid-in capital	2,011	2,011
Accumulated other comprehensive income	36	39
Retained earnings (Accumulated deficit)	146	121
Total common stockholders' equity	2,329	2,307
Long-term debt and other long-term obligations	1,729	1,736
Total capitalization	4,058	4,043
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	908	859
Retirement benefits	163	170
Asset retirement obligations	117	115
Power purchase contract liability	136	147
Nuclear fuel disposal costs	197	197
Other	209	262
Total noncurrent liabilities	1,730	1,750
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	6,347	6,325
JCP&L | Affiliates [Member]
Short-term borrowings-
Affiliated companies	$ 300	$ 259

XML

Pensions and Other Postemployment Benefits

3 Months Ended

Mar. 31, 2012

Compensation and Retirement Disclosure [Abstract]

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

PENSIONS AND OTHER POSTEMPLOYMENT 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. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pensions and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. 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 endedMarch 31, 2012, FirstEnergy made pre-tax contributions to its qualified pension plan of $600 million.

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2012			2011			2012			2011
	(In millions)
Service cost	$	40		$	29		$	3		$	3
Interest cost	97			84			12			11
Expected return on plan assets	(121		)	(102		)	(9		)	(10		)
Amortization of prior service cost	3			4			(51		)	(48		)
Other adjustments (settlements, curtailments, etc)	—			7			—			—
Net periodic costs (credits)	$	19		$	22		$	(45	)	$	(44	)

Pension and OPEB obligations are allocated to FE's subsidiaries employing the plan participants. The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and its subsidiaries were as follows:

Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	13		$	20		$	(30	)	$	(32	)
FES	10			7			(8		)	(7		)
OE	(1		)	(2		)	(5		)	(6		)
JCP&L	(1		)	(2		)	(2		)	(3		)

XML

Segment Information (Tables)

3 Months Ended

Mar. 31, 2012

Segment Reporting [Abstract]

Segment Financial Information

Segment Financial Information

Three Months Ended	Regulated Distribution		Competitive Energy Services		Regulated Independent Transmission		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
March 31, 2012
External revenues	$	2,383	$	1,607	$	109	$	(24	)	$	1		$	4,076
Internal revenues	—		268		—		—			(266		)	2
Total revenues	2,383		1,875		109		(24		)	(265		)	4,078
Depreciation and amortization	234		100		18		8			—			360
Investment income	24		6		—		—			(19		)	11
Net interest charges	142		54		12		21			—			229
Income taxes	108		83		20		(16		)	27			222
Net income	183		141		34		(28		)	(24		)	306
Total assets	27,551		17,187		2,452		501			—			47,691
Total goodwill	5,551		893		—		—			—			6,444
Property additions	301		243		28		17			—			589
March 31, 2011
External revenues	$	2,268	$	1,254	$	67	$	(23	)	$	(22	)	$	3,544
Internal revenues	—		343		—		—			(311		)	32
Total revenues	2,268		1,597		67		(23		)	(333		)	3,576
Depreciation and amortization	250		88		13		6			—			357
Investment income	25		6		—		—			(10		)	21
Net interest charges	131		68		9		19			(14		)	213
Income taxes	64		9		7		—			31			111
Net income	109		15		12		(55		)	(34		)	47
Total assets	27,766		17,399		2,486		914			—			48,565
Total goodwill	5,551		956		—		—			—			6,507
Property additions	177		214		27		31			—			449

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified																						3 Months Ended
	Mar. 31, 2012 FTRs		Dec. 31, 2011 FTRs		Dec. 31, 2010 FTRs		Mar. 31, 2012 FTRs FES	Dec. 31, 2011 FTRs FES	Dec. 31, 2010 FTRs FES	Mar. 31, 2012 Non Utility Generation contract		Dec. 31, 2011 Non Utility Generation contract		Dec. 31, 2010 Non Utility Generation contract		Mar. 31, 2012 Non Utility Generation contract JCP&L		Dec. 31, 2011 Non Utility Generation contract JCP&L		Dec. 31, 2010 Non Utility Generation contract JCP&L		Mar. 31, 2012 Model Level 3 Minimum FTRs	Mar. 31, 2012 Model Level 3 Minimum FTRs FES	Mar. 31, 2012 Model Level 3 Minimum Non Utility Generation contract MWh	Mar. 31, 2012 Model Level 3 Minimum Non Utility Generation contract JCP&L MWh	Mar. 31, 2012 Model Level 3 Maximum FTRs	Mar. 31, 2012 Model Level 3 Maximum FTRs FES	Mar. 31, 2012 Model Level 3 Maximum Non Utility Generation contract MWh	Mar. 31, 2012 Model Level 3 Maximum Non Utility Generation contract JCP&L MWh	Mar. 31, 2012 Model Level 3 Weighted Average [Member] FTRs	Mar. 31, 2012 Model Level 3 Weighted Average [Member] FTRs FES	Mar. 31, 2012 Model Level 3 Weighted Average [Member] Non Utility Generation contract MWh	Mar. 31, 2012 Model Level 3 Weighted Average [Member] Non Utility Generation contract JCP&L MWh
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value	$ (14)	[1]	$ (22)	[1]	$ 0	[1]	$ (3)	$ (6)	$ 0	$ (300)	[1]	$ (292)	[1]	$ (344)	[1]	$ (132)	[2]	$ (143)	[2]	$ (227)	[2]
Fair Value Inputs, RTO Auction Clearing Prices																						(4.18)	(4.18)			9.81	8.03			1.51	0.76
Fair Value Inputs, Generation																								500	69,000			6,809,000	736,000			2,547,000	157,000
Fair Value Inputs, Power, Regional Prices																								58.71	58.71			84.92	84.92			66.77	68.65

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

[2] Changes in the fair value of NUG contracts are subject to regulatory accounting and do not impact earnings.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2012

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share

The following table reconciles basic and diluted earnings per share of common stock:

	Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2012		2011
	(In millions, except per share amounts)
Weighted average number of basic shares outstanding	418		342
Assumed exercise of dilutive stock options and awards(1)	2		1
Weighted average number of diluted shares outstanding	420		343
Earnings Available to FirstEnergy Corp.	$	306	$	52
Basic earnings per share of common stock	$	0.73	$	0.15
Diluted earnings per share of common stock	$	0.73	$	0.15

⁽¹⁾  The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect were not significant for the three months endedMarch 31, 2012 and 2011.