10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 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 AUGUST 6, 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 deactivate our older unscrubbed regulated and competitive fossil units, including the impact on vendor commitments, and the timing of those deactivations as they relate to, among other things, the RMR arrangements and the reliability of the transmission grid.

• Issues that could result from the NRC's review of the indications of cracking in the Davis Besse Plant shield building.

• 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).

• 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, changes in their operational status and any related impacts on vendor commitments.

• 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 measurement of liabilities and 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	60
FirstEnergy Corp. Management's Discussion of Analysis of Financial Condition and Results of Operations	60
Management’s Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	106
Ohio Edison Company	110
Jersey Central Power & Light Company	112
Item 3. Quantitative and Qualitative Disclosures About Market Risk	114
Item 4. Controls and Procedures — FirstEnergy	114
Part II. Other Information
Item 1. Legal Proceedings	114
Item 1A. Risk Factors	114
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	114
Item 3. Defaults Upon Senior Securities	114
Item 4. Mine Safety Disclosures	114
Item 5. Other Information	115
Item 6. Exhibits	116

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
AGC	Allegheny Generating Company, a generation subsidiary of AE
Allegheny	Allegheny Energy, Inc., together with its consolidated subsidiaries
Allegheny Utilities	MP, PE and WP
ATSI	American Transmission Systems, Incorporated, formerly a direct subsidiary of FE that became a subsidiary of FET 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
FET	FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC, a subsidiary of AE, which is the parent of ATSI and TrAIL and has a joint venture in PATH.
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
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 FET, 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
BTU	British Thermal Units
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
GWH	Gigawatt-hour
HCL	Hydrochloric Acid
ICG	International Coal Group Inc.
ILP	Integrated License Application Process
IRS	Internal Revenue Service
IT	Information Technology
kV	Kilovolt
KWH	Kilowatt-hour
LBR	Little Blue Run
LCAPP	Long-Term Capacity Agreement Pilot Program
LITE	Local Infrastructure and Transmission Enhancement
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.

iii

GLOSSARY OF TERMS, Continued
Moody’s	Moody’s Investors Service, Inc.
MTEP	MISO Regional Transmission Expansion Plan
MVP	Multi-value Project
MW	Megawatt
MWH	Megawatt-hour
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
NMB	Non-Market Based
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
RMR	Reliability Must-Run
RPM	Reliability Pricing Model
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

iv

GLOSSARY OF TERMS, Continued
TDS	Total Dissolved Solid
TMDL	Total Maximum Daily Load
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
VIE	Variable Interest Entity
VSCC	Virginia State Corporation Commission
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia

v

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended June 30						Six Months Ended June 30
(In millions, except per share amounts)	2012			2011			2012			2011
REVENUES:
Electric utilities	$	2,279		$	2,590		$	4,790		$	4,925
Unregulated businesses	1,590			1,470			3,157			2,711
Total revenues*	3,869			4,060			7,947			7,636
OPERATING EXPENSES:
Fuel	656			635			1,197			1,088
Purchased power	1,156			1,220			2,503			2,406
Other operating expenses	914			1,065			1,726			2,058
Provision for depreciation	292			287			577			512
Amortization of regulatory assets, net	62			90			137			222
General taxes	232			242			504			479
Total operating expenses	3,312			3,539			6,644			6,765
OPERATING INCOME	557			521			1,303			871
OTHER INCOME (EXPENSE):
Investment income	13			31			24			52
Interest expense	(274		)	(265		)	(520		)	(496		)
Capitalized interest	19			20			36			38
Total other expense	(242		)	(214		)	(460		)	(406		)
INCOME BEFORE INCOME TAXES	315			307			843			465
INCOME TAXES	127			114			349			225
NET INCOME	188			193			494			240
Income (loss) attributable to noncontrolling interest	1			(10		)	1			(15		)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	187		$	203		$	493		$	255
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$	0.45		$	0.48		$	1.18		$	0.67
Diluted	$	0.45		$	0.48		$	1.18		$	0.67
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	417			418			418			380
Diluted	419			420			419			382
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	—		$	—		$	0.55		$	0.55

* Includes excise tax collections of $107 million and $116 million in the three months ended June 30, 2012 and 2011, respectively, and $228 million and $235 million in the six months ended June 30, 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 June 30						Six Months Ended June 30
(In millions)	2012			2011			2012			2011
NET INCOME	$	188		$	193		$	494		$	240
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(48		)	48			(101		)	4
Amortized losses on derivative hedges	3			17			1			11
Change in unrealized gain on available-for-sale securities	2			10			12			19
Other comprehensive income (loss)	(43		)	75			(88		)	34
Income taxes (benefits) on other comprehensive income (loss)	(27		)	33			(51		)	14
Other comprehensive income (loss), net of tax	(16		)	42			(37		)	20
COMPREHENSIVE INCOME	172			235			457			260
Comprehensive income (loss) attributable to noncontrolling interest	1			(10		)	1			(15		)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	171		$	245		$	456		$	275

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)	June 30, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	94	$	202
Receivables-
Customers, net of allowance for uncollectible accounts of $36 in 2012 and $37 in 2011	1,635		1,525
Other, net of allowance for uncollectible accounts of $2 in 2012 and $3 in 2011	263		269
Materials and supplies	921		811
Prepaid taxes	248		191
Derivatives	276		235
Other	171		122
	3,608		3,355
PROPERTY, PLANT AND EQUIPMENT:
In service	41,167		40,122
Less — Accumulated provision for depreciation	12,336		11,839
	28,831		28,283
Construction work in progress	1,937		2,054
	30,768		30,337
INVESTMENTS:
Nuclear plant decommissioning trusts	2,153		2,112
Investments in lease obligation bonds	326		402
Other	1,039		1,008
	3,518		3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444		6,441
Regulatory assets	2,122		2,030
Other	1,588		1,641
	10,154		10,112
	$	48,048	$	47,326
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,577	$	1,621
Short-term borrowings	1,890		—
Accounts payable	1,052		1,174
Accrued taxes	436		558
Accrued compensation and benefits	288		384
Derivatives	222		218
Other	617		900
	6,082		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	9,756		9,765
Accumulated other comprehensive income	389		426
Retained earnings	3,310		3,047
Total common stockholders’ equity	13,497		13,280
Noncontrolling interest	15		19
Total equity	13,512		13,299
Long-term debt and other long-term obligations	15,159		15,716
	28,671		29,015
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,042		5,670
Retirement benefits	2,257		2,823
Asset retirement obligations	1,548		1,497
Deferred gain on sale and leaseback transaction	909		925
Adverse power contract liability	559		469
Other	1,980		2,072
	13,295		13,456
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	48,048	$	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)

	Six Months Ended June 30
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	494		$	240
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	577			512
Amortization of regulatory assets, net	137			222
Nuclear fuel and lease amortization	106			92
Deferred purchased power and other costs	(149		)	(168		)
Deferred income taxes and investment tax credits, net	423			598
Deferred rents and lease market valuation liability	(106		)	(61		)
Stock based compensation	(18		)	(4		)
Accrued compensation and retirement benefits	(160		)	(31		)
Commodity derivative transactions, net	(86		)	(21		)
Pension trust contributions	(600		)	(262		)
Asset impairments	7			41
Cash collateral, net	22			(31		)
Decrease (increase) in operating assets-
Receivables	(105		)	199
Materials and supplies	(109		)	24
Prepayments and other current assets	(117		)	(268		)
Decrease in operating liabilities-
Accounts payable	(122		)	(28		)
Accrued taxes	(192		)	(66		)
Accrued interest	(5		)	(4		)
Other	65			47
Net cash provided from operating activities	62			1,031
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	182			503
Short-term borrowings, net	1,890			—
Redemptions and Repayments-
Long-term debt	(746		)	(1,002		)
Short-term borrowings, net	—			(44		)
Common stock dividend payments	(460		)	(420		)
Other	(35		)	(76		)
Net cash provided from (used for) financing activities	831			(1,039		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,001		)	(1,018		)
Sales of investment securities held in trusts	382			1,703
Purchases of investment securities held in trusts	(420		)	(1,807		)
Cash investments	87			50
Cash received in Allegheny merger	—			590
Other	(49		)	(53		)
Net cash used for investing activities	(1,001		)	(535		)
Net change in cash and cash equivalents	(108		)	(543		)
Cash and cash equivalents at beginning of period	202			1,019
Cash and cash equivalents at end of period	$	94		$	476
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 June 30						Six Months Ended June 30
(In millions)	2012			2011			2012			2011
STATEMENTS OF INCOME
REVENUES:
Electric sales to non-affiliates	$	1,293		$	1,052		$	2,625		$	2,097
Electric sales to affiliates	109			170			230			431
Other	54			70			117			156
Total revenues	1,456			1,292			2,972			2,684
OPERATING EXPENSES:
Fuel	380			316			675			659
Purchased power from affiliates	133			65			250			134
Purchased power from non-affiliates	434			329			921			626
Other operating expenses	393			413			688			878
Provision for depreciation	69			69			132			138
General taxes	32			30			69			60
Impairment of long-lived assets	—			7			—			20
Total operating expenses	1,441			1,229			2,735			2,515
OPERATING INCOME	15			63			237			169
OTHER INCOME (EXPENSE):
Investment income	6			16			12			22
Miscellaneous income	20			4			24			8
Interest expense — affiliates	(2		)	(2		)	(4		)	(3		)
Interest expense — other	(48		)	(52		)	(89		)	(105		)
Capitalized interest	9			10			18			20
Total other expense	(15		)	(24		)	(39		)	(58		)
INCOME BEFORE INCOME TAXES	—			39			198			111
INCOME TAXES	1			10			77			37
NET INCOME (LOSS)	$	(1	)	$	29		$	121		$	74
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	$	(1	)	$	29		$	121		$	74
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	8			(5		)	3			(9		)
Amortized gain (loss) on derivative hedges	1			14			(4		)	5
Change in unrealized gain on available-for-sale securities	3			8			13			15
Other comprehensive income	12			17			12			11
Income taxes on other comprehensive income	2			8			4			4
Other comprehensive income, net of tax	10			9			8			7
COMPREHENSIVE INCOME	$	9		$	38		$	129		$	81

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)	June 30, 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	457		424
Affiliated companies	537		600
Other, net of allowance for uncollectible accounts of $2 in 2012 and $3 in 2011	96		61
Notes receivable from affiliated companies	228		383
Materials and supplies	548		492
Derivatives	265		219
Prepayments and other	19		38
	2,157		2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	11,375		10,983
Less — Accumulated provision for depreciation	4,314		4,110
	7,061		6,873
Construction work in progress	919		1,014
	7,980		7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	1,250		1,223
Other	7		7
	1,257		1,230
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	118		123
Goodwill	24		24
Property taxes	43		43
Unamortized sale and leaseback costs	118		80
Derivatives	110		79
Other	137		129
	550		478
	$	11,944	$	11,819
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,144	$	905
Accounts payable-
Affiliated companies	608		436
Other	306		220
Accrued taxes	62		227
Derivatives	219		189
Other	242		261
	2,581		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	84		76
Retained earnings	2,052		1,931
Total common stockholder's equity	3,704		3,577
Long-term debt and other long-term obligations	2,500		2,799
	6,204		6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	909		925
Accumulated deferred income taxes	436		286
Asset retirement obligations	934		904
Retirement benefits	179		356
Lease market valuation liability	148		171
Other	553		563
	3,159		3,205
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	11,944	$	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)

	Six Months Ended June 30
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	121		$	74
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	132			138
Nuclear fuel and lease amortization	103			92
Deferred rents and lease market valuation liability	(103		)	(58		)
Deferred income taxes and investment tax credits, net	162			138
Asset impairments	6			28
Gain on asset sales	(17		)	—
Accrued compensation and retirement benefits	14			(24		)
Pension trust contribution	(209		)	—
Commodity derivative transactions, net	(53		)	(60		)
Cash collateral, net	17			(40		)
Decrease (increase) in operating assets-
Receivables	—			(36		)
Materials and supplies	(56		)	50
Prepayments and other current assets	19			12
Increase (decrease) in operating liabilities-
Accounts payable	243			(124		)
Accrued taxes	(167		)	(29		)
Other	7			21
Net cash provided from operating activities	219			182
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	82			247
Short-term borrowings, net	—			530
Redemptions and repayments-
Long-term debt	(140		)	(472		)
Other	(6		)	(11		)
Net cash provided from (used for) financing activities	(64		)	294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(303		)	(334		)
Proceeds from assets sale	17			—
Sales of investment securities held in trusts	109			513
Purchases of investment securities held in trusts	(127		)	(545		)
Loans to affiliated companies, net	155			(93		)
Other	(6		)	(20		)
Net cash used for investing activities	(155		)	(479		)
Net change in cash and cash equivalents	—			(3		)
Cash and cash equivalents at beginning of period	7			9
Cash and cash equivalents at end of period	$	7		$	6

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 June 30						Six Months Ended June 30
(In millions)	2012			2011			2012			2011
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	364		$	360		$	723		$	724
Excise and gross receipts tax collections	24			25			51			53
Total revenues	388			385			774			777
OPERATING EXPENSES:
Purchased power from affiliates	38			69			90			163
Purchased power from non-affiliates	66			63			136			123
Other operating expenses	119			106			240			202
Provision for depreciation	25			23			49			46
Amortization of regulatory assets, net	15			2			15			3
General taxes	46			46			96			95
Total operating expenses	309			309			626			632
OPERATING INCOME	79			76			148			145
OTHER INCOME (EXPENSE):
Investment income	5			4			9			9
Interest expense	(23		)	(22		)	(45		)	(44		)
Capitalized interest	1			1			2			1
Total other expense	(17		)	(17		)	(34		)	(34		)
INCOME BEFORE INCOME TAXES	62			59			114			111
INCOME TAXES	21			18			42			38
NET INCOME	$	41		$	41		$	72		$	73
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	41		$	41		$	72		$	73
OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(7		)	(7		)	(17		)	(15		)
Change in unrealized gain on available-for-sale securities	—			2			—			2
Other comprehensive loss	(7		)	(5		)	(17		)	(13		)
Income tax benefits on other comprehensive loss	(4		)	(3		)	(9		)	(7		)
Other comprehensive loss, net of tax	(3		)	(2		)	(8		)	(6		)
COMPREHENSIVE INCOME	$	38		$	39		$	64		$	67

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)	June 30, 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	173			163
Affiliated companies	51			86
Other	15			41
Notes receivable from affiliated companies	245			181
Prepayments and other	14			17
	498			514
UTILITY PLANT:
In service	3,443			3,358
Less — Accumulated provision for depreciation	1,294			1,267
	2,149			2,091
Construction work in progress	87			91
	2,236			2,182
OTHER PROPERTY AND INVESTMENTS:
Investment in lease obligation bonds	148			163
Nuclear plant decommissioning trusts	141			137
Other	91			90
	380			390
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	340			363
Property taxes	80			81
Unamortized sale and leaseback costs	23			25
Other	23			19
	466			488
	$	3,580		$	3,574
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	3		$	2
Accounts payable-
Affiliated companies	90			119
Other	37			35
Accrued taxes	76			88
Accrued interest	28			25
Other	69			79
	303			348
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 175,000,000 shares – 60 shares outstanding	721			747
Accumulated other comprehensive income	46			54
Accumulated deficit	(12		)	(84		)
Total common stockholder's equity	755			717
Noncontrolling interest	5			5
Total equity	760			722
Long-term debt and other long-term obligations	1,157			1,155
	1,917			1,877
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	799			787
Retirement benefits	211			213
Asset retirement obligations	74			71
Other	276			278
	1,360			1,349
COMMITMENTS AND CONTINGENCIES (Note 9)
	$	3,580		$	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)

	Six Months Ended June 30
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	72		$	73
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	49			46
Amortization of regulatory assets, net	15			3
Amortization of lease costs	(5		)	(5		)
Deferred income taxes and investment tax credits, net	22			66
Accrued compensation and retirement benefits	(26		)	(18		)
Pension trust contribution	—			(27		)
Decrease (increase) in operating assets-
Receivables	54			81
Prepayments and other current assets	3			(29		)
Decrease in operating liabilities-
Accounts payable	(27		)	(22		)
Accrued taxes	(12		)	(9		)
Accrued interest	3			—
Other	(2		)	(9		)
Net cash provided from operating activities	146			150
CASH FLOWS FROM FINANCING ACTIVITIES:
Redemptions and Repayments-
Long-term debt	(1		)	(1		)
Short-term borrowings, net	—			(142		)
Common stock dividend payments	(25		)	(268		)
Other	(1		)	(2		)
Net cash used for financing activities	(27		)	(413		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(86		)	(79		)
Sales of investment securities held in trusts	57			20
Purchases of investment securities held in trusts	(62		)	(25		)
Loans to affiliated companies, net	(63		)	(79		)
Cash investments	13			12
Other	(4		)	(6		)
Net cash used for investing activities	(145		)	(157		)
Net change in cash and cash equivalents	(26		)	(420		)
Cash and cash equivalents at beginning of period	26			420
Cash and cash equivalents at end of period	$	—		$	—

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 June 30						Six Months Ended June 30
(In millions)	2012			2011			2012			2011
STATEMENTS OF INCOME
REVENUES:
Electric sales	$	476		$	577		$	954		$	1,211
Excise tax collections	8			11			18			24
Total revenues	484			588			972			1,235
OPERATING EXPENSES:
Purchased power	254			328			518			698
Other operating expenses	81			73			162			153
Provision for depreciation	32			28			62			54
Amortization of regulatory assets, net	8			40			28			122
General taxes	12			15			27			33
Total operating expenses	387			484			797			1,060
OPERATING INCOME	97			104			175			175
OTHER INCOME (EXPENSE):
Miscellaneous income	1			3			2			5
Interest expense	(30		)	(31		)	(61		)	(61		)
Capitalized interest	1			1			1			1
Total other expense	(28		)	(27		)	(58		)	(55		)
INCOME BEFORE INCOME TAXES	69			77			117			120
INCOME TAXES	30			32			52			52
NET INCOME	$	39		$	45		$	65		$	68
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	39		$	45		$	65		$	68
OTHER COMPREHENSIVE LOSS:
Pensions and OPEB prior service costs	(6		)	(6		)	(12		)	(12		)
Other comprehensive loss	(6		)	(6		)	(12		)	(12		)
Income tax benefits on other comprehensive loss	(3		)	(3		)	(7		)	(5		)
Other comprehensive loss, net of tax	(3		)	(3		)	(5		)	(7		)
COMPREHENSIVE INCOME	$	36		$	42		$	60		$	61

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)	June 30, 2012		December 31, 2011
ASSETS
CURRENT ASSETS:
Receivables-
Customers, net of allowance for uncollectible accounts of $3 in 2012 and 2011	$	227	$	235
Affiliated companies	12		—
Other	23		17
Prepaid taxes	108		33
Other	22		19
	392		304
UTILITY PLANT:
In service	5,067		4,872
Less — Accumulated provision for depreciation	1,779		1,743
	3,288		3,129
Construction work in progress	125		227
	3,413		3,356
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust	227		219
Nuclear plant decommissioning trusts	196		193
Other	2		2
	425		414
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	1,811		1,811
Regulatory assets	523		408
Other	33		32
	2,367		2,251
	$	6,597	$	6,325
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	35	$	34
Short-term borrowings-
Affiliated companies	338		259
Other	80		—
Accounts payable-
Affiliated companies	16		19
Other	101		101
Accrued compensation and benefits	33		41
Customer deposits	24		24
Accrued interest	18		18
Other	21		36
	666		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	34		39
Retained earnings	136		121
Total common stockholder's equity	2,317		2,307
Long-term debt and other long-term obligations	1,720		1,736
	4,037		4,043
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	917		859
Power purchase contract liability	270		147
Nuclear fuel disposal costs	197		197
Retirement benefits	163		170
Asset retirement obligations	119		115
Other	228		262
	1,894		1,750
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
	$	6,597	$	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)

	Six Months Ended June 30
(In millions)	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	65		$	68
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	62			54
Amortization of regulatory assets, net	28			122
Deferred purchased power and other costs	(75		)	(71		)
Deferred income taxes and investment tax credits, net	64			55
Accrued compensation and retirement benefits	(27		)	(11		)
Pension trust contribution	—			(105		)
Decrease (increase) in operating assets-
Receivables	(10		)	58
Prepaid taxes	(75		)	(125		)
Increase (decrease) in operating liabilities-
Accounts payable	(2		)	14
Accrued taxes	(14		)	(1		)
Other	7			—
Net cash provided from operating activities	23			58
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	159			411
Redemptions and Repayments-
Long-term debt	(16		)	(15		)
Common stock dividend payments	(50		)	(500		)
Other	—			(1		)
Net cash provided from (used for) financing activities	93			(105		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(102		)	(98		)
Loans to affiliated companies, net	—			161
Sales of investment securities held in trusts	165			376
Purchases of investment securities held in trusts	(172		)	(386		)
Other	(7		)	(6		)
Net cash provided from (used for) investing activities	(116		)	47
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	17
5	Variable Interest Entities	17
6	Fair Value Measurements	19
7	Derivative Instruments	28
8	Regulatory Matters	34
9	Commitments, Guarantees and Contingencies	42
10	Supplemental Guarantor Information	49
11	Segment Information	58

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 FET), 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 six months ended June 30, 2011, include just four months 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 six months ended June 30, 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 June 30				Six Months Ended June 30
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2012		2011		2012		2011
	(In millions, except per share amounts)
Weighted average number of basic shares outstanding	417		418		418		380
Assumed exercise of dilutive stock options and awards(1)	2		2		1		2
Weighted average number of diluted shares outstanding	419		420		419		382
Earnings Available to FirstEnergy Corp.	$	187	$	203	$	493	$	255
Basic earnings per share of common stock	$	0.45	$	0.48	$	1.18	$	0.67
Diluted earnings per share of common stock	$	0.45	$	0.48	$	1.18	$	0.67

⁽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 and six months ended June 30, 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 six months ended June 30, 2012, FirstEnergy made a voluntary $600 million pre-tax contribution to its qualified pension plan.

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 June 30,	2012			2011			2012			2011
	(In millions)
Service cost	$	40		$	34		$	3		$	3
Interest cost	97			96			12			12
Expected return on plan assets	(121		)	(115		)	(9		)	(10		)
Amortization of prior service cost	3			4			(51		)	(51		)
Other adjustments (settlements, curtailments, etc)	—			—			—			—
Net periodic costs (credits)	$	19		$	19		$	(45	)	$	(46	)

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Six Months Ended June 30,	2012			2011			2012			2011
	(In millions)
Service cost	$	80		$	63		$	6		$	6
Interest cost	194			180			24			23
Expected return on plan assets	(242		)	(217		)	(18		)	(20		)
Amortization of prior service cost	6			8			(102		)	(99		)
Other adjustments (settlements, curtailments, etc)	—			7			—			—
Net periodic costs (credits)	$	38		$	41		$	(90	)	$	(90	)

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:

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Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended June 30,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	14		$	14		$	(32	)	$	(34	)
FES	11			7			(8		)	(9		)
OE	(1		)	(2		)	(6		)	(5		)
JCP&L	(2		)	(3		)	(2		)	(2		)

Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Six Months Ended June 30,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	27		$	34		$	(62	)	$	(66	)
FES	21			14			(16		)	(16		)
OE	(2		)	(4		)	(11		)	(11		)
JCP&L	(3		)	(5		)	(4		)	(5		)

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 second quarter of 2012, FirstEnergy reached a settlement with state authorities related to state apportionment factors in Pennsylvania on an intercompany asset sale, which favorably affected FirstEnergy's effective tax rate by $3 million in the three and six months ended June 30, 2012. Earlier in the year, 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 the 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 for the first six months of 2012. In the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy's effective tax rate in the three and six months ended June 30, 2011.

As of June 30, 2012, it is reasonably possible that approximately $42 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $7 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 six months of 2012 there were no material changes to the amount of accrued interest. The interest associated with the settlement of the claim in 2011 noted above favorably affected FirstEnergy's effective tax rate by $6 million in the first six months of 2011. During the first six months of 2011, there were no other 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 June 30, 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 $28 million in the first six 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 2009 and 2010. 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

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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 second 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 $262 million was outstanding as of June 30, 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 $503 million was outstanding as of June 30, 2012.

The caption noncontrolling interest within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. The change in noncontrolling interest within the Consolidated Balance Sheets during the six months ended June 30, 2012, was primarily due to net income attributable to noncontrolling interests of $1 million, offset by a $5 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 $31 million as of June 30, 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 21 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 ended June 30, 2012, were $14 million, $27 million and $17 million for JCP&L, PE and WP, respectively and $26 million, $59 million and $33 million for the six months ended June 30, 2012, 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 ended June 30, 2011, were $55 million, $47 million, and $21 million, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, respectively.

In 1998 the PPUC issued an order approving a transition plan for WP that disallowed certain costs, including an estimated amount

18

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 June 30, 2012, WP’s reserve for this adverse purchase power commitment was $48 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 June 30, 2012:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,318	$	1,111	$	207
OE	574		384		190
Other FE subsidiaries	599		333		266

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.5 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 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.

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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 quarterly basis, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. 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.

LCAPP contracts are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. LCAPP contracts are recorded at fair value using a mark-to-model methodology on a quarterly basis, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Quarterly pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices for the 2015/2016 delivery year and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2015/2016 delivery year are developed through a simulation of future PJM RPM auctions. The capacity price forecast assumes a continuation of the current PJM RPM market design and is reflective of the regional peak demand growth and generation fleet additions and retirements that underlie FirstEnergy’s long-term energy price forecast. 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 June 30, 2012 from those used as of 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 transfers between levels during the six months ended June 30, 2012. The following tables set forth the recurring 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	June 30, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,636		$	—		1,636			$	—	$	1,544		$	—		$	1,544
Derivative assets - commodity contracts	4			337			—			341			—		264			—			264
Derivative assets - FTRs	—			—			12			12			—		—			1			1
Derivative assets - interest rate swaps	—			3			—			3			—		—			—			—
Derivative assets - NUG contracts(1)	—			—			9			9			—		—			56			56
Equity securities(2)	280			—			—			280			259		—			—			259
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			144			—			144			—		148			—			148
U.S. state debt securities	—			308			—			308			—		314			—			314
Other(3)	63			128			—			191			49		225			—			274
Total assets	347			2,556			21			2,924			308		2,498			57			2,863
Liabilities
Derivative liabilities - commodity contracts	(1		)	(262		)	—			(263		)	—		(247		)	—			(247		)
Derivative liabilities - FTRs	—			—			(9		)	(9		)	—		—			(23		)	(23		)
Derivative liabilities - interest rate swaps	—			(23		)	—			(23		)	—		—			—			—
Derivative liabilities - NUG contracts(1)	—			—			(302		)	(302		)	—		—			(349		)	(349		)
Derivative liabilities - LCAPP contracts(1)	—			—			(145		)	(145		)	—		—			—			—
Total liabilities	(1		)	(285		)	(456		)	(742		)	—		(247		)	(372		)	(619		)
Net assets (liabilities)(4)	$	346		$	2,271		$	(435	)	$	2,182		$	308	$	2,251		$	(315	)	$	2,244

⁽¹⁾  NUG and LCAPP contracts are generally subject to regulatory accounting treatment 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 $(7) million and $(52) million as of June 30, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with 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 NUG and LCAPP contracts held by certain Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:

	NUG Contracts(1)									LCAPP Contracts(1)								FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
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)	(48		)	(86		)	(134		)	—		—			—			—			(2		)	(2		)
Purchases	—			—			—			—		(145		)	(145		)	12			(9		)	3
Issues	—			—			—			—		—			—			—			—			—
Sales	—			—			—			—		—			—			—			—			—
Settlements	—			133			133			—		—			—			(1		)	25			24
Transfers in (out) of Level 3	—			—			—			—		—			—			—			—			—
June 30, 2012 Balance	$	9		$	(302	)	$	(293	)	$	—	$	(145	)	$	(145	)	$	12		$	(9	)	$	3

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

Level 3 Quantitative Information

The following table provides quantitative information for FTRs, NUG contracts and LCAPP contracts that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	3		Model	RTO auction clearing prices	($3.60) to $4.90	$	0.70	Dollars/MWH
NUG Contracts	$	(293	)	Model	Generation Electricity regional prices	500 to 6,609,000 $49.50 to $84.90	2,665,000 $63.70		MWH Dollars/MWH
LCAPP Contracts	$	(145	)	Model	Regional capacity prices	$94.90 to $248.40	$183.90		Dollars/MW-Day

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FES
Recurring Fair Value Measurements	June 30, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,057		$	—		$	1,057		$	—	$	1,010		$	—		$	1,010
Derivative assets - commodity contracts	4			326			—			330			—		248			—			248
Derivative assets - FTRs	—			—			8			8			—		—			1			1
Equity securities(1)	145			—			—			145			124		—			—			124
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			6			—			6			—		7			—			7
U.S. state debt securities	—			—			—			—			—		5			—			5
Other(2)	—			48			—			48			—		132			—			132
Total assets	149			1,437			8			1,594			124		1,405			1			1,530
Liabilities
Derivative liabilities - commodity contracts	(1		)	(262		)	—			(263		)	—		(234		)	—			(234		)
Derivative liabilities - FTRs	—			—			(6		)	(6		)	—		—			(7		)	(7		)
Total liabilities	(1		)	(262		)	(6		)	(269		)	—		(234		)	(7		)	(241		)
Net assets (liabilities)(3)	$	148		$	1,175		$	2		$	1,325		$	124	$	1,171		$	(6	)	$	1,289

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

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

⁽³⁾  Excludes $(6) million and $(58) million as of June 30, 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 June 30, 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	8			(7		)	1
Issues	—			—			—
Sales	—			—			—
Settlements	(1		)	9			8
Transfers in (out) of Level 3	—			—			—
June 30, 2012 Balance	$	8		$	(6	)	$	2

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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 June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)		Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	2	Model	RTO auction clearing prices	($3.60) to $4.90	$0.50	Dollars/MWH

OE
Recurring Fair Value Measurements	June 30, 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	—		138		—		138		—		132		—		132
Other(1)	—		3		—		3		—		2		—		2
Total assets(2)	$	—	$	141	$	—	$	141	$	—	$	137	$	—	$	137

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

⁽²⁾  Excludes $1 million as of June 30, 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	June 30, 2012										December 31, 2011
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	149	$	—		$	149		$	—	$	144	$	—		$	144
Derivative assets - NUG contracts(1)	—		—		4			4			—		—		4			4
Equity securities(2)	30		—		—			30			30		—		—			30
U.S. government debt securities	—		—		—			—			—		2		—			2
U.S. state debt securities	—		223		—			223			—		219		—			219
Other(3)	—		19		—			19			—		15		—			15
Total assets	30		391		4			425			30		380		4			414
Liabilities
Derivative liabilities - NUG contracts(1)	—		—		(125		)	(125		)	—		—		(147		)	(147		)
Derivative liabilities - LCAPP contracts(1)	—		—		(145		)	(145		)	—		—		—			—
Total liabilities	—		—		(270		)	(270		)	—		—		(147		)	(147		)
Net assets (liabilities)(4)	$	30	$	391	$	(266	)	$	155		$	30	$	380	$	(143	)	$	267

⁽¹⁾  NUG and LCAPP contracts are subject to regulatory accounting treatment 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 June 30, 2012 and December 31, 2011 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 NUG and LCAPP contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:

	NUG Contracts(1)									LCAPP Contracts(1)
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net
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 Balance	$	4		$	(147	)	$	(143	)	$	—	$	—		$	—
Realized gain (loss)	—			—			—			—		—			—
Unrealized gain (loss)	—			(7		)	(7		)	—		—			—
Purchases	—			—			—			—		(145		)	(145		)
Issues	—			—			—			—		—			—
Sales	—			—			—			—		—			—
Settlements	—			29			29			—		—			—
Transfers in (out) of Level 3	—			—			—			—		—			—
June 30, 2012 Balance	$	4		$	(125	)	$	(121	)	$	—	$	(145	)	$	(145	)

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

Level 3 Quantitative Information

The following table provides quantitative information for NUG and LCAPP contracts held by JCP&L that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
NUG Contracts	$	(121	)	Model	Generation Electricity regional prices	63,000 to 715,000 $49.50 to $84.90	166,000 $65.80	MWH Dollars/MWH
LCAPP Contracts	$	(145	)	Model	Regional capacity prices	$94.90 to $248.40	$183.90	Dollars/MW-Day

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,

25

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 June 30, 2012 and December 31, 2011:

	June 30, 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	$	2,032	$	52	$	—	$	2,084	$	1,980	$	25	25	$	—	—	$	2,005
FES	1,034		29		—		1,063		1,012		13			—			1,025
OE	138		—		—		138		134		—			—			134
JCP&L	358		12		—		370		356		7			—			363
Equity securities
FE Consolidated	$	243	$	36	$	—	$	279	$	222	$	36		$	—		$	258
FES	125		19		—		144		104		20			—			124
JCP&L	27		3		—		30		27		3			—			30

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $113 million; FES - $42 million; OE - $3 million; JCP&L - $23 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 and six months ended June 30, 2012 and 2011 were as follows:

Three Months Ended
June 30, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	131	$	17	$	(18	)	$	18
FES	25		13		(14		)	11
OE	20		—		—			1
JCP&L	70		1		(1		)	3
June 30, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	734	$	22	$	(16	)	$	28
FES	297		10		(7		)	17
OE	12		—		—			1
JCP&L	159		4		(2		)	4

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Six Months Ended
June 30, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	382	$	37	$	(35	)	$	33
FES	109		26		(25		)	18
OE	57		—		—			1
JCP&L	165		2		(2		)	7
June 30, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	1,703	$	122	$	(45	)	$	52
FES	513		22		(23		)	32
OE	20		—		—			2
JCP&L	376		26		(6		)	8

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 June 30, 2012 and December 31, 2011:

	June 30, 2012						December 31, 2011
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FE Consolidated	$	326	$	55	$	381	$	402	$	50	$	452
OE	148		32		180		163		21		184

Investments in emission allowances, employee benefit trusts and cost and equity method investments totaling $716 million as of June 30, 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 in "Short-term borrowings" on the Consolidated Balance Sheets at cost, which approximates their fair market value. 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 June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FE Consolidated	$	16,571	$	18,998	$	17,165	$	19,320
FES	3,617		3,862		3,675		3,931
OE	1,157		1,493		1,157		1,434
JCP&L	1,762		2,076		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 June 30, 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.

Total net unamortized gains included in AOCI associated with de-designated cash flow hedges totaled $15 million and $19 million as of June 30, 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 $1 million and $14 million during the three months ended June 30, 2012 and 2011, respectively, and $4 million and $19 million during the six months ended June 30, 2012 and 2011, respectively. Approximately $9 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 June 30, 2012, no forward starting swap agreements accounted for as a cash flow hedge were outstanding. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $74 million as of June 30, 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 June 30, 2012 and 2011, respectively, and $5 million and $6 million during the six months ended June 30, 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 June 30, 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 $91 million as of June 30, 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 during the three months ended June 30, 2012 and 2011, and $11 million during the six months ended June 30, 2012 and 2011.

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 June 30, 2012, FirstEnergy’s net asset position under commodity derivative contracts was $78 million, which related to FES and AE Supply positions. Under these commodity derivative contracts, FES posted $34 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $12 million of additional collateral

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if the credit rating for its debt were to fall below investment grade.

Based on commodity derivative contracts held as of June 30, 2012, an adverse 10% change in commodity prices would decrease net income by approximately $2 million during the next twelve months.

Interest Rate Swaps

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are considered economic hedges, protecting against the risk of increases in future interest payments resulting from increases in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the three months ended June 30, 2012, FirstEnergy executed forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties for a combined notional value of $1.6 billion in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%. Changes in the fair value of the forward starting swap agreements are recorded in net income on a mark-to-market basis.

LCAPP

The LCAPP law was enacted in New Jersey during 2011 to promote the construction of qualified electric generation facilities. JCP&L maintains two LCAPP contracts, which are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. During the second quarter of 2012, JCP&L began to account for these contracts as derivatives as a result of the generators clearing the 2015/2016 PJM RPM capacity auction. JCP&L expects to recover from its customers payments made to the generators and give credit to customers for payments from the generators under these contracts. As a result, the projected future obligations for the LCAPP contracts are reflected on the Consolidated Balance Sheets as derivative liabilities (assets) with a corresponding regulatory asset (liability). Since the LCAPP contracts are subject to regulatory accounting, changes in their fair value do not impact earnings.

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.

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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
	June 30, 2012		December 31, 2011			June 30, 2012			December 31, 2011
	(In millions)					(In millions)
Power Contracts					Power Contracts
Current Assets	$	232	$	185	Current Liabilities	$	(213	)	$	(196	)
Noncurrent Assets	106		79		Noncurrent Liabilities	(49		)	(51		)
FTRs					FTRs
Current Assets	12		1		Current Liabilities	(8		)	(22		)
Noncurrent Assets	—		—		Noncurrent Liabilities	(1		)	(1		)
NUGs	9		56		NUGs	(302		)	(349		)
LCAPP	—		—		LCAPP	(145		)	—
Interest Rate Swaps					Interest Rate Swaps
Noncurrent Assets	3		—		Noncurrent Liabilities	(23		)	—
Other					Other
Current Assets	4		—		Current Liabilities	(1		)	—
	$	366	$	321		$	(742	)	$	(619	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2012:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	29	40	(11	)	MWH
FTRs	82	—	82		MWH
Interest Rate Swaps	1,600	—	1,600		notional dollars
NUGs	22	—	22		MWH
LCAPP	408	—	408		MW
Natural Gas	26	—	26		Million BTUs

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The effect of derivative instruments on the Consolidated Statements of Income during the three months ended June 30, 2012 and 2011, are summarized in the following tables:

	Three Months Ended June 30
	Power Contracts			FTRs			Interest Rate Swaps			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	1		$	—		$	—		$	—		$	1
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	14		$	—		$	—		$	—		$	14
Derivatives Not in a Hedging Relationship
2012
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	7		$	12		$	—		$	5		$	24
Interest Expense	—			—			(20		)	—			(20		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(104	)	$	—		$	—		$	—		$	(104	)
Revenues	95			5			—			—			100
Other Operating Expense	—			(18		)	—			—			(18		)
Fuel Expense	—			—			—			(1		)	(1		)
Interest Expense	—			—			—			—			—
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	33		$	—		$	—		$	—		$	33
Revenues	(4		)	—			—			—			(4		)
Other Operating Expense	(34		)	11			—			—			(23		)
Interest Expense	—			—			—			—			—
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	1		$	—		$	—		$	—		$	1
Revenues	(39		)	13			—			—			(26		)
Other Operating Expense	—			(40		)	—			—			(40		)
Interest Expense	—			—			—			—			—

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	Six Months Ended June 30
	Power Contracts			FTRs			Interest Rate Swaps			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(4	)	$	—		$	—		$	—		$	(4	)
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	5		$	—		$	—		$	—		$	5
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:
Other Operating Expense	$	62		$	17		$	—		$	3		$	82
Interest Expense	—			—			(20		)	—			(20		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(221	)	$	—		$	—		$	—		$	(221	)
Revenues	206			11			—			—			217
Other Operating Expense	—			(41		)	—			—			(41		)
Fuel Expense	—			—			—			(1		)	(1		)
Interest Expense	—			—			—			—			—
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	61		$	—		$	—		$	—		$	61
Revenues	(3		)	—			—			—			(3		)
Other Operating Expense	(54		)	12			1			—			(41		)
Interest Expense	—			—			—			—			—
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(36	)	$	—		$	—		$	—		$	(36	)
Revenues	(29		)	16			(1		)	—			(14		)
Other Operating Expense	—			(54		)	—			—			(54		)
Interest Expense	—			—			—			—			—

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The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and six months ended June 30, 2012 and 2011, are summarized in the following tables:

	Three Months Ended June 30
	NUGs			LCAPP			Regulated FTRs		Other		Total
	(In millions)
Derivatives Not in a Hedging Relationship with Regulatory Offset
2012
Unrealized Gain (Loss) to Derivative Instrument	$	(54	)	$	(145	)	$	—	$	—	$	(199	)
Realized Gain (Loss) to Derivative Instrument	61			—			5		—		66
2011
Unrealized Gain (Loss) to Derivative Instrument	$	(147	)	$	—		$	2	$	—	$	(145	)
Realized Gain (Loss) to Derivative Instrument	62			—			—		—		62

	Six Months Ended June 30
	NUGs			LCAPP			Regulated FTRs			Other		Total
	(In millions)
Derivatives Not in a Hedging Relationship with Regulatory Offset
2012
Unrealized Gain (Loss) to Derivative Instrument	$	(133	)	$	(145	)	$	(1	)	$	—	$	(279	)
Realized Gain (Loss) to Derivative Instrument	133			—			9			—		142
2011
Unrealized Gain (Loss) to Derivative Instrument	$	(236	)	$	—		$	2		$	—	$	(234	)
Realized Gain (Loss) to Derivative Instrument	134			—			(10		)	—		124

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 and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			LCAPP			Regulated FTRs			Other		Total
	(In millions)
Outstanding net asset (liability) as of April 1, 2012	$	(300	)	$	—		$	(5	)	$	—	$	(305	)
Additions/Change in value of existing contracts	(54		)	(145		)	—			—		(199		)
Settled contracts	61			—			5			—		66
Outstanding net asset (liability) as of June 30, 2012	$	(293	)	$	(145	)	$	—		$	—	$	(438	)
Outstanding net asset (liability) as of April 1, 2011	$	(362	)	$	—		$	—		$	—	$	(362	)
Additions/Change in value of existing contracts	(147		)	—			2			—		(145		)
Settled contracts	62			—			—			—		62
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	—		$	2		$	—	$	(445	)

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	Six Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			LCAPP			Regulated FTRs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2012	$	(293	)	$	—		$	(8	)	$	—		$	(301	)
Additions/Change in value of existing contracts	(133		)	(145		)	(1		)	—			(279		)
Settled contracts	133			—			9			—			142
Outstanding net asset (liability) as of June 30, 2012	$	(293	)	$	(145	)	$	—		$	—		$	(438	)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	—		$	—		$	10		$	(335	)
Additions/Change in value of existing contracts	(236		)	—			2			—			(234		)
Settled contracts	134			—			—			(10		)	124
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	—		$	2		$	—		$	(445	)

⁽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.

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, on August 31, 2011, PE filed a new comprehensive plan that includes additional and improved programs for the period 2012-2014.The plan is expected to cost approximately$66 millionover the three-year period.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

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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.In its written Order issued July 31, 2012, affirming the determination made at its July 18, 2012 agenda meeting, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year on or before November 1, 2012. JCP&L is unable to predict the outcome of this matter.

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 August 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.

On April 13, 2012, the Ohio Companies filed an application with the PUCO to essentially extend the terms of their current ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012.

As approved, the ESP 3 plan will 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 power to shopping and to non-shopping customers as part of the 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 approved, the ESP 3 plan will provide additional new benefits, including:

• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, 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 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.

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).Sevenadditional parties agreed not to oppose the filing.

Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total

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annual energy savings equivalent of approximately1,211GWHs in 2012 (an increase of416,000MWHs over 2011 levels),1,726GWHs in 2013,2,306GWHs in 2014 and2,903GWHs for each year thereafter 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 intended to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. In March 2011, the PUCO issued an Opinion and Order generally approving the Ohio Companies' 2010-2012 portfolio plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies have implemented those programs included in the plan. However, due to the timing of the approval of the plan, the Ohio Companies requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks for 2010. 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 because they achieved their targets in that year. 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.

The Ohio Companies had filed applications for rehearing regarding portions of the PUCO's decision related to the Ohio Companies'three-year portfolio plan, which was later denied. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, which was dismissed on June 20, 2012. In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their next three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.

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 management audit, and final audit reports are currently scheduled to be filed with the PUCO on August 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, the Pennsylvania Companies filed a Joint Petition for Approval of their DSP that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2013 through May 31, 2015.The ALJ issued a Recommended Decision on June 15, 2012, that supported adoption of the Pennsylvania Companies' proposed wholesale procurement plans, denial of their proposed Market Adjustment Charge, and various modifications to the proposed competitive enhancements. Exceptions to the Recommended Decision are currently pending.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.On June 27, 2012, ME and PN filed a Petition for Writ of Certiorari with the Supreme Court of the United States. The PPUC's brief in opposition is due on August 31, 2012, and the ME/PE reply is due on September 10, 2012. If the Supreme Court declines to take the case then ME and PE will pursue their claims in the proceedings that are pending in the U.S. District Court (E.D. PA).

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

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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.The PPUC entered an order on May 10, 2012 approving the Joint Settlement.

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 by the end of 2012, or in a future base distribution rate case.The deadline for the Pennsylvania Companies to file their smart meter deployment plan is December 31, 2012.

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.Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on April 26, 2012, on the proposed rulemaking, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of

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evidence demonstrating a need for them.

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 West Virginia Supreme Court issued an Order on June 11, 2012, upholding the WVPSC's decision.

The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC alleging the WVPSC order violated PURPA and requested FERC initiate an enforcement action. 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.FERC also noted there may be language in the WVPSC decision that is inconsistent with PURPA. MP filed for rehearing of the FERC's order taking the position that the WVPSC order is consistent with PURPA. New Martinsville filed a complaint in the U.S. District Court on June 4, 2012, alleging that the WVPSC order violates PURPA.

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 deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.

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

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(transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up toelevenhours. 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 expects the matter to be resolved for an immaterial amount.

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 advocated 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.

Order No. 1000 issued by FERC on July 21, 2011, requires the submission of a compliance filing in October 2012 by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfies the principles set forth in the order. The PJM transmission owners have announced their intention to submit a compliance filing based on a hybrid methodology of 50% beneficiary pays and 50% postage stamp (or socialization) to be effective for projects approved by the PJM Board on and after the effective date of the compliance filing. FirstEnergy is working with other PJM transmission owners to develop the required filing based on this proposed methodology.

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 FirstEnergy) 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 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

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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 with briefs due from the parties through 2012 and oral argument to be scheduled in 2013.

In February 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.FERC also set for hearing the question of whether it is just and reasonable for ATSI to pay the Michigan Thumb project costs and, if so, the amount of and methodology for calculating ATSI's Michigan Thumb project cost responsibility.On March 28, 2012, FirstEnergy filed for clarification and rehearing of the February 2012 Order, and such request is pending before the FERC.On July 10, 2012, a prehearing conference was convened before a FERC ALJ who will determine the scope of the hearing and thereafter set the hearing schedule.

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 million ($0.5 million - FES; $34.5 million - AE Supply) in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year are estimated to be approximately$11.5 million($11.4 million- FES;$0.1 million- AE Supply).

On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue.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.On July 19, 2012, FERC issued its Order on Rehearing and again dismissed FirstEnergy's complaint without prejudice. FERC noted PJM's ongoing stakeholder process and directed that if the issues were not addressed in that process FirstEnergy could file its complaint again.

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. Exelon Corporation filed a protest, and several other parties filed comments.On July 11, 2012, FERC issued its Order Granting Complaint and Requiring a Compliance Filing. In the order, FERC agreed with FirstEnergy's description of the issues and with FirstEnergy's proposed changes to PJM's rules, and FERC directed PJM to submit a compliance filing within 60 days to implement the changes in the rules.

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

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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.By Order issued June 13, 2012, FERC denied the request for rehearing. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals.

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 additional 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.By Order issued June 13, 2012, that request for rehearing also was denied. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals. 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.The PJM Board has directed the PJM staff to perform additional analysis using the 2012 RTEP assumptions and incorporating the results of the May 2012 RPM base residual auction. The PJM staff is expected to report its conclusions from this analysis to the Transmission Expansion Advisory Committee on August 9, 2012. All applications for authorization to construct the project filed with state commissions have been withdrawn.

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

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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.

MISO Capacity Portability

On June 11, 2012, the FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO Stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. Comments are due on August 10, 2012, and reply comments are due on August 27, 2012. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including the prices at which those auctions would clear. FirstEnergy anticipates submitting initial comments by August 10, 2012 and, depending on the comments submitted by other parties, submitting reply comments by August 27, 2012.

9. COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.

As of June 30, 2012, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting of parental guarantees ($0.9 billion), subsidiaries' guarantees ($2.4 billion) and other guarantees ($0.7 billion).

Of this amount, substantially all relates to guarantees of wholly-owned consolidated entities. 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.

COLLATERAL AND CONTINGENT-RELATED FEATURES

As part of the normal course of business, FirstEnergy and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuels, and emissions allowances. Certain bilateral agreements and derivative instruments contain provisions that require FirstEnergy or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FirstEnergy's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.

Bilateral agreements and derivative instruments entered into by FirstEnergy and its subsidiaries have margining provisions that require posting of collateral.Based on FES' and AE Supply's power portfolio exposure as ofJune 30, 2012, FES has posted collateral of$36 million. The Regulated Distribution segment has posted collateral of$9 million.

These credit-risk-related contingent features stipulate that if the subsidiaries were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

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 FirstEnergy or its

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subsidiaries.The following chart discloses the additional credit contingent contractual obligations as ofJune 30, 2012:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	373	$	6	$	40	$	419
BB+/Ba1 Credit Ratings	$	429	$	6	$	59	$	494
Full impact of credit contingent contractual obligations	$	658	$	73	$	73	$	804

Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Segment.As ofJune 30, 2012neither 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$46 millionand$13 million, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

Signal Peak and Global Rail are borrowers under a$350 millionsyndicated 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, continued to guarantee the borrowers' obligations under the current facility. 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.Global Holding is involved in negotiations to refinance the current facility with a bank facility under which it would be the borrower. In connection with such proposed refinancing, FirstEnergy expects to provide the new lenders with a guarantee of Global Holding's obligations, and FirstEnergy and WMB Marketing Ventures, LLC expect to pledge not less than two-thirds of the equity interests in Global Holding and its subsidiaries.

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.On July 27, 2012, FirstEnergy filed a motion for summary judgment arguing the Plaintiff's remaining claims for civil penalties are barred by the statute of limitations. 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

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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. On June 29, 2012, EPA issued another CAA section 114 request for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. 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 June 12, 2012, the EPA revised certain CSAPR 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.

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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 deactivation 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.MATS has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. FirstEnergy and other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS.Depending on the outcome of these proceedings and how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS is estimated to be$975 millionand 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 system832megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. However, when these units did not clear the May PJM capacity auction, the decision was made to not proceed with the project at this time. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant deactivations and requested RMR arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18.On July 10, 2012, FirstEnergy filed with FERC, for informational purposes, the compensation arrangements for these units which will remain in effect for as long as these generating units continue to operate. On July 16, 2012, FGCO and ATSI filed an application with FERC for authorization to transfer from FGCO to ATSI certain assets associated with Eastlake Units 1-5 and Lakeshore Unit 18 for conversion to synchronous condensers by ATSI for transmission reliability purposes as directed by PJM. Upon FERC approval, it is expected that the assets will be transferred in staggered closings when the units are no longer needed for RMR purposes. During the three months and six months ended June 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately$10 million($6 million by FES) and $17 million ($10 million by FES), respectively, as a result of the deactivations. These costs are included in "other operating expenses" in the Consolidated Statements of Income.

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 deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates 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, South Africa, established a negotiating process to develop a new

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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 U.S. 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. In July 2012, the period for finalizing the Section 316(b) regulation was extendedto July 27, 2013.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 June 5, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil liability claims for those petroleum spills toJanuary 31, 2013. 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 proposed settlement, in the form of a Consent Decree, was lodged with the Commonwealth Court of Pennsylvania and published in the June 23, 2012, Pennsylvania Bulletin for a 30-day public comment period. 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

46

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 setting deadlines for MP to meet certain of the effluent limits that were 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. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a 60-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. 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 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.

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.On July 27, 2012, the PA DEP filed a complaint against FGCO in the U.S. District Court for the Western District of Pennsylvania with claims under the Resource Conservation and Recovery Act and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FGCO to resolve those claims. The Consent Decree will be published to allow for a 30-day public comment period and requires FGCO to conduct monitoring, studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. BMP is pursuing several options for disposal of CCB following December 31, 2016.

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 ofJune 30, 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$122 million(including$86 millionapplicable to JCP&L) have been accrued throughJune 30, 2012. Included in the total are accrued liabilities of approximately$79 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 ofJune 30, 2012, FirstEnergy had approximately$2 billioninvested 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

47

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 intervenors supplemented their petition for a contention on the shield building on multiple occasions. On July 9, 2012, the intervenors petitioned the ASLB for a new contention on the environmental impacts of temporary spent fuel storage at Davis-Besse due to the lack of a repository and the disposal of these wastes. The ASLB has yet to rule on the admission of these latest requests for new contentions.

Similarly, on June 18 and 19, 2012, the intervenors in the Davis-Besse license renewal proceeding and other petitioners requested that the NRC suspends the issuance of final decisions in all pending reactor licensing proceedings as a result of the decision in the case of State of New York v. NRC, No. 11-1045. (D.C. Cir. June 8, 2012). In this case, the D.C. Circuit vacated the NRC's updated Waste Confidence Decision and its Temporary Storage Rule and remanded those rulemakings to the NRC for further consideration. FENOC and other Licensees opposed the suspension request. By order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the D.C. Circuit decision and all pending contentions on this topic should be held in abeyance until further order. The NRC also directed that all licensing reviews and proceedings should continue to move forward.

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.On June 21, 2012, the NRC issued an Inspection Report that concluded that FENOC established a sufficient basis for the causes of the shield building laminar cracking.

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. Additional adverse findings by the NRC could result in further inspection activities.

On March 12, 2012, the NRC 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

48

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 has concluded and an oral argument was held on May 16, 2012. A decision from the Appellate court is expected in the fourth quarter of 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.

10. SUPPLEMENTAL GUARANTOR INFORMATION

In 2007, FGCO completed a sale and leaseback transaction for its 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 and six months ended June 30, 2012 and 2011, Consolidating Balance Sheets as of June 30, 2012 and December 31, 2011, and Consolidating Statements of Cash Flows for the six months ended June 30, 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.

49

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,430		$	636		$	473		$	(1,083	)	$	1,456
OPERATING EXPENSES:
Fuel	—			336			44			—			380
Purchased power from affiliates	1,156			—			60			(1,083		)	133
Purchased power from non-affiliates	434			—			—			—			434
Other operating expenses	107			100			172			14			393
Provision for depreciation	1			30			39			(1		)	69
General taxes	20			8			4			—			32
Total operating expenses	1,718			474			319			(1,070		)	1,441
OPERATING INCOME (LOSS)	(288		)	162			154			(13		)	15
OTHER INCOME (EXPENSE):
Investment income	—			5			7			(6		)	6
Miscellaneous income, including net income from equity investees	279			19			—			(278		)	20
Interest expense — affiliates	(5		)	(2		)	(1		)	6			(2		)
Interest expense — other	(24		)	(26		)	(14		)	16			(48		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	250			(3		)	—			(262		)	(15		)
INCOME (LOSS) BEFORE INCOME TAXES	(38		)	159			154			(275		)	—
INCOME TAXES (BENEFITS)	(37		)	(7		)	42			3			1
NET INCOME (LOSS)	$	(1	)	$	166		$	112		$	(278	)	$	(1	)
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	$	(1	)	$	166		$	112		$	(278	)	$	(1	)
OTHER COMPREHENSIVE INCOME:
Pensions and OPEB prior service costs	8			7			—			(7		)	8
Amortized gain on derivative hedges	1			—			—			—			1
Change in unrealized gain on available for sale securities	3			—			3			(3		)	3
Other comprehensive income	12			7			3			(10		)	12
Income taxes on other comprehensive income	2			3			1			(4		)	2
Other comprehensive income, net of tax	10			4			2			(6		)	10
COMPREHENSIVE INCOME	$	9		$	170		$	114		$	(284	)	$	9

50

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Six Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	2,920		$	1,178		$	867		$	(1,993	)	$	2,972
OPERATING EXPENSES:
Fuel	—			576			99			—			675
Purchased power from affiliates	2,121			—			122			(1,993		)	250
Purchased power from non-affiliates	921			—			—			—			921
Other operating expenses	183			192			288			25			688
Provision for depreciation	2			60			73			(3		)	132
General taxes	40			18			11			—			69
Total operating expenses	3,267			846			593			(1,971		)	2,735
OPERATING INCOME (LOSS)	(347		)	332			274			(22		)	237
OTHER INCOME (EXPENSE):
Investment income	1			9			12			(10		)	12
Miscellaneous income, including net income from equity investees	537			19			—			(532		)	24
Interest expense — affiliates	(9		)	(3		)	(2		)	10			(4		)
Interest expense — other	(47		)	(52		)	(21		)	31			(89		)
Capitalized interest	—			2			16			—			18
Total other income (expense)	482			(25		)	5			(501		)	(39		)
INCOME BEFORE INCOME TAXES	135			307			279			(523		)	198
INCOME TAXES (BENEFITS)	14			(8		)	65			6			77
NET INCOME	$	121		$	315		$	214		$	(529	)	$	121
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	121		$	315		$	214		$	(529	)	$	121
OTHER COMPREHENSIVE INCOME
Pensions and OPEB prior service costs	3			3			—			(3		)	3
Amortized loss on derivative hedges	(4		)	—			—			—			(4		)
Change in unrealized gain on available for sale securities	13			—			13			(13		)	13
Other comprehensive income	12			3			13			(16		)	12
Income taxes on other comprehensive income	4			1			5			(6		)	4
Other comprehensive income, net of tax	8			2			8			(10		)	8
COMPREHENSIVE INCOME	$	129		$	317		$	222		$	(539	)	$	129

51

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,275		$	535		$	393		$	(911	)	$	1,292
OPERATING EXPENSES:
Fuel	6			266			44			—			316
Purchased power from affiliates	902			9			65			(911		)	65
Purchased power from non-affiliates	332			(3		)	—			—			329
Other operating expenses	159			108			134			12			413
Provision for depreciation	1			32			37			(1		)	69
General taxes	16			8			6			—			30
Impairment of long-lived assets	—			7			—			—			7
Total operating expenses	1,416			427			286			(900		)	1,229
OPERATING INCOME (LOSS)	(141		)	108			107			(11		)	63
OTHER INCOME (EXPENSE):
Investment income	—			1			15			—			16
Miscellaneous income, including net income from equity investees	132			1			—			(129		)	4
Interest expense — affiliates	—			(1		)	(1		)	—			(2		)
Interest expense — other	(24		)	(28		)	(16		)	16			(52		)
Capitalized interest	—			5			5			—			10
Total other income (expense)	108			(22		)	3			(113		)	(24		)
INCOME (LOSS) BEFORE INCOME TAXES	(33		)	86			110			(124		)	39
INCOME TAXES (BENEFITS)	(62		)	28			41			3			10
NET INCOME	$	29		$	58		$	69		$	(127	)	$	29
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	29		$	58		$	69		$	(127	)	$	29
OTHER COMPREHENSIVE INCOME (LOSS)
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	14			—			—			—			14
Change in unrealized gain on available for sale securities	8			—			8			(8		)	8
Other comprehensive income (loss)	17			(4		)	8			(4		)	17
Income taxes (benefits) on other comprehensive income (loss)	8			(2		)	3			(1		)	8
Other comprehensive income (loss), net of tax	9			(2		)	5			(3		)	9
COMPREHENSIVE INCOME	$	38		$	56		$	74		$	(130	)	$	38

52

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	2,642		$	1,278		$	862		$	(2,098	)	$	2,684
OPERATING EXPENSES:
Fuel	7			560			92			—			659
Purchased power from affiliates	2,087			11			134			(2,098		)	134
Purchased power from non-affiliates	629			(3		)	—			—			626
Other operating expenses	321			219			313			25			878
Provision for depreciation	2			63			76			(3		)	138
General taxes	27			19			14			—			60
Impairment of long-lived assets	—			20			—			—			20
Total operating expenses	3,073			889			629			(2,076		)	2,515
OPERATING INCOME (LOSS)	(431		)	389			233			(22		)	169
OTHER INCOME (EXPENSE):
Investment income	1			1			20			—			22
Miscellaneous income, including net income from equity investees	374			2			—			(368		)	8
Interest expense — affiliates	(1		)	(1		)	(1		)	—			(3		)
Interest expense — other	(48		)	(56		)	(33		)	32			(105		)
Capitalized interest	—			10			10			—			20
Total other income (expense)	326			(44		)	(4		)	(336		)	(58		)
INCOME (LOSS) BEFORE INCOME TAXES	(105		)	345			229			(358		)	111
INCOME TAXES (BENEFITS)	(179		)	125			86			5			37
NET INCOME	$	74		$	220		$	143		$	(363	)	$	74
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	74		$	220		$	143		$	(363	)	$	74
OTHER COMPREHENSIVE INCOME (LOSS)
Pensions and OPEB prior service costs	(9		)	(8		)	—			8			(9		)
Amortized gain on derivative hedges	5			—			—			—			5
Change in unrealized gain on available for sale securities	15			—			15			(15		)	15
Other comprehensive income (loss)	11			(8		)	15			(7		)	11
Income taxes (benefits) on other comprehensive income (loss)	4			(4		)	6			(2		)	4
Other comprehensive income (loss), net of tax	7			(4		)	9			(5		)	7
COMPREHENSIVE INCOME	$	81		$	216		$	152		$	(368	)	$	81

53

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of June 30, 2012	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	457		—		—		—			457
Affiliated companies	464		482		297		(706		)	537
Other	67		25		4		—			96
Notes receivable from affiliated companies	155		1,653		152		(1,732		)	228
Materials and supplies, at average cost	68		272		208		—			548
Derivatives	265		—		—		—			265
Prepayments and other	3		15		1		—			19
	1,479		2,454		662		(2,438		)	2,157
PROPERTY, PLANT AND EQUIPMENT:
In service	89		5,620		6,051		(385		)	11,375
Less — Accumulated provision for depreciation	30		1,872		2,594		(182		)	4,314
	59		3,748		3,457		(203		)	7,061
Construction work in progress	28		187		704		—			919
	87		3,935		4,161		(203		)	7,980
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,250		—			1,250
Investment in affiliated companies	6,241		—		—		(6,241		)	—
Other	—		7		—		—			7
	6,241		7		1,250		(6,241		)	1,257
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		261		—		(261		)	—
Customer intangibles	118				—		—			118
Goodwill	24				—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		4		—		114			118
Derivatives	110				—		—			110
Other	86		160		1		(110		)	137
	338		445		24		(257		)	550
	$	8,145	$	6,841	$	6,097	$	(9,139	)	$	11,944
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	646	$	518	$	(21	)	$	1,144
Short-term borrowings-
Affiliated companies	1,597		135		—		(1,732		)	—
Accounts payable-
Affiliated companies	739		279		305		(715		)	608
Other	173		133		—		—			306
Accrued taxes	23		20		27		(8		)	62
Derivatives	219		—		—		—			219
Other	68		124		13		37			242
	2,820		1,337		863		(2,439		)	2,581
CAPITALIZATION:
Total equity	3,704		3,413		2,810		(6,223		)	3,704
Long-term debt and other long-term obligations	1,482		1,657		580		(1,219		)	2,500
	5,186		5,070		3,390		(7,442		)	6,204
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		909			909
Accumulated deferred income taxes	28		—		572		(164		)	436
Asset retirement obligations	—		29		905		—			934
Retirement benefits	34		145		—		—			179
Lease market valuation liability	—		148		—		—			148
Other	77		112		367		(3		)	553
	139		434		1,844		742			3,159
	$	8,145	$	6,841	$	6,097	$	(9,139	)	$	11,944

54

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	5,700		—		—		(5,700		)	—
Other	—		7		—		—			7
	5,700		7		1,223		(5,700		)	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
	$	7,483	$	6,667	$	5,846	$	(8,177	)	$	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:
Total equity	3,577		3,097		2,587		(5,684		)	3,577
Long-term debt and other long-term obligations	1,483		1,905		641		(1,230		)	2,799
	5,060		5,002		3,228		(6,914		)	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
	$	7,483	$	6,667	$	5,846	$	(8,177	)	$	11,819

55

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Six Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(525	)	$	308		$	446		$	(10	)	$	219
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			52			30			—			82
Short-term borrowings, net	532			46			—			(578		)	—
Redemptions and Repayments-
Long-term debt	—			(63		)	(87		)	10			(140		)
Short-term borrowings, net	—			—			(32		)	32			—
Other	(1		)	(4		)	(1		)	—			(6		)
Net cash provided from (used for) financing activities	531			31			(90		)	(536		)	(64		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(44		)	(254		)	—			(303		)
Proceeds from assets sale	—			17			—			—			17
Sales of investment securities held in trusts	—			—			109			—			109
Purchases of investment securities held in trusts	—			—			(127		)	—			(127		)
Loans to affiliated companies, net	1			(308		)	(84		)	546			155
Other	(2		)	(4		)	—			—			(6		)
Net cash provided from (used for) investing activities	(6		)	(339		)	(356		)	546			(155		)
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

56

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

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

57

11. SEGMENT INFORMATION

During the second quarter of 2012, FirstEnergy successfully completed the integration of AE into its IT business networks and financial systems. An important element of this system integration was the capability to modify the segment reporting to reflect how management now views and makes investment decisions regarding the distribution and transmission operations of FirstEnergy. The external segment reporting is now consistent with the internal financial reports used by FirstEnergy's chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. Disclosures for FirstEnergy's operating segments for 2011 have been reclassified to conform to the current presentation.

The key changes in FirstEnergy's reportable segments during the second quarter of 2012 consisted principally of including the federally-regulated transmission assets and operations of JCP&L, ME, PN, MP, PE and WP, that were previously reported within the Regulated Distribution segment, with the renamed Regulated Transmission Segment. There were no changes to the Competitive Energy Services or Other / Corporate Segments. FirstEnergy continues to havethreereportable operating segments — Regulated Distribution, Regulated 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’stenutility operating companies, serving approximatelysix millioncustomers within65,000square 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 regulated electric generation facilities in West Virginia and New Jersey that 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 Transmission segment, previously known in part as the Regulated Independent Transmission Segment, transmits electricity through transmission lines owned and operated by certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and independent transmission companies (ATSI, TrAIL and PATH). Its revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Revenues are also derived from providing transmission services to electric energy providers, power marketers and revenue from operating 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 approximately17,000MWs of capacity, excluding approximately2,700MWs from unregulated plants expected to be deactivated, (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.

The Other / Corporate Segment 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.

58

Segment Financial Information

Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
June 30, 2012
External revenues	$	2,095	$	184	$	1,616	$	(24	)	$	(2	)	$	3,869
Internal revenues	—		—		209		—			(209		)	—
Total revenues	2,095		184		1,825		(24		)	(211		)	3,869
Depreciation and amortization	215		29		103		8			(1		)	354
Investment income	19		—		6		1			(13		)	13
Net interest charges	132		22		59		42			—			255
Income taxes	94		31		14		(25		)	13			127
Net income	161		52		25		(42		)	(8		)	188
Total assets	25,787		4,473		17,216		572			—			48,048
Total goodwill	5,025		526		893		—			—			6,444
Property additions	177		59		150		26			—			412
June 30, 2011
External revenues	$	2,409	$	182	$	1,495	$	(30	)	$	(8	)	$	4,048
Internal revenues	—		—		318		—			(306		)	12
Total revenues	2,409		182		1,813		(30		)	(314		)	4,060
Depreciation and amortization	232		28		109		8			—			377
Investment income	25		—		16		—			(10		)	31
Net interest charges	134		24		69		19			(1		)	245
Income taxes	100		33		12		(30		)	(1		)	114
Net income	171		57		21		(51		)	(5		)	193
Total assets	25,069		4,202		17,146		1,179			—			47,596
Total goodwill	5,025		526		885		—			—			6,436
Property additions	266		81		197		25			—			569
Six Months Ended
June 30, 2012
External revenues	$	4,420	$	370	$	3,222	$	(47	)	$	(20	)	$	7,945
Internal revenues	—		—		477		—			(475		)	2
Total revenues	4,420		370		3,699		(47		)	(495		)	7,947
Depreciation and amortization	435		61		203		16			(1		)	714
Investment income	42		1		12		1			(32		)	24
Net interest charges	264		45		113		63			(1		)	484
Income taxes	187		66		97		(41		)	40			349
Net income	318		112		166		(69		)	(33		)	494
Total assets	25,787		4,473		17,216		572			—			48,048
Total goodwill	5,025		526		893		—			—			6,444
Property additions	443		122		393		43			—			1,001
June 30, 2011
External revenues	$	4,632	$	295	$	2,736	$	(53	)	$	(18	)	$	7,592
Internal revenues	—		—		661		—			(617		)	44
Total revenues	4,632		295		3,397		(53		)	(635		)	7,636
Depreciation and amortization	473		50		197		14			—			734
Investment income	48		—		21		1			(18		)	52
Net interest charges	256		41		122		39			—			458
Income taxes	158		47		21		(30		)	29			225
Net income	267		80		36		(105		)	(38		)	240
Total assets	25,069		4,202		17,146		1,179			—			47,596
Total goodwill	5,025		526		885		—			—			6,436
Property additions	381		170		411		56			—			1,018

59

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 second quarter of 2012 were $187 million, or basic and diluted earnings of $0.45 per share of common stock, compared with $203 million, or basic and diluted earnings of $0.48 per share of common stock in the second quarter of 2011. Earnings available to FirstEnergy Corp. in the first six months of 2012 were $493 million or basic and diluted earnings of $1.18 per share of common stock, compared with $255 million or basic and diluted earnings of $0.67 per share of common stock in the first six months 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 June 30			Six Months Ended June 30
Basic Earnings Per Share - 2011	$	0.48		$	0.67
Segment operating results(1) -
Regulated Distribution	(0.01		)	(0.04		)
Regulated Transmission	—			(0.01		)
Competitive Energy Services	(0.06		)	(0.04		)
Regulatory charges	—			0.02
Income Tax Charge – retiree prescription drug subsidy	(0.02		)	(0.04		)
Merger-related costs	0.02			0.36
Impact of non-core asset sales / impairments	0.03			0.06
Mark-to-market adjustments	0.01			0.09
Merger accounting — commodity contracts	0.04			0.04
Plant closing costs	(0.07		)	(0.13		)
Litigation resolution	0.05			0.05
Net merger accretion(1)(2)	—			0.17
Depreciation	(0.01		)	—
Interest expense, net of amounts capitalized	0.01			0.02
Investment Income	(0.02		)	(0.02		)
Other	—			(0.02		)
Basic Earnings Per Share - 2012	$	0.45		$	1.18

⁽¹⁾  Excludes amounts that are shown separately. Allegheny results for the three months ended June 30, 2012 and 2011, are included in Segment Operating Results.

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

Operational Matters

Enhancing Transmission System Reliability

On May 29, 2012, FirstEnergy announced plans to construct a series of transmission projects to enhance service reliability across its service area. The projects have been approved by PJM and will include specialized voltage regulating equipment in northern Ohio. In addition to the work in Ohio, approved transmission projects will also be undertaken in Pennsylvania, West Virginia, New Jersey and Maryland as part of FirstEnergy's ongoing commitment to enhance its transmission system reliability. FirstEnergy estimates spending between $700 million - $900 million through 2016 on these projects.

On June 14, 2012, JCP&L announced that it plans to begin work on 17 transmission construction projects over the next six months in its northern and central New Jersey service areas. These projects are part of the multi-year, $200 million LITE program, which began in 2011, to address New Jersey's growing demand for electricity and provide key enhancements to the transmission system designed to improve service reliability for JCP&L's 1.1 million customers. All of the LITE projects are being designed and built specifically to serve only JCP&L customers.

60

Beaver Valley Unit 1 Returns to Service After Refueling Outage

On May 11, 2012, Beaver Valley Power Station Unit 1 returned to service following an April 9, 2012 shutdown for refueling and maintenance. During the outage, 65 of the 157 fuel assemblies were exchanged and safety inspections were successfully conducted. In addition, maintenance and improvement projects were completed to ensure continued safe and reliable operations. Prior to the outage, Beaver Valley Unit 1 operated safely and reliably for 359 consecutive days during which time it generated more than 9.3 million MWH of electricity. The plant also posted an industry top-decile forced-loss rate of 0.01 percent during the 18 months of operation prior to the outage.

Davis-Besse Returns to Service After Refueling Outage

On June 13, 2012, Davis-Besse Nuclear Power Station returned to service following a May 6, 2012, shutdown for refueling and maintenance. During the outage, 68 of Davis-Besse's 177 fuel assemblies were exchanged and safety inspections, including inspections of the station's steam generators, were successfully conducted. Preventive maintenance and improvement projects also were completed that are designed to promote continued safe and reliable operations.

Storm Costs

During the last weekend of June 2012, MP, PE, WP and OE experienced significant customer outages due to a rare “derecho” wind storm. While projections for restoration costs are not finalized, estimated costs incurred in the third quarter related to this storm are expected to exceed $130 million. Approximately 70% of these estimated expenditures are anticipated to be capital-related. Most of the remaining maintenance costs are expected to be deferred for future recovery. MP and PE do not currently have regulatory authority to defer storm costs, but expect to make a filing in the third quarter of 2012 with the WVPSC requesting deferral of those costs. MP and PE can provide no assurance that they will be successful in getting WVPSC authorization for the deferral of storm costs.

Regulatory Matters

Ohio Electric Security Plan Update

On July 18, 2012, the PUCO approved the Ohio Companies' ESP allowing the Ohio Companies to essentially extend the terms of the current ESP for two additional years and establish electricity prices for their customers through May 31, 2016.

The approved ESP 3 plan will 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 power to shopping and to non-shopping customers as part of the 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.

The approved ESP 3 plan provides significant additional benefits including:

• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, 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 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.

The approved plan reflects the diverse interests and concerns of 19 signatories, including parties that represent residential, low-income, commercial and industrial customers, as well as competitive retail electric suppliers, schools and hospitals.

Ohio Companies Solar Renewable Energy

On April 26, 2012, FirstEnergy announced that its Ohio Companies have met the 2012 benchmarks for in-state solar renewable energy that were established under Ohio's energy law. The benchmarks were met through a successful RFP to secure 10-year SRECs. In Ohio, FirstEnergy supports the development of solar energy resources by purchasing SRECs, which represent the environmental attributes of solar renewable electricity generation. For every MWH of solar renewable electricity generated, an equivalent amount of SRECs are produced. The RFP sought and procured the delivery of 1,000 SRECs produced by generating facilities throughout Ohio for each calendar year beginning in 2012 and continuing through 2021. There were 38 qualified bids received, offering over 15 times the required SRECs being sought under the RFP.

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NJBPU Update

In its written Order issued July 31, 2012, affirming the determination made at its July 18, 2012 agenda meeting, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year on or before November 1, 2012. JCP&L is unable to predict the outcome of this matter.

Financial Matters

In the second quarter of 2012, FirstEnergy executed a total of $1.6 billion forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%.

On May 8, 2012, FET entered into a new $1 billion revolving credit facility. In conjunction with this action, an existing $450 million TrAIL revolving credit facility was terminated. On May 9, 2012, FET drew the entire amount to repay $171.3 million of short-term borrowings and to pay $3.2 million in expenses related to the closing. The balance was invested in the unregulated money pool. On May 10, 2012, FE repaid $1.0 billion under the existing $2.0 billion facility. Additionally, FirstEnergy and FES/AE Supply amended their existing $2.0 billion and $2.5 billion revolving credit facilities, respectively. The termination date on both facilities was extended from June 2016 to May 2017 and pricing was reduced to reflect current market conditions.

On August 1, 2012, FGCO mandatorily repurchased approximately $106.5 million of 4.75% PCRBs, which it is holding for future remarketing or refinancing subject to market and other conditions.

FIRSTENERGY’S BUSINESS

During the second quarter of 2012, FirstEnergy successfully completed the integration of AE into its IT business networks and financial systems. An important element of this system integration was the capability to modify the segment reporting to reflect how management now views and makes investment decisions regarding the distribution and transmission operations of FirstEnergy. The external segment reporting is now consistent with the internal financial reports used by FirstEnergy's chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. Disclosures for FirstEnergy's operating segments for 2011 have been reclassified to conform to the current presentation.

The key changes in FirstEnergy's reportable segments during the second quarter of 2012 consisted principally of including the federally-regulated transmission assets and operations of JCP&L, ME, PN, MP, PE and WP, that were previously reported within the Regulated Distribution segment, with the renamed Regulated Transmission Segment. There were no changes to the Competitive Energy Services or Other / Corporate Segments. FirstEnergy continues to havethreereportable operating segments — Regulated Distribution, Regulated 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’stenutility operating companies, serving approximately6 millioncustomers within65,000square 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 regulated electric generation facilities in West Virginia and New Jersey that 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 Transmission segment, previously known in part as the Regulated Independent Transmission Segment, transmits electricity through transmission lines owned and operated by certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and independent transmission companies (ATSI, TrAIL and PATH). Its revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Revenues are also derived from providing transmission services to electric energy providers, power marketers and revenue from operating 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 approximately17,000MWs of capacity, excluding approximately2,700MWs from unregulated plants expected to be deactivated, (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.

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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 of operations for the six months ended June 30, 2011, include only four months of Allegheny results which have been segregated from the pre-merger companies (FirstEnergy and its subsidiaries prior to the merger) for variance reporting and analysis. In addition, Allegheny's results were affected by many of the same factors that influenced the operating results of the pre-merger 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 June 30									Six Months Ended June 30
	2012			2011			Increase (Decrease)			2012			2011			Increase
	(In millions, except per share data)
Earnings (Loss) By Business Segment:
Regulated Distribution	$	161		$	171		$	(10	)	$	318		$	267		$	51
Competitive Energy Services	25			21			4			166			36			130
Regulated Transmission	52			57			(5		)	112			80			32
Other and reconciling adjustments (1)	(51		)	(46		)	(5		)	(103		)	(128		)	25
Earnings available to FirstEnergy Corp.	$	187		$	203		$	(16	)	$	493		$	255		$	238
Basic Earnings Per Share	$	0.45		$	0.48		$	(0.03	)	$	1.18		$	0.67		$	0.51
Diluted Earnings Per Share	$	0.45		$	0.48		$	(0.03	)	$	1.18		$	0.67		$	0.51

⁽¹⁾  Consists primarily of interest expense related to holding company debt, corporate support services revenues and expenses, noncontrolling interests and the elimination of intersegment transactions.

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Second Quarter 2012 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,059		$	—		$	1,527		$	1		$	3,587
Other	36			184			89			(27		)	282
Internal	—			—			209			(209		)	—
Total Revenues	2,095			184			1,825			(235		)	3,869
Operating Expenses:
Fuel	57			—			598			1			656
Purchased power	895			—			470			(209		)	1,156
Other operating expenses	393			41			513			(33		)	914
Provision for depreciation	151			31			103			7			292
Amortization (deferral) of regulatory assets, net	64			(2		)	—			—			62
General taxes	167			9			49			7			232
Total Operating Expenses	1,727			79			1,733			(227		)	3,312
Operating Income	368			105			92			(8		)	557
Other Income (Expense):
Investment income	19			—			6			(12		)	13
Interest expense	(135		)	(23		)	(71		)	(45		)	(274		)
Capitalized interest	3			1			12			3			19
Total Other Expense	(113		)	(22		)	(53		)	(54		)	(242		)
Income Before Income Taxes	255			83			39			(62		)	315
Income taxes	94			31			14			(12		)	127
Net Income	161			52			25			(50		)	188
Income attributable to noncontrolling interest	—			—			—			1			1
Earnings Available to FirstEnergy Corp.	$	161		$	52		$	25		$	(51	)	$	187

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Second Quarter 2011 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,352		$	—		$	1,394		$	—		$	3,746
Other	57			182			101			(38		)	302
Internal	—			—			318			(306		)	12
Total Revenues	2,409			182			1,813			(344		)	4,060
Operating Expenses:
Fuel	73			—			561			1			635
Purchased power	1,145			—			381			(306		)	1,220
Other operating expenses	402			30			625			8			1,065
Provision for depreciation	145			26			109			7			287
Amortization of regulatory assets, net	87			2			—			1			90
General taxes	177			10			51			4			242
Total Operating Expenses	2,029			68			1,727			(285		)	3,539
Operating Income	380			114			86			(59		)	521
Other Income (Expense):
Investment income	25			—			16			(10		)	31
Interest expense	(136		)	(25		)	(80		)	(24		)	(265		)
Capitalized interest	2			1			11			6			20
Total Other Expense	(109		)	(24		)	(53		)	(28		)	(214		)
Income Before Income Taxes	271			90			33			(87		)	307
Income taxes	100			33			12			(31		)	114
Net Income	171			57			21			(56		)	193
Loss attributable to noncontrolling interest	—			—			—			(10		)	(10		)
Earnings Available to FirstEnergy Corp.	$	171		$	57		$	21		$	(46	)	$	203

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Changes Between Second Quarter 2012 and Second Quarter 2011 Financial Results Increase (Decrease)	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	(293	)	$	—		$	133		$	1		$	(159	)
Other	(21		)	2			(12		)	11			(20		)
Internal	—			—			(109		)	97			(12		)
Total Revenues	(314		)	2			12			109			(191		)
Operating Expenses:
Fuel	(16		)	—			37			—			21
Purchased power	(250		)	—			89			97			(64		)
Other operating expenses	(9		)	11			(112		)	(41		)	(151		)
Provision for depreciation	6			5			(6		)	—			5
Amortization (deferral) of regulatory assets, net	(23		)	(4		)	—			(1		)	(28		)
General taxes	(10		)	(1		)	(2		)	3			(10		)
Total Operating Expenses	(302		)	11			6			58			(227		)
Operating Income	(12		)	(9		)	6			51			36
Other Income (Expense):
Investment income	(6		)	—			(10		)	(2		)	(18		)
Interest expense	1			2			9			(21		)	(9		)
Capitalized interest	1			—			1			(3		)	(1		)
Total Other Expense	(4		)	2			—			(26		)	(28		)
Income Before Income Taxes	(16		)	(7		)	6			25			8
Income taxes	(6		)	(2		)	2			19			13
Net Income	(10		)	(5		)	4			6			(5		)
Income attributable to noncontrolling interest	—			—			—			11			11
Earnings Available to FirstEnergy Corp.	$	(10	)	$	(5	)	$	4		$	(5	)	$	(16	)

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Regulated Distribution — Second Quarter 2012 Compared with Second Quarter 2011

Net income decreased by $10 million in the second quarter of 2012 compared to the same period of 2011, primarily due to reduced revenues, partially offset by decreased purchased power costs and other operating expenses in the second quarter of 2012.

Revenues —

The $314 million decrease in total revenues resulted from the following sources:

	Three Months Ended June 30				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Distribution services	$	936	$	966	$	(30	)
Generation sales:
Retail	961		1,166		(205		)
Wholesale	86		172		(86		)
Total generation sales	1,047		1,338		(291		)
Transmission	61		41		20
Other	51		64		(13		)
Total Revenues	$	2,095	$	2,409	$	(314	)

The decrease in distribution services revenue primarily reflected the suspension of Ohio's deferred distribution cost recovery rider in December 2011 and an NJBPU-approved reduction to the JCP&L NUG Rider which became effective on March 1, 2012, partially offset by a PAPUC-approved increase to the ME and PN NUG Rider which also became effective on March 1, 2012. Distribution deliveries increased by 0.9% in the second quarter of 2012 from the same period of 2011. Distribution deliveries by customer class are summarized in the following table:

	Three Months Ended June 30		Increase
Electric Distribution MWH Deliveries	2012	2011	(Decrease)
	(in thousands)
Residential	11,832	11,958	(1.1	)%
Commercial	10,564	10,460	1.0	%
Industrial	12,784	12,433	2.8	%
Other	151	149	1.3	%
Total Electric Distribution MWH Deliveries	35,331	35,000	0.9	%

Lower deliveries to residential customers reflect declining average customer consumption and slightly reduced residential accounts. Commercial class deliveries increased due to load growth in the sector. In the industrial sector, MWH deliveries increased by 2.8% primarily due to increased deliveries of 4% to steel customers, 2% to automotive customers and 2% to petroleum customers, partially offset by a 3% decrease in deliveries to chemical customers.

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The following table summarizes the price and volume factors contributing to the $291 milliondecrease in generation revenues in the second quarter of 2012 compared to the same period of 2011:

Source of Change in Generation Revenues	Decrease
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(152	)
Change in prices	(53		)
	(205		)
Wholesale:
Effect of decrease in sales volumes	(62		)
Change in prices	(24		)
	(86		)
Decrease in Generation Revenues	$	(291	)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the Utilities' service territories during the second quarter of 2012, compared with the same period of 2011. This increase in customer shopping is expected to continue. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 79% from 77% for the Ohio Companies, 65% from 53% for the Pennsylvania Companies and 51% from 45% for JCP&L.

The decrease in wholesale generation revenues of $86 million in the second quarter of 2012 was a result of the expiration of a NUG contract in August 2011 and lower PJM market prices.

Transmission revenues increased $20 million primarily due tothe implementation of Ohio's NMB transmission rider in June of 2011, which recovers network integration transmission service charges as described below, partially offset by lower RTO revenue resulting from decreased congestion prices.

Other revenue decreased $13 million primarily due to the absence in 2012 of revenue from the sale of certain pole attachment lease rights in June 2011.

Operating Expenses —

Total operating expenses decreased by $302 million due to the following:

• Fuel expense decreased by $16 million primarily due to lower generation output from the Fort Martin power station.

• Purchased power costs were $250 million lower in the second quarter of 2012 primarily due to increased customer shopping, which reduced purchased power requirements, and lower purchased power prices resulting from lower auction prices during the second quarter of 2012 compared to the same period of 2011.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(103	)
Change due to decreased volumes	(111		)
	(214		)
Purchases from FES:
Change due to decreased unit costs	(11		)
Change due to decreased volumes	(99		)
	(110		)
Decrease in costs deferred	74
Net Decrease in Purchased Power Costs	$	(250	)

• Transmission expenses increased $23 million during the second quarter of 2012 compared to the same period of 2011, primarily due to network integration transmission service expenses that, prior to June 2011, were incurred by the generation supplier, and are now being recovered through the NMB transmission rider discussed above, partially offset by lower

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congestion costs.

• Depreciation expense increased $6 million primarily due to higher asset removal costs incurred by JCP&L.

• Regulatory asset amortization expense decreased $23 million due to the following:

◦ The scheduled suspension of the rider recovery of deferred distribution costs in December 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, and increased recovery of energy efficiency expenses.

• General taxes decreased by $10 million primarily due a decrease in gross receipts taxes partially offset by an increase in property taxes.

• Regulated generation operation and maintenance expenses decreased by $6 million primarily due to the upcoming anticipated plant deactivations.

• Expenses related to storm activity decreased $12 million in the second quarter of 2012 compared to the same period in 2011.

• Expenses were further decreased by $15 million due to synergies achieved in connection with the Allegheny merger.

Other Expense —

Other expense increased $4 million in the second quarter of 2012 primarily due to lower investment income on OE's and TE's NDT assets.

Regulated Transmission — Second Quarter 2012 Compared with Second Quarter 2011

Net income decreased by $5 million in the second quarter of 2012 compared to the same period of 2011 primarily due to increased operating expenses.

Revenues —

Total revenues increased by $2 million primarily due to a higher TrAIL rate base.

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

Revenues by	Three Months Ended June 30
Transmission Asset Owner	2012		2011		Increase
	(In millions)
ATSI	$	54	$	54	$	—
TrAIL	49		47		2
PATH	4		4		—
Utilities	77		77		—
Total Revenues	$	184	$	182	$	2

Operating Expenses —

Total operating expenses increased by $11 million due to the following:

• Operation and maintenance expenses increased by $11 million primarily due to increased vegetation management costs resulting from additional miles trimmed in second quarter of 2012 compared to the same period in 2011.

• Depreciation expense increased by $5 million primarily due to the TrAIL project in-servicing during May 2011.

• Net amortization of regulatory assets expense decreased by $4 million primarily due to the completion in May 2011 of ATSI's deferred vegetation management cost recovery.

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Other Expense —

Other expense decreased $2 million in the second quarter of 2012 due to lower net interest expense, related to the refinancing of the transmission credit facility.

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

Net income increased by $4 million in the second quarter of 2012, compared to the same period of 2011, due to higher retail revenues partially offset by increased operating expenses.

Revenues —

Total revenues increased by $12 million in the second quarter of 2012 primarily due to growth in direct and governmental aggregation and wholesale sales, partially offset by a decline in net POLR and structured sales. Revenues were also adversely impacted by lower unit prices compared to the second quarter of 2011.

The increase in total revenues resulted from the following sources:

	Three Months Ended June 30				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	1,055	$	951	$	104
POLR and Structured Sales	295		416		(121		)
Wholesale	386		333		53
Transmission	42		62		(20		)
RECs	—		12		(12		)
Other	47		39		8
Total Revenues	$	1,825	$	1,813	$	12

	Three Months Ended June 30		Increase
MWH Sales by Type of Service	2012	2011	(Decrease)
	(In thousands)
Direct	13,937	11,972	16.4	%
Governmental Aggregation	4,744	3,970	19.5	%
POLR and Structured Sales	5,379	6,733	(20.1	)%
Wholesale	4,846	5,006	(3.2	)%
Total MWH Sales	28,906	27,681	4.4	%

The increase in combined direct and governmental aggregation revenues of $104 million resulted from the acquisition of new residential, commercial and industrial customers. Our customer base increased to 2.0 million industrial, commercial and residential customers as of June 2012 as compared to 1.7 million in June 2011. The volume increase was partially offset by lower unit prices for commercial, industrial and governmental aggregation customers given declining market prices.

The decrease in combined POLR and structured revenues of $121 million was due primarily to lower sales volumes for POLR sales to the Ohio Companies, ME and PN due to an increased migration of customers away from their default service. Revenues were also adversely impacted by lower unit prices. The decline in POLR sales reflects a continued focus on other sales channels by FES.

Wholesale revenues increased $53 million due to increased gains of $147 million on financially settled contracts, which were offset by a $45 million decrease in capacity revenues resulting from the lower capacity prices in the RTO zone effective June 1, 2012, and a $49 million decrease in short-term (net hourly positions) transactions.

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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 and Governmental Aggregation:
Effect of increase in sales volumes	$	165
Change in prices	(61		)
	$	104

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of decrease in sales volumes	$	(84	)
Change in prices	(37		)
	$	(121	)

Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(7	)
Change in prices	(42		)
Gain on settled contracts	147
Capacity revenue	(45		)
	$	53

Transmission revenues decreased by $20 million primarily due to lower congestion revenue.

Operating Expenses —

Total operating expenses increased by $6 million in the second quarter of 2012 due to the following:

• Fuel costs increased $37 million primarily due to higher volumes consumed ($30 million) and higher unit prices ($7 million). Volumes increased due to higher fossil generation as a result of fewer planned and unplanned outages.

• Purchased power costs increased $89 million due to higher volumes ($41 million) and losses on settled contracts ($133 million), partially offset by reduced capacity expenses ($21 million) and lower unit prices ($64 million). The increase in purchased power volume primarily relates to the overall increase in direct and governmental aggregation sales volumes and economic purchases.

• Fossil operating costs decreased by $22 million due primarily to lower contractor, materials and equipment costs resulting from a decrease in planned and unplanned outages, partially offset by severance costs associated with certain fossil units to be deactivated.

• Nuclear operating costs increased by $21 million due primarily to higher contractor and materials and equipment costs. The second quarter of 2012 included refueling outages at Davis Besse and Beaver Valley Unit 1, whereas the second quarter of 2011 included a refueling outage at Perry and the conclusion of the Beaver Valley 2 refueling outage that began in the first quarter of 2011.

• Transmission expenses decreased by $71 million due to lower congestion, network and loss expenses.

• General taxes decreased by $2 million due to lower property taxes, partially offset by increases in revenue-related taxes.

• Depreciation expense decreased by $6 million primarily due to a lower asset base resulting from 2011 asset sales and impairments, combined with slightly reduced depreciation rates that reflect a periodic study that updated estimated economic lives for certain fossil units.

• Other operating expenses decreased by $40 million primarily due to favorable mark-to-market adjustments on commodity

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contract positions.

Other Expense —

Total other expense in the second quarter of 2012 was flat compared to the second quarter of 2011. Reduced interest expense was offset by lower investment income from the nuclear decommissioning trusts.

Other — Second Quarter of 2012 Compared with Second 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 $5 milliondecrease in earnings available to FirstEnergy Corp. in the second quarter of 2012 compared to the same period of 2011. The decrease resulted primarily from increased net interest expense ($24 million) and increased income attributable to noncontrolling interest ($11 million) relating to Global Holding, which was de-consolidated in the fourth quarter of 2011, partially offset by lower operating expenses ($41 million) due to lower merger-related costs.

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Summary of Results of Operations — First Six Months of 2012 Compared with the First Six Months of 2011

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

First Six Months 2012 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	4,329		$	—		$	3,058		$	1		$	7,388
Other	91			370			164			(68		)	557
Internal	—			—			477			(475		)	2
Total Revenues	4,420			370			3,699			(542		)	7,947
Operating Expenses:
Fuel	97			—			1,100			—			1,197
Purchased power	1,977			—			1,000			(474		)	2,503
Other operating expenses	828			66			922			(90		)	1,726
Provision for depreciation	297			61			203			16			577
Amortization of regulatory assets, net	138			—			—			(1		)	137
General taxes	356			21			110			17			504
Total Operating Expenses	3,693			148			3,335			(532		)	6,644
Operating Income	727			222			364			(10		)	1,303
Other Income (Expense):
Investment income	42			1			12			(31		)	24
Interest expense	(269		)	(46		)	(136		)	(69		)	(520		)
Capitalized interest	5			1			23			7			36
Total Other Expense	(222		)	(44		)	(101		)	(93		)	(460		)
Income Before Income Taxes	505			178			263			(103		)	843
Income taxes	187			66			97			(1		)	349
Net Income	318			112			166			(102		)	494
Income attributable to noncontrolling interest	—			—			—			1			1
Earnings Available to FirstEnergy Corp.	$	318		$	112		$	166		$	(103	)	$	493

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First Six Months 2011 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	4,527		$	—		$	2,556		$	—		$	7,083
Other	105			295			180			(71		)	509
Internal	—			—			661			(617		)	44
Total Revenues	4,632			295			3,397			(688		)	7,636
Operating Expenses:
Fuel	97			—			991			—			1,088
Purchased power	2,323			—			700			(617		)	2,406
Other operating expenses	753			58			1,256			(9		)	2,058
Provision for depreciation	258			45			197			12			512
Amortization of regulatory assets, net	215			5			—			2			222
General taxes	353			19			95			12			479
Total Operating Expenses	3,999			127			3,239			(600		)	6,765
Operating Income	633			168			158			(88		)	871
Other Income (Expense):
Investment income	48			—			21			(17		)	52
Interest expense	(259		)	(42		)	(144		)	(51		)	(496		)
Capitalized interest	3			1			22			12			38
Total Other Expense	(208		)	(41		)	(101		)	(56		)	(406		)
Income Before Income Taxes	425			127			57			(144		)	465
Income taxes	158			47			21			(1		)	225
Net Income	267			80			36			(143		)	240
Loss attributable to noncontrolling interest	—			—			—			(15		)	(15		)
Earnings Available to FirstEnergy Corp.	$	267		$	80		$	36		$	(128	)	$	255

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Changes Between First Six Months 2012 and First Six Months 2011 Financial Results Increase (Decrease)	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	(198	)	$	—		$	502		$	1		$	305
Other	(14		)	75			(16		)	3			48
Internal	—			—			(184		)	142			(42		)
Total Revenues	(212		)	75			302			146			311
Operating Expenses:
Fuel	—			—			109			—			109
Purchased power	(346		)	—			300			143			97
Other operating expenses	75			8			(334		)	(81		)	(332		)
Provision for depreciation	39			16			6			4			65
Amortization of regulatory assets, net	(77		)	(5		)	—			(3		)	(85		)
General taxes	3			2			15			5			25
Total Operating Expenses	(306		)	21			96			68			(121		)
Operating Income	94			54			206			78			432
Other Income (Expense):
Investment income	(6		)	1			(9		)	(14		)	(28		)
Interest expense	(10		)	(4		)	8			(18		)	(24		)
Capitalized interest	2			—			1			(5		)	(2		)
Total Other Expense	(14		)	(3		)	—			(37		)	(54		)
Income Before Income Taxes	80			51			206			41			378
Income taxes	29			19			76			—			124
Net Income	51			32			130			41			254
Income attributable to noncontrolling interest	—			—			—			16			16
Earnings Available to FirstEnergy Corp.	$	51		$	32		$	130		$	25		$	238

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Regulated Distribution — First Six Months of 2012 Compared to First Six Months of 2011

Net income increased by $51 million in the first six months of 2012 compared to the same period of 2011, primarily due to earnings from the Allegheny Utilities and lower merger-related costs, partially offset by decreased weather-related customer usage in the first six months of 2012.

Results of operations for the six months ended June 30, 2011, include only four months of Allegheny results which have been segregated from the pre-merger companies (FirstEnergy and its subsidiaries prior to the merger) for variance reporting and analysis.

Revenues —

The $212 milliondecrease in total revenues resulted from the following sources:

	Six Months Ended June 30				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Pre-merger companies:
Distribution services	$	1,541	$	1,721	$	(180	)
Generation sales:
Retail	1,300		1,620		(320		)
Wholesale	95		220		(125		)
Total generation sales	1,395		1,840		(445		)
Transmission	90		11		79
Other	80		93		(13		)
Total pre-merger companies	3,106		3,665		(559		)
Allegheny Utilities(1)	1,314		967		347
Total Revenues	$	4,420	$	4,632	$	(212	)

⁽¹⁾  Allegheny results include 6 months in 2012 and 4 months in 2011.

The decrease in distribution services revenue for the pre-merger companies reflects lower distribution deliveries (described below), the suspension of Ohio's deferred distribution cost recovery rider in December 2011 and an NJBPU-approved reduction to the JCP&L NUG Rider which became effective on March 1, 2012, partially offset by a PAPUC-approved increase to the ME and PN NUG Rider which also became effective on March 1, 2012. Distribution deliveries (excluding the Allegheny Utilities) decreased by 1.3% in the first six months of 2012 from the same period of 2011. Distribution deliveries by customer class are summarized in the following table:

	Six Months Ended June 30		Increase
Electric Distribution MWH Deliveries	2012	2011	(Decrease)
	(In thousands)
Pre-merger companies:
Residential	18,294	19,288	(5.2	)%
Commercial	15,777	15,882	(0.7	)%
Industrial	18,071	17,640	2.4	%
Other	248	256	(3.1	)%
Total pre-merger companies	52,390	53,066	(1.3	)%
Allegheny Utilities(1)	20,137	13,068	54.1	%
Total Electric Distribution MWH Deliveries	72,527	66,134	9.7	%

⁽¹⁾  Allegheny results include 6 months in 2012 and 4 months in 2011.

Lower deliveries to residential and commercial customers for the pre-merger companies reflect decreased weather-related usage resulting from heating degree days that were 21% below 2011 levels, partially offset by cooling degree days that were 9% higher than 2011 levels. In the industrial sector, MWH deliveries increased 3% to steel customers and 3% to automotive customers, partially offset by a decrease of 1% to petroleum customers and 2% to chemical customers.

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The following table summarizes the price and volume factors contributing to the $445 milliondecrease in generation revenues for the pre-merger companies in the first six months 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	$	(328	)
Change in prices	8
	(320		)
Wholesale:
Effect of decrease in sales volumes	(87		)
Change in prices	(38		)
	(125		)
Net Decrease in Generation Revenues	$	(445	)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the Utilities' service territories in the first six months of 2012, compared with the same period of 2011. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 78% from 75% for the Ohio Companies, 63% from 48% for ME's, PN's and Penn's service areas and 50% from 43% for JCP&L.

The decrease in wholesale generation revenues of $125 million in the first six months of 2012 was a result of the expiration of a NUG contract in August 2011 and lower PJM market prices.

Transmission revenues increased $79 million primarily due tothe implementation of Ohio's NMB transmission rider in June of 2011, which recovers network integration transmission service charges as described further below.

Operating Expenses —

Total operating expenses decreased by $306 million due to the following:

• Purchased power costs, excluding the Allegheny Utilities, were $526 million lower in the first six months of 2012 due primarily to a decrease in volumes required from increased customer shopping and the impact of milder weather.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Pre-merger companies:
Purchases from non-affiliates:
Change due to decreased unit costs	$	(83	)
Change due to decreased volumes	(300		)
	(383		)
Purchases from FES:
Change due to decreased unit costs	(27		)
Change due to decreased volumes	(167		)
	(194		)
Decrease in costs deferred	51
Total pre-merger companies	(526		)
Purchases by Allegheny Utilities	180
Net Decrease in Purchased Power Costs	$	(346	)

• Transmission expenses increased $96 million during the first six months 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 the generation supplier, and are now being recovered through the NMB transmission rider referred to above.

• Regulatory assets amortization expense decreased $85 million due to the following:

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◦ The scheduled suspension of the rider recovering deferred distribution costs in December 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 $24 million.

• General taxes decreased by $17 million primarily due to a decrease in gross receipts taxes for ME, PN and JCP&L.

• Depreciation expense increased by $11 million primarily due to higher asset removal costs incurred by JCP&L.

• Other costs decreased due to 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 $54 million in the first six months of 2012 compared to the same period of 2011.

	Six Months Ended June 30						Increase
Operating Expenses - Allegheny(1)	2012			2011			(Decrease)
	(In millions)
Purchased Power	$	653		$	473		$	180
Fuel	97			97			—
Transmission	68			51			17
Amortization of regulatory assets, net	(5		)	(13		)	8
Other operating expenses	24			8			16
General Taxes	68			48			20
Depreciation Expense	85			57			28
Total Operating Expenses	$	990		$	721		$	269

⁽¹⁾  Allegheny results include 6 months in 2012 and 4 month in 2011.

Other Expense —

Other expense increased $14 million in the first six months of 2012 primarily due to net interest expense on debt of the Allegheny Utilities.

Regulated Transmission — First Six Months of 2012 Compared with First Six Months of 2011

Net income increased by $32 million in the first six months of 2012 compared to the same period of 2011 primarily due to earnings associated with TrAIL, PATH and the Allegheny Utilities' transmission assets that were acquired in the merger.

Revenues —

Total revenues increased by $75 million principally due to revenues from TrAIL, PATH and the Allegheny Utilities' transmission assets.

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

	Six Months Ended June 30				Increase
Revenues by Transmission Asset Owner	2012		2011		(Decrease)
	(In millions)
ATSI	$	107	$	106	$	1
TrAIL(1)	102		61		41
PATH(1)	7		5		2
Utilities(1)	154		123		31
Total Revenues	$	370	$	295	$	75

⁽¹⁾  Allegheny results include 6 months in 2012 and 4 months in 2011.

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Operating Expenses —

Total operating expenses increased by $21 million principally due to the addition of TrAIL, PATH and the Allegheny Utilities' transmission operating expenses for six months in 2012 compared to four months in 2011, partially offset by reduced regulatory asset amortization expense due to the completion in May 2011 of ATSI's deferred vegetation management cost recovery.

Other Expense —

Other expense increased by $3 million in the first six months of 2012 due to a full six months of TrAIL interest expense compared to four months in 2011.

Competitive Energy Services — First Six Months of 2012 Compared with First Six Months of 2011

Net income increased by $130 million in the first six months of 2012, compared to the same period of 2011, due to higher retail revenues and the inclusion of the results of the Allegheny companies, partially offset by higher operating expenses.

Revenues —

Total revenues increased by $302 million in the first six months of 2012 primarily due to growth in direct and governmental aggregation and wholesale sales and the inclusion of the Allegheny companies for six months in 2012 compared to four months in 2011, partially offset by a net decline in POLR and structured sales. Revenues were also adversely impacted by lower unit prices compared to the first six months of 2011.

The increase in total revenues resulted from the following sources:

	Six Months Ended June 30				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Pre-merger Companies:
Direct and Governmental Aggregation	$	2,040	$	1,765	$	275
POLR and Structured Sales	426		607		(181		)
Wholesale(1)	259		156		103
Transmission	60		56		4
RECs	5		44		(39		)
Other	76		79		(3		)
Allegheny companies(2)	833		690		143
Total Revenues	$	3,699	$	3,397	$	302
Allegheny companies(2)
Direct and Governmental Aggregation	$	46	$	34	$	12
POLR and Structured Sales	248		254		(6		)
Wholesale	511		357		154
Transmission	28		44		(16		)
Other	—		1		(1		)
Total Revenues	$	833	$	690	$	143
(1)   Excludes $128 million in intra-segment sales by AE Supply to FES
(2)   Allegheny results include 6 months in 2012 and 4 months in 2011.

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	Six Months Ended June 30		Increase
MWH Sales by Type of Service	2012	2011	(Decrease)
	(In thousands)
Pre-merger Companies:
Direct	25,954	21,219	22.3	%
Governmental Aggregation	9,930	8,279	19.9	%
POLR and Structured Sales	7,645	9,561	(20.0	)%
Wholesale	86	1,380	(93.8	)%
Allegheny companies(1)	13,406	10,687	25.4	%
Total MWH Sales	57,021	51,126	11.5	%
Allegheny companies(1)
Direct and Governmental Aggregation	762	570	33.7	%
POLR	4,098	2,981	37.5	%
Structured Sales	279	1,149	(75.7	)%
Wholesale	8,267	5,987	38.1	%
Total MWH Sales	13,406	10,687	25.4	%
(1)   Allegheny results include 6 months in 2012 and 4 months in 2011.

The increase in combined direct and governmental aggregation revenues of $275 million resulted from the acquisition of new residential, commercial and industrial customers. Our customer base increased to 2.0 million industrial, commercial and residential customers as of June 2012 as compared to 1.7 million in June 2011. The volume increase was partially offset by lower unit prices for commercial, industrial and governmental aggregation customers.

The decrease in combined POLR and structured revenues of $181 million was due primarily to lower sales volumes to the Ohio Companies, ME and PN. Revenues were also adversely impacted by lower unit prices, discussed above, which were partially offset by increased structured sales. The decline in POLR sales reflects a continued focus on other sales channels.

Wholesale revenues increased $103 million due to increased gains of $100 million on financially settled contracts and a $42 million increase in capacity revenues. These increases were partially offset by decreased volumes sold of $39 million.

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 and Governmental Aggregation:
Effect of increase in sales volumes	$	381
Change in prices	(106		)
	$	275

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of decrease in sales volumes	$	(122	)
Change in prices	(59		)
	$	(181	)

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Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(39	)
Change in prices	—
Gain on settled contracts	100
Capacity revenue	42
	$	103

Operating Expenses —

Total operating expenses for the pre-merger companies increased by $95 million in the first six months of 2012 due to the following:

• Fuel costs increased $38 million primarily due to higher unit prices ($29 million) and higher volumes consumed ($9 million). Volumes increased due to higher nuclear generation, partially offset by lower generation from the fossil units.

• Purchased power costs increased $295 million due to higher volumes ($147 million), loss on settled contracts ($229 million) and increased capacity expense ($61 million), partially offset by lower unit prices ($142 million). The increase in purchased power volumes primarily relates to the overall increase in direct and governmental aggregation sales volumes and economic purchases.

• Fossil operating costs decreased by $16 million due primarily to lower contractor, materials and equipment costs resulting from a decrease in planned and unplanned outages, partially offset by severance costs associated with certain fossil units to be deactivated.

• Nuclear operating costs decreased by $8 million due primarily to lower labor, materials and equipment costs. During the first six months of 2012, there were refueling outages at Davis Besse and Beaver Valley Unit 1 compared to 2011, which included refueling outages at Perry and Beaver Valley Unit 2. Total outage days were reduced in the first six months of 2012 compared to the same period of 2011.

• Transmission expenses decreased $89 million due primarily to lower congestion, network and line loss costs, partially offset by higher ancillary costs.

• General taxes increased by $4 million primarily due to an increase in revenue-related taxes.

• Depreciation expense decreased $15 million primarily due to a lower asset base resulting from 2011 asset sales and impairments, combined with slightly reduced depreciation rates that reflect a periodic study that updated estimated economic lives for certain fossil assets and credits resulting from a settlement with the DOE regarding storage of spent nuclear fuel.

• Other operating expenses decreased by $114 million primarily due to favorable mark-to-market adjustments on commodity contract positions ($64 million) and reduced 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 $20 million impairment charge related to non-core assets. These decreases were partially offset by increases in other expenses of $38 million associated with inter-segment leases, and labor, agent fees and professional and contractor costs associated with our retail business.

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The Allegheny companies’ operations for six months in 2012 and four months in 2011 added $720 million and $719 million to operating expenses, respectively, as shown in the following table:

	Six Months Ended June 30					Increase
Operating Expenses (Credits) - Allegheny(1)	2012			2011		(Decrease)
	(In millions)
Fuel	$	391		$	320	$	71
Purchased power	79			74		5
Fossil generation	88			82		6
Transmission	63			99		(36		)
Other operating expenses	23			43		(20		)
Mark-to-market adjustments	(16		)	43		(59		)
General taxes	28			15		13
Depreciation	64			43		21
Total Operating Expense	$	720		$	719	$	1
(1)   Allegheny results include 6 months in 2012 and 4 months in 2011.

Other Expense —

Total other expense in the first six months of 2012 was flat compared to the first six months of 2011. Reduced net interest expense from debt reductions in 2011 was offset by lower investment income from the nuclear decommissioning trusts.

Other — First Six Months of 2012 Compared with First Six Months 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 $25 millionincrease in earnings available to FirstEnergy Corp. in the first six months of 2012 compared to the same period of 2011. The increase resulted primarily from decreased other operating expenses ($81 million) due to lower merger-related costs, partially offset by increased net interest expenses ($23 million), decreased investment income ($14 million) and decreased income attributable to noncontrolling interest ($16 million) relating to Global Holding, which was de-consolidated in the fourth quarter of 2011.

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 June 30, 2012 and December 31, 2011, and the changes during the six months ended June 30, 2012:

Regulatory Assets by Source	June 30, 2012			December 31, 2011			Increase (Decrease)
	(In millions)
Regulatory transition costs	$	297		$	309		$	(12	)
Customer receivables for future income taxes	490			519			(29		)
Nuclear decommissioning and spent fuel disposal costs	(215		)	(210		)	(5		)
Asset removal costs	(375		)	(347		)	(28		)
Deferred transmission costs	392			340			52
Deferred generation costs	334			400			(66		)
Deferred distribution costs	249			267			(18		)
Contract valuations	516			299			217
Other	434			453			(19		)
Total	$	2,122		$	2,030		$	92

FirstEnergy had $437 million of net regulatory liabilities as of June 30, 2012, that are primarily related to asset removal costs. Regulatory assets that do not earn a current return totaled approximately $315 million as of June 30, 2012. JCP&L had $118 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 $197 million of regulatory assets include certain PJM transmission and

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regulatory transition costs, which are expected to be recovered by 2020.

CAPITAL RESOURCES AND LIQUIDITY

As of June 30, 2012, FirstEnergy had $94 million of cash and cash equivalents and available liquidity of approximately $3.6 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 the remainder of 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 issuance of long-term debt and/or equity. 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 June 30, 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 June 30, 2012, included the following:

Currently Payable Long-term Debt	(In millions)
PCRBs supported by bank LOCs (1)	$	713
Term loan	150
Unsecured notes	150
Unsecured PCRBs (1)	317
Secured PCRBs (1)	106
Collateralized lease obligation bonds	71
Sinking fund requirements	54
Other notes	16
	$	1,577

⁽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 $1.9 billion of short-term borrowings as of June 30, 2012, and no significant short-term borrowings as of December 31, 2011. FirstEnergy’s available liquidity as of June 30, 2012, is summarized in the following table:

Company	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	May 2017	$	2,000	$	1,080
FES / AE Supply	Revolving	May 2017	2,500		2,498
FET(2)	Revolving	May 2017	1,000		—
AGC	Revolving	Dec 2013	50		—
		Subtotal	$	5,550	$	3,578
		Cash	—		63
		Total	$	5,550	$	3,641

⁽¹⁾  FirstEnergy Corp. and the Utilities.

⁽²⁾  Includes FET, ATSI and TrAIL.

Revolving Credit Facilities

FirstEnergy, FES/AE Supply and FET Facilities

FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of $5.5 billion (Facilities). The Facilities consist of a $2.0 billion aggregate FirstEnergy Facility, a $2.5 billion FES/AE Supply Facility and a $1.0 billion FET Facility, that are each available until May 2017, 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%, and 70% for FET, measured at the end of each fiscal quarter.

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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 June 30, 2012:

Borrower	FirstEnergy Revolving Credit Facility Sub-Limit			FES/AE Supply Revolving Credit Facility Sub-Limit			FET Revolving Credit Facility Sub-Limit			Regulatory and Other Short-Term Debt Limitations				Debt to Capitalization
	(In millions)
FE		$	2,000		$	—		$	—		$	—	(2)	58.8%
FES		—			1,500			—			—		(3)	50.2%
AE Supply		—			1,000			—			—		(3)	34.7%
FET		—			—			1,000			—		(2)	64.4%
OE		500			—			—			500		(4)	61.9%
CEI		500			—			—			500		(4)	62.0%
TE		500			—			—			500		(4)	62.6%
JCP&L		425			—			—			600		(1)(4)	45.6%
ME		300			—			—			500		(1)(4)	54.3%
PN		300			—			—			300		(1)(4)	59.0%
WP		200			—			—			200		(1)(4)	52.7%
MP		150			—			—			150		(1)(4)	54.9%
PE		150			—			—			150		(1)(4)	54.9%
ATSI		—			—			100			100		(4)	48.6%
Penn		50			—			—			50		(1)(4)	41.1%
TrAIL		—			—			200			400		(1)(4)	44.0%

⁽¹⁾  On June 1, 2012 the joint application, which was filed with the FERC on April 11, 2012, seeking authorization to increase or incur short-term debt, was granted.

⁽²⁾  No limitations.

⁽³⁾  No limitation based upon blanket financing authorization from the FERC under existing open market tariffs.

⁽⁴⁾  Including amounts which may be borrowed under the regulated companies' money pool.

As of June 30, 2012, FE and its subsidiaries could issue additional debt of approximately $5.7 billion, or recognize a reduction in equity of approximately $3.1 billion, and remain within the limitations of the financial covenants required by the Facilities.

The entire amount of the FES/AE Supply Facility, $700 million of the FirstEnergy Facility and $225 million of the FET 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 is related to the credit ratings of the company borrowing the funds, other than the FET Facility, which is based on its subsidiaries' credit ratings. 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 Revolving Credit Facility

A separate $50 million revolving credit facility is available to AGC until December 2013. Under the terms of this credit facility, outstanding debt of AGC may not exceed 65% of the sum of its debt and equity as of the last day of each calendar quarter. This provision limits the debt level of AGC and also limits the net assets of AGC that may be transferred to AE. As of June 30, 2012, the debt to total capitalization ratios for AGC (as defined under this credit facility) was 52% and AGC could issue additional debt of approximately $37 million and remain within the limitations of the financial covenants under this credit facility.

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

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through the pool. The average interest rate for borrowings in the first six months of 2012 was 0.65% per annum for the regulated companies’ money pool and 1.24% per annum for the unregulated companies’ money pool.

Pollution Control Revenue Bonds

As of June 30, 2012, FirstEnergy’s currently payable long-term debt included approximately $713 million ($640 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 June 30, 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.	166		June 2014	June 2014
Wachovia Bank	152		March 2014	March 2014
The Bank of Nova Scotia	49		April 2014	Multiple dates(2)
The Bank of Nova Scotia	82		April 2015	April 2015
Total	$	721

⁽¹⁾  Includes approximately $8 million of applicable interest coverage.

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

Long-Term Debt Capacity

As of June 30, 2012, the Ohio Companies and Penn had the aggregate capacity to issue approximately $2.8 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 to incur additional secured debt not otherwise permitted by a specified exception of up to $139 million. As a result of the indenture provisions, CEI and TE cannot incur any additional secured debt. ME and PN had the capability to issue secured debt of approximately $375 million and $385 million, respectively, under provisions of their senior note indentures as of June 30, 2012. In addition, based upon their net earnings and available bondable property additions as of June 30, 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. Additionally, the issuance of FMBs by these companies is subject to compliance with the financial covenants of the Facilities and any required regulatory approvals and may be subject to statutory and/or charter limitations.

The Ohio Companies filed an application with the PUCO for a financing order under the Ohio securitization legislation adopted in December 2011, which we expect will be primarily used 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 June 30, 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 June 30, 2012, NGC had the capacity to issue $2.2 billion of additional FMBs under the terms of that indenture.

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FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ debt credit ratings as of June 30, 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 June 30, 2012, FirstEnergy had $94 million of cash and cash equivalents compared to $202 million of cash and cash equivalents as of December 31, 2011. As of June 30, 2012 and December 31, 2011, FirstEnergy had approximately $68 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 transmission and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $62 million during the first six months of 2012 compared with $1,031 million being provided from operating activities during the first six months of 2011, as summarized in the following table:

	Six Months Ended June 30						Increase
Operating Cash Flows	2012			2011			(Decrease)
	(In millions)
Net income	$	494		$	240		$	254
Non-cash charges	817			1,201			(384		)
Pension trust contributions	(600		)	(262		)	(338		)
Working capital and other	(649		)	(148		)	(501		)
	$	62		$	1,031		$	(969	)

The $384 million decrease in non-cash charges and other adjustments is primarily due to the following:

• $129 million from accrued compensation and retirement benefits as a result of higher performance-related incentive compensation payments during the first six months of 2012 compared to the same period of 2011.

• $85 million from lower net amortization of regulatory assets as a result of the suspension of the rider recovering deferred distribution costs in September 2011 and 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.

• $175 million from decreased deferred income taxes as a result of a change in bonus depreciation.

The $501 million decrease in cash flows from working capital and other is primarily due to the following:

• $304 million from lower collections from customers during the first six months of 2012 as a result of the effects of milder weather described in Results of Operations above.

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• $133 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.

• $94 million from lower accounts payable balances as a result of the timing of payments to vendors during the first six months of 2012 as compared to the same period of 2011.

Cash Flows From Financing Activities

In the first six months of 2012, cash provided from financing activities was $831 million compared to $1,039 million of net cash used for financing activities during the first six months of 2011. The following tables summarize new debt financing (net of any discounts) and redemptions:

	Six Months Ended June 30
Securities Issued or Redeemed / Retired	2012		2011
	(In millions)
New Issues
PCRBs	$	82	$	272
Long-term revolving credit	—		70
FMBs	100		—
Unsecured Notes	—		161
	$	182	$	503
Redemptions / Retirements
PCRBs	$	82	$	312
Long-term revolving credit	—		475
Senior secured notes	81		166
FMBs	—		14
Unsecured notes	583		35
	$	746	$	1,002
Short-term borrowings, net	$	1,890	$	(44	)

On August 1, 2012, FGCO mandatorily repurchased approximately $106.5 million of 4.75% PCRBs, which it is holding for future remarketing or refinancing subject to market and other conditions.

Cash Flows From Investing Activities

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

	Six Months Ended June 30						Increase
Cash Used for (Provided from) Investing Activities	2012			2011			(Decrease)
	(In millions)
Property Additions:
Regulated distribution	$	443		$	381		$	62
Regulated transmission	122			170			(48		)
Competitive energy services	393			411			(18		)
Other and reconciling adjustments	43			56			(13		)
Cash received in Allegheny merger	—			(590		)	590
Investments	(49		)	54			(103		)
Other	49			53			(4		)
	$	1,001		$	535		$	466

Net cash used for investing activities during the first six months of 2012 increased by $466 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), partially offset by a decrease in property additions ($17 million), a decrease in net purchases of investment securities ($66 million) and

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additional restricted cash investments ($37 million).

During the remainder of 2012, capital requirements for property additions and capital leases are estimated to be approximately $1.4 billion, including approximately $201 million for nuclear fuel.

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. The maximum potential amount of future payments FirstEnergy could have been required to make under these guarantees as of June 30, 2012, was approximately $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)	$	287
LOC (long-term debt) - interest coverage(2)	5
OVEC obligations	300
Other(3)	296
	888
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts	137
LOC (long-term debt) - interest coverage(2)	3
FES’ guarantee of NGC’s nuclear property insurance	85
FES’ guarantee of FGCO’s sale and leaseback obligations	2,199
Other	12
	2,436
Signal Peak & Global Rail facility	350
Surety Bonds	221
LOCs(4)	173
	744
Total Guarantees and Other Assurances	$	4,068

⁽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 $713 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 arrangements, and $32 million for railcar leases.

⁽⁴⁾  Includes $32 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $108 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $34 million pledged in connection with the sale and leaseback of Perry by OE.

Of this amount, substantially all relates to guarantees of wholly-owned consolidated entities. 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.

Collateral and Contingent-Related Features

As part of the normal course of business, FirstEnergy and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuels, and emissions allowances. Certain bilateral agreements and derivative instruments contain provisions that require FirstEnergy or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FirstEnergy's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.

Bilateral agreements and derivative instruments entered into by FirstEnergy and its subsidiaries have margining provisions that require posting of collateral.Based on FES' and AE Supply's power portfolio exposure as ofJune 30, 2012, FES has posted collateral

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of$36 million. The Regulated Distribution segment has posted collateral of$9 million.

These credit-risk-related contingent features stipulate that if the subsidiaries were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

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 FirstEnergy or its subsidiaries.The following chart discloses the additional credit contingent contractual obligations as ofJune 30, 2012:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	373	$	6	$	40	$	419
BB+/Ba1 Credit Ratings	$	429	$	6	$	59	$	494
Full impact of credit contingent contractual obligations	$	658	$	73	$	73	$	804

Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Segment.As ofJune 30, 2012neither 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$46 millionand$13 million, respectively.

Other Commitments and Contingencies

Signal Peak and Global Rail are borrowers under a$350 millionsyndicated 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, continued to guarantee the borrowers' obligations under the current facility. 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.Global Holding is involved in negotiations to refinance the current facility with a bank facility under which it would be the borrower. In connection with such proposed refinancing, FirstEnergy expects to provide the new lenders with a guarantee of Global Holding's obligations, and FirstEnergy and WMB Marketing Ventures, LLC expect to pledge not less than two-thirds of the equity interests in Global Holding and its subsidiaries.

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 $1.5 billion as of June 30, 2012, of which $121 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. FGCO has reached preliminary agreement with some of the parties on the purchase price and certain other parties have invoked an appraisal process to determine the fair market value. On August 2, 2012, FGCO completed the acquisition of the equity interest in certain of the 1987 Bruce Mansfield Plant leases with two owner participants totaling approximately $69.4 million. From time to time we also enter into discussions with certain parties to the arrangements regarding acquisition of owner participant and other interests. We cannot provide assurance that any such acquisitions will occur on satisfactory terms or at all.

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.

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The valuation of derivative contracts is based on observable market information to the extent that such information is available. In cases where such information is not available, FirstEnergy relies on model-based information. The model provides estimates of future regional prices for electricity and an estimate of related price volatility. FirstEnergy uses these results to develop estimates of fair value for financial reporting purposes and for internal management decision making (see Note 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 June 30, 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)	$	3		$	—		$	—		$	—		$	—		$	—		$	3
Other external sources(2)	(100		)	(45		)	(26		)	(27		)	—			—			(198		)
Prices based on models	4			—			—			—			(22		)	(143		)	(161		)
Total(3)	$	(93	)	$	(45	)	$	(26	)	$	(27	)	$	(22	)	$	(143	)	$	(356	)

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

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

⁽³⁾  Includes $(438) million in non-hedge commodity derivative contracts that are primarily related to NUG contracts. NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of June 30, 2012, an adverse 10% change in commodity prices would decrease net income by approximately $2 million during the next 12 months.

Interest Rate Risk

In the second quarter of 2012, FirstEnergy executed a total of $1.6 billion forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%.

Equity Price Risk

As of June 30, 2012, the FirstEnergy pension plan assets were in approximately 21% in equity securities, 52% in fixed income securities, 17% in absolute return strategies, 5% in real estate, 2% in private equity and 3% in 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 six months ended June 30, 2012, FirstEnergy made a voluntary pre-tax contribution to its qualified pension plans of $600 million. See Note 3, Pensions and Other Postemployment Benefits, to the Consolidated Financial Statements for additional details on FirstEnergy's pension plans and OPEB.

NDT funds have been established to satisfy NGC’s, OE's, JCP&L's and other FE subsidiaries' nuclear decommissioning obligations. As of June 30, 2012, approximately 82% of the funds were invested in fixed income securities, 13% of the funds were invested in equity securities and 5% 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 $1,780 million, $280 million and $100 million for fixed income securities, equity securities and short-term investments, respectively, as of June 30, 2012, excluding $7 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $28 million reduction in fair value as of June 30, 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 recognize 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. During the three months ended June 30, 2012, approximately $4 million was contributed to OE's NDT. FENOC has submitted a $95 million parental guarantee to the NRC relating to a shortfall 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 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

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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's principal retail credit risk exposure relates to its 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.

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, on August 31, 2011, PE filed a new comprehensive plan that includes additional and improved programs for the period 2012-2014.The plan is expected to cost approximately$66 millionover the three-year period.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

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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.In its written Order issued July 31, 2012, affirming the determination made at its July 18, 2012 agenda meeting, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year on or before November 1, 2012. JCP&L is unable to predict the outcome of this matter.

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 August 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.

On April 13, 2012, the Ohio Companies filed an application with the PUCO to essentially extend the terms of their current ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012.

As approved, the ESP 3 plan will 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 power to shopping and to non-shopping customers as part of the 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 approved, the ESP 3 plan will provide additional new benefits, including:

• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, 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 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.

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).Sevenadditional parties agreed not to oppose the filing.

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Under the provisions of SB221, the Ohio Companies are required to implement energy efficiency programs that will achieve a total annual energy savings equivalent of approximately1,211GWHs in 2012 (an increase of416,000MWHs over 2011 levels),1,726GWHs in 2013,2,306GWHs in 2014 and2,903GWHs for each year thereafter 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 intended to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. In March 2011, the PUCO issued an Opinion and Order generally approving the Ohio Companies' 2010-2012 portfolio plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies have implemented those programs included in the plan. However, due to the timing of the approval of the plan, the Ohio Companies requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks for 2010. 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 because they achieved their targets in that year. 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.

The Ohio Companies had filed applications for rehearing regarding portions of the PUCO's decision related to the Ohio Companies'three-year portfolio plan, which was later denied. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, which was dismissed on June 20, 2012. In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their next three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.

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 management audit, and final audit reports are currently scheduled to be filed with the PUCO on August 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, the Pennsylvania Companies filed a Joint Petition for Approval of their DSP that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2013 through May 31, 2015.The ALJ issued a Recommended Decision on June 15, 2012, that supported adoption of the Pennsylvania Companies' proposed wholesale procurement plans, denial of their proposed Market Adjustment Charge, and various modifications to the proposed competitive enhancements. Exceptions to the Recommended Decision are currently pending.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.On June 27, 2012, ME and PN filed a Petition for Writ of Certiorari with the Supreme Court of the United States. The PPUC's brief in opposition is due on August 31, 2012, and the ME/PE reply is due on September 10, 2012. If the Supreme Court declines to take the case then ME and PE will pursue their claims in the proceedings that are pending in the U.S. District Court (E.D. PA).

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

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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.The PPUC entered an order on May 10, 2012 approving the Joint Settlement.

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 by the end of 2012, or in a future base distribution rate case.The deadline for the Pennsylvania Companies to file their smart meter deployment plan is December 31, 2012.

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

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financial condition.Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on April 26, 2012, on the proposed rulemaking, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of evidence demonstrating a need for them.

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 West Virginia Supreme Court issued an Order on June 11, 2012, upholding the WVPSC's decision.

The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC alleging the WVPSC order violated PURPA and requested FERC initiate an enforcement action. 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.FERC also noted there may be language in the WVPSC decision that is inconsistent with PURPA. MP filed for rehearing of the FERC's order taking the position that the WVPSC order is consistent with PURPA. New Martinsville filed a complaint in the U.S. District Court on June 4, 2012, alleging that the WVPSC order violates PURPA.

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 deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.

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.

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On December 9, 2008, a transformer at JCP&L's Oceanview substation failed, resulting in an outage on certain bulk electric system (transmission voltage) lines out of the Oceanview and Atlantic substations resulting in customers losing power for up toelevenhours. 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 expects the matter to be resolved for an immaterial amount.

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 advocated 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.

Order No. 1000 issued by FERC on July 21, 2011, requires the submission of a compliance filing in October 2012 by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfies the principles set forth in the order. The PJM transmission owners have announced their intention to submit a compliance filing based on a hybrid methodology of 50% beneficiary pays and 50% postage stamp (or socialization) to be effective for projects approved by the PJM Board on and after the effective date of the compliance filing. FirstEnergy is working with other PJM transmission owners to develop the required filing based on this proposed methodology.

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 FirstEnergy) jointly filed with FERC a proposed cost allocation methodology for certain new transmission projects. The new transmission projects - described as MVPs - are a class

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of transmission projects that are approved via 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 with briefs due from the parties through 2012 and oral argument to be scheduled in 2013.

In February 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.FERC also set for hearing the question of whether it is just and reasonable for ATSI to pay the Michigan Thumb project costs and, if so, the amount of and methodology for calculating ATSI's Michigan Thumb project cost responsibility.On March 28, 2012, FirstEnergy filed for clarification and rehearing of the February 2012 Order, and such request is pending before the FERC.On July 10, 2012, a prehearing conference was convened before a FERC ALJ who will determine the scope of the hearing and thereafter set the hearing schedule.

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 million ($0.5 million - FES; $34.5 million - AE Supply) in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year are estimated to be approximately$11.5 million($11.4 million- FES;$0.1 million- AE Supply).

On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue.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.On July 19, 2012, FERC issued its Order on Rehearing and again dismissed FirstEnergy's complaint without prejudice. FERC noted PJM's ongoing stakeholder process and directed that if the issues were not addressed in that process FirstEnergy could file its complaint again.

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. Exelon Corporation filed a protest, and several other parties filed comments.On July 11, 2012, FERC issued its Order Granting Complaint and Requiring a Compliance Filing. In the order, FERC agreed with FirstEnergy's description of the issues and with FirstEnergy's proposed changes to PJM's rules, and FERC directed PJM to submit a compliance filing within 60 days to implement the changes in the rules.

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

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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.By Order issued June 13, 2012, FERC denied the request for rehearing. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals.

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 additional 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.By Order issued June 13, 2012, that request for rehearing also was denied. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals. 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.The PJM Board has directed the PJM staff to perform additional analysis using the 2012 RTEP assumptions and incorporating the results of the May 2012 RPM base residual auction. The PJM staff is expected to report its conclusions from this analysis to the Transmission Expansion Advisory Committee on August 9, 2012. All applications for authorization to construct the project filed with state commissions have been withdrawn.

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.

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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.

MISO Capacity Portability

On June 11, 2012, the FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO Stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. Comments are due on August 10, 2012, and reply comments are due on August 27, 2012. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including the prices at which those auctions would clear. FirstEnergy anticipates submitting initial comments by August 10, 2012 and, depending on the comments submitted by other parties, submitting reply comments by August 27, 2012.

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.On July 27, 2012, FirstEnergy filed a motion for summary judgment arguing the Plaintiff's remaining claims for civil penalties are barred by the statute of limitations. 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

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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. On June 29, 2012, EPA issued another CAA section 114 request for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. 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 June 12, 2012, the EPA revised certain CSAPR 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.

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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 deactivation 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.MATS has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. FirstEnergy and other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS.Depending on the outcome of these proceedings and how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS is estimated to be$975 millionand 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 system832megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. However, when these units did not clear the May PJM capacity auction, the decision was made to not proceed with the project at this time. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant deactivations and requested RMR arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18.On July 10, 2012, FirstEnergy filed with FERC, for informational purposes, the compensation arrangements for these units which will remain in effect for as long as these generating units continue to operate. On July 16, 2012, FGCO and ATSI filed an application with FERC for authorization to transfer from FGCO to ATSI certain assets associated with Eastlake Units 1-5 and Lakeshore Unit 18 for conversion to synchronous condensers by ATSI for transmission reliability purposes as directed by PJM. Upon FERC approval, it is expected that the assets will be transferred in staggered closings when the units are no longer needed for RMR purposes. During the three months and six months ended June 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately$10 million($6 million by FES) and $17 million ($10 million by FES), respectively, as a result of the deactivations. These costs are included in "other operating expenses" in the Consolidated Statements of Income.

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 deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates 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

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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, South 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 U.S. 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. In July 2012, the period for finalizing the Section 316(b) regulation was extendedto July 27, 2013.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 June 5, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil liability claims for those petroleum spills toJanuary 31, 2013. 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 proposed settlement, in the form of a Consent Decree, was lodged with the Commonwealth Court of Pennsylvania and published in the June 23, 2012, Pennsylvania Bulletin for a 30-day public comment period. 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

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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 setting deadlines for MP to meet certain of the effluent limits that were 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. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a 60-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. 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 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.

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.On July 27, 2012, the PA DEP filed a complaint against FGCO in the U.S. District Court for the Western District of Pennsylvania with claims under the Resource Conservation and Recovery Act and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FGCO to resolve those claims. The Consent Decree will be published to allow for a 30-day public comment period and requires FGCO to conduct monitoring, studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. BMP is pursuing several options for disposal of CCB following December 31, 2016.

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 ofJune 30, 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$122 million(including$86 millionapplicable to JCP&L) have been accrued throughJune 30, 2012. Included in the total are accrued liabilities of approximately$79 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.

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OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofJune 30, 2012, FirstEnergy had approximately$2 billioninvested 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 intervenors supplemented their petition for a contention on the shield building on multiple occasions. On July 9, 2012, the intervenors petitioned the ASLB for a new contention on the environmental impacts of temporary spent fuel storage at Davis-Besse due to the lack of a repository and the disposal of these wastes. The ASLB has yet to rule on the admission of these latest requests for new contentions.

Similarly, on June 18 and 19, 2012, the intervenors in the Davis-Besse license renewal proceeding and other petitioners requested that the NRC suspends the issuance of final decisions in all pending reactor licensing proceedings as a result of the decision in the case of State of New York v. NRC, No. 11-1045. (D.C. Cir. June 8, 2012). In this case, the D.C. Circuit vacated the NRC's updated Waste Confidence Decision and its Temporary Storage Rule and remanded those rulemakings to the NRC for further consideration. FENOC and other Licensees opposed the suspension request. By order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the D.C. Circuit decision and all pending contentions on this topic should be held in abeyance until further order. The NRC also directed that all licensing reviews and proceedings should continue to move forward.

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.On June 21, 2012, the NRC issued an Inspection Report that concluded that FENOC established a sufficient basis for the causes of the shield building laminar cracking.

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. Additional adverse findings by the NRC could result in further inspection activities.

On March 12, 2012, the NRC 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

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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 has concluded and an oral argument was held on May 16, 2012. A decision from the Appellate court is expected in the fourth quarter of 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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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, the uncommitted output of AE Supply, 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, and pursuant to full output, cost-of-service PSAs.

FES’ revenues are derived from sales to individual retail customers, sales to customers 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 as well as economic activity and weather conditions in the Midwest and Mid-Atlantic regions of the United States.

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 $47 million in the first six months of 2012 compared to the same period of 2011, as more fully described below.

Revenues -

Total revenues increased $288 million, or 11%, in the first six months of 2012, compared to the same period of 2011, primarily due to growth in direct and governmental aggregation sales and wholesale sales partially offset by a net decline in POLR and structured sales. Revenues were also adversely impacted by lower unit prices compared to the first six months of 2011.

The increase in total revenues resulted from the following sources:

	Six Months Ended June 30				Increase
Revenues by Type of Service	2012		2011		(Decrease)
	(In millions)
Direct and Governmental Aggregation	$	2,040	$	1,765	$	275
POLR and Structured Sales	426		607		(181		)
Wholesale	387		156		231
Transmission	60		56		4
RECs	5		44		(39		)
Other	54		56		(2		)
Total Revenues	$	2,972	$	2,684	$	288

	Six Months Ended June 30		Increase
MWH Sales by Type of Service	2012	2011	(Decrease)
	(In thousands)
Direct	25,954	21,219	22.3	%
Governmental Aggregation	9,930	8,279	19.9	%
POLR and Structured Sales	7,645	9,561	(20.0	)%
Wholesale	86	1,380	(93.8	)%
Total MWH Sales	43,615	40,439	7.9	%

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The increase in combined direct and governmental aggregation revenues of $275 million resulted from the acquisition of new residential, commercial and industrial customers. Sales were provided to approximately 2.0 million residential, commercial and industrial customers as of June 2012, compared to approximately 1.7 million as of June 2011. The volume increase was partially offset by lower unit prices for commercial, industrial and governmental aggregation customers given declining electric market prices.

The decrease in combined POLR and structured revenues of $181 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 $231 million due to increased gains of $228 million on financially settled contracts and a $42 million increase in capacity revenues. These increases were partially offset by decreased volumes sold.

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 and Governmental Aggregation:
Effect of increase in sales volumes	$	381
Change in prices	(106		)
	$	275

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of decrease in sales volumes	$	(122	)
Change in prices	(59		)
	$	(181	)

Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(39	)
Gain on settled contracts	228
Capacity revenue	42
	$	231

Operating Expenses -

Total operating expenses increased by $220 million in the first six 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 six months of 2012 compared with the same period last year:

Source of Change in Fuel and Purchased Power	Increase (Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	22
Change due to volume consumed	(13		)
	9
Nuclear Fuel:
Change due to increased unit costs	1
Change due to volume consumed	6
	7
Non-affiliated Purchased Power:
Change due to decreased unit costs	(142		)
Change due to volume purchased	147
Loss on settled contracts	229
Capacity expense	61
	295
Affiliated Purchased Power:
Change due to decreased unit costs	(53		)
Change due to volume purchased	41
Loss on settled contracts	128
	116
Net Increase in Fuel and Purchased Power Costs	$	427

The increase in purchased power volumes primarily relates to the overall increase in sales volumes and economic purchases.

Other operating expenses decreased by $190 million in the first six months of 2012, compared to the first six months of 2011 due to the following:

• Transmission expenses decreased $89 million due primarily to lower congestion, network and line loss costs, partially offset by higher ancillary costs.

• Nuclear operating costs decreased by $8 million due primarily to lower labor and materials and equipment costs. During the first six months of 2012, there were refueling outages at Davis Besse and Beaver Valley Unit 1 compared to the first six months of 2011, which included refueling outages at Perry and Beaver Valley Unit 2. Total outage days were reduced in the first six months of 2012 compared to the same period of 2011.

• Fossil operating costs decreased by $16 million due primarily to lower contractor and materials and equipment costs resulting from a decrease in planned and unplanned outages, partially offset by severance costs associated with certain fossil units to be deactivated.

• Other operating expenses decreased by $77 million primarily due to favorable mark-to-market adjustments on commodity contract positions ($64 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. These decreases were partially offset by increases of $41 million for labor, agent fees, professional and contractor services and costs associated with our retail business.

Impairment charges on long-lived assets decreased by $20 million due to a 2011 charge related to peaking facilities that were subsequently sold in 2011.

General taxes increased by $9 million due to an increase in revenue-related taxes.

Depreciation expense decreased by $6 million primarily due to a lower asset base resulting from 2011 asset sales and impairments, combined with slightly reduced depreciation rates that reflect a periodic study that updated estimated economic lives for certain

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fossil assets and credits resulting from a settlement with the DOE regarding storage of spent nuclear fuel.

Other Expense -

Total other expense decreased by $19 million in the first six months of 2012, compared to the same period of 2011, primarily due to lower net interest expense of $13 million resulting from debt reductions in 2011 and credits related to the settlement with the DOE noted above. Non-operating income increased by $16 million due primarily to additional proceeds on 2011 asset sales that were earned during the first six months of 2012, and was partially offset by lower investment income ($10 million) on the NDTs.

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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 customers 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 during the first six months of 2012, compared to the same period of 2011, as more fully described below.

Revenues -

Revenues decreased by $3 million in the first six months of 2012, compared with the same period of 2011, due to a decrease in distribution and retail generation revenues.

Distribution revenues decreased by $1 million in the first six 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. Reduced deliveries to the residential and commercial classes were driven by lower weather-related usage and declining average customer consumption. Average prices for residential customers were relatively unchanged as the implementation of Ohio's Rider NMB in June 2011, which recovers non-market based charges from PJM, including network integration transmission service charges, were offset by the suspension of Ohio's deferred cost recovery rider in December 2011. 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 six months of 2012, compared to the same period of 2011, are summarized in the following tables:

Distribution MWH Deliveries	Increase (Decrease)
Residential	(4.5	)%
Commercial	(0.3	)%
Industrial	6.3	%
Net Increase in Distribution MWH Deliveries	0.3	%

Distribution Revenues	Increase (Decrease)
	(In millions)
Residential	$	(12	)
Commercial	5
Industrial	6
Net Decrease in Distribution Revenues	$	(1	)

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. Retail generation revenues decreased by $1 million primarily due to reduced MWH sales from increased customer shopping, partially offset by higher average prices in the residential customer class. Lower MWH sales were primarily due to lower weather-related usage resulting from heating degree days that were 22% below 2011 levels, declining average customer consumption, reduced residential accounts as well as an increase in customer shopping levels to 73% compared to 69% in the same quarter of last year. Higher average prices for residential customers were primarily due to the recovery of residential generation credits for electric heating discounts, which began in September 2011.

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

Retail Generation MWH Sales	Decrease
Residential	(12.6	)%
Commercial	(23.4	)%
Industrial	(7.0	)%
Decrease in Retail Generation Sales	(13.3	)%

Retail Generation Revenues	Increase (Decrease)
	(In millions)
Residential	$	30
Commercial	(22		)
Industrial	(9		)
Net Decrease in Retail Generation Revenues	$	(1	)

Wholesale generation revenues decreased by $4 million in the first six 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 six 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	$	(60	)
Other operating expenses	38
Provision for depreciation	3
Amortization of regulatory assets, net	12
General taxes	1
Net Decrease in Operating Expenses	$	(6	)

Purchased power costs decreased in the first six months of 2012, compared to the same period of 2011, due to lower MWH purchases resulting from reduced requirements from lower generation sales. The increase in other operating expenses for the first six 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 Rider NMB discussed above. Amortization of regulatory assets, net, increased primarily due to lower deferred residential generation credits in 2012. Provision for depreciation expense increased mainly due to an increase in the depreciable asset base.

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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 decreased by $3 million in the first six months of 2012, compared to the same period of 2011, as more fully described below.

Revenues

Revenues decreased by $263 million, or 21%, in the first six 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 $81 million in the first six 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 in the residential class, reflecting decreased weather-related usage in the first six months of 2012, partially offset by higher MWH deliveries to industrial customers.

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

Distribution MWH Deliveries	Increase (Decrease)
Residential	(4.9	)%
Commercial	(0.8	)%
Industrial	2.2	%
Net Decrease in Distribution Deliveries	(2.2	)%

Distribution Revenues	Decrease
	(In millions)
Residential	$	(41	)
Commercial	(32		)
Industrial	(8		)
Decrease in Distribution Revenues	$	(81	)

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. Retail generation revenues decreased by $104 million due to lower retail generation MWH sales in all customer classes primarily due to lower weather-related usage and an increase in customer shopping levels to 50% in the first six months of 2012, compared to 43% in the same period of 2011.

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

Retail Generation MWH Sales	Decrease
Residential	(12.3	)%
Commercial	(15.9	)%
Industrial	(21.9	)%
Decrease in Retail Generation Sales	(13.5	)%

Retail Generation Revenues	Decrease
	(In millions)
Residential	$	(69	)
Commercial	(29		)
Industrial	(6		)
Decrease in Retail Generation Revenues	$	(104	)

Wholesale generation revenues decreased by $78 million in the first six 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 $263 million in the first six 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	$	(180	)
Other operating expenses	9
Provision for depreciation	8
Amortization of regulatory assets, net	(94		)
General taxes	(6		)
Net Decrease in Operating Expenses	$	(263	)

Purchased power costs decreased by $180 million in the first six months of 2012 due to the expiration of a NUG contract and a decrease in volumes required, as described above. This was partially offset by the completion of the NJBPU-approved NUG deferred cost recovery, which was the primary cause for the decrease in amortization of regulatory assets, net.

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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 June 30, 2012, other than the changes resulting from the system integration discussed below, there have been no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s, FES’, OE’s and JCP&L’s internal control over financial reporting.

In April 2012, FirstEnergy integrated Allegheny into its IT business networks and financial systems following completion of the merger in 2011. This initiative completes the integration of Allegheny's financial operations, processes and internal controls into FirstEnergy.

PART II. OTHER INFORMATION

ITEM 1.        LEGAL PROCEEDINGS

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

ITEM 1A.    RISK FACTORS

For the quarter ended June 30, 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 second quarter of 2012.

	Period
	April		May		June		Second Quarter
Total Number of Shares Purchased(1)	60,533		416,736		454,399		931,668
Average Price Paid per Share	$	45.99	$	47.37	$	47.09	$	47.15
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

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ITEM 5.        OTHER INFORMATION

None

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ITEM 6.        EXHIBITS

Exhibit Number
FirstEnergy
	10.1		U.S. $1,000,000,000 Credit Agreement, dated as of May 8, 2012, among FirstEnergy Transmission, LLC, American Transmission Systems, Incorporated and Trans-Allegheny Interstate Line Company, as borrowers, PNC Bank, National Association, as administrative agent, and the lending banks and fronting banks identified therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.1, File No. 333-21011).
	10.2		Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.2, File No. 333-21011).
(A)	10.3		Form of Officer Indemnification Agreement (incorporated by reference to FirstEnergy's Form 8-K filed July 23, 2012, Exhibit 10.1, File No. 333-21011).
(B)	12		Fixed charge ratio
(B)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(B)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(B)	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101		The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 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 and (v) document and entity information.
FES
(B)	10.1		First Supplemental Trust Indenture, dated April 2, 2012, supplementing and amending that certain Trust Indenture dated as of April 1, 2006 between the Ohio Water Development Authority and The Bank of New York Mellon Trust Company, N.A. as Trustee securing pollution control revenue refunding bonds issued on behalf of FirstEnergy Generation Corp. (FirstEnergy Generation Corp. Project), which trust indenture, as amended, is substantially similar to various other PCRB trust indentures of FirstEnergy Generation Corp.
(B)	10.2		First Amendment to Loan Agreement dated April 2, 2012, amending the Waste Water Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Generation Corp. dated as of April 1, 2006, which loan agreement, as amended, is substantially similar to various other PCRB loan agreements of FirstEnergy Generation Corp.
(B)	10.3		First Supplemental Trust Indenture, dated April 2, 2012, supplementing and amending that certain Trust Indenture dated as of December 1, 2006 between the Ohio Water Development Authority and The Bank of New York Mellon Trust Company, N.A., as Trustee securing State of Ohio Pollution Control Revenue Refunding Bonds (FirstEnergy Nuclear Generation Corp. Project), which trust indenture, as amended, is substantially similar to various other PCRB trust indentures of FirstEnergy Nuclear Generation Corp.
(B)	10.4		First Amendment to Loan Agreement dated April 2, 2012, amending the Waste Water Facilities and Solid Waste Facilities Loan Agreement between the Ohio Water Development Authority and FirstEnergy Nuclear Generation Corp. dated as of December 1, 2006, which loan agreement, as amended, is substantially similar to various other PCRB loan agreements of FirstEnergy Nuclear Generation Corp.
	10.5		Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Solutions Corp., and Allegheny Energy Supply Company, LLC, as borrowers, JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.3, File No. 333-21011).
(B)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(B)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(B)	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended June 30, 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 and (v) document and entity information.
OE
	10.1		Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.2, File No. 333-21011).
(B)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(B)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(B)	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350

116

	101	*	The following materials from the Quarterly Report on Form 10-Q of Ohio Edison Company. for the period ended June 30, 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 and (v) document and entity information.
JCP&L
	10.1		Amendment, dated as of May 8, 2012, to the Credit Agreement, dated as of June 17, 2011, among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, American Transmission Systems, Incorporated, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as borrowers, the Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (incorporated by reference to FE's Form 8-K filed May 11, 2012, Exhibit 10.2, File No. 333-21011).
(B)	31.1		Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(B)	31.2		Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(B)	32		Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	*	The following materials from the Quarterly Report on Form 10-Q of Jersey Central Power & Light Company. for the period ended June 30, 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 and (v) document and entity information.
(A)			Management contract or compensatory plan, contract or agreement filed pursuant to Item 601 of Regulation S-K.
(B)			Provided herein in electronic format as an exhibit.

* 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.

117

SIGNATURES

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

August 7, 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) 

118

EX-10.1

EXHIBIT 10.1

OHIO WATER DEVELOPMENT AUTHORITY

to

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

FIRST SUPPLEMENTAL TRUST INDENTURE

Dated April 2, 2012

Supplementing and amending that certain Trust Indenture
dated as of April 1, 2006

Securing $90,140,000 of State of Ohio
Pollution Control Revenue Refunding Bonds
Series 2006-A
(FirstEnergy Generation Corp. Project)

EXHIBIT 10.1

THIS FIRST SUPPLEMENTAL TRUST INDENTURE (the “First Supplemental Indenture”), dated April 2, 2012, is made by and between the Ohio Water Development Authority, a body politic and corporate duly organized and validly existing under the laws of the State of Ohio (the “Issuer”), and The Bank of New York Mellon Trust Company, N.A., a national banking association duly organized and existing under the laws of the United States of America and authorized to exercise trust powers under the laws of the State of Ohio, as the current trustee (the “Trustee”) under the Original Indenture (as defined below), with capitalized terms not otherwise defined herein having the same meaning as in the Original Indenture;

W I T N E S S E T H:

WHEREAS, the Issuer has issued $90,140,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-A (FirstEnergy Generation Corp. Project) (the “Bonds”) pursuant to Chapter 6121 of the Ohio Revised Code and a Trust Indenture dated as of April 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 FirstEnergy Generation Corp. (the “Company”) in the refinancing of a portion of the cost of the acquiring, constructing and installing certain facilities comprising “waste water facilities” as defined in Section 6121.01 of the Ohio Revised Code; and

WHEREAS, pursuant to the Original Indenture, the Issuer assigned to the Trustee the Issuer’s rights to receive loan payments under the Original Loan Agreement (defined below) and certain other rights of the Issuer thereunder; and

WHEREAS, the Issuer loaned the proceeds of the Bonds to the Company, pursuant to a Waste Water Facilities Loan Agreement dated as of April 1, 2006 between the Issuer and the Company (the “Original Loan Agreement”), which provides for loan payments by the Company in amounts sufficient to pay, when due, the principal or redemption price of and interest on the Bonds; 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 (the “LLC Conversion”) and in connection therewith the Company desires to amend the Original Loan Agreement to allow for such LLC Conversion; and

WHEREAS, the Company has requested that the Issuer and the Trustee amend the Original Indenture to provide that conversions from the Daily Rate, the Weekly Rate or the Semi-Annual Rate may be made on any Business Day, and to make certain other amendments to the Original Indenture of an administrative nature (including amendments to the Original Indenture to provide for the LLC Conversion); and

WHEREAS, Section 15.01(j) of the Original Indenture provides that the Indenture may be amended or supplemented in any respect from time to time by a supplemental indenture entered into by the Issuer and the Trustee and authorized by a resolution of the Issuer filed with the Trustee, without the consent of the Bondholders, in connection with any mandatory purchase of all of the Bonds, provided that such amendment is not effective until after such mandatory purchase

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EXHIBIT 10.1

and payment of the purchase price in connection therewith; and

WHEREAS, the Company has directed that the Bonds be converted from a Daily Rate to a Weekly Rate on April 2, 2012, and in connection therewith the Bonds will be subject to mandatory purchase on such date; and

WHEREAS, the Trustee and the Issuer desire to amend the Original Indenture as requested by the Company, such amendment to be effective upon mandatory purchase of the Bonds on April 2, 2012 and payment of the purchase price in connection therewith; and

WHEREAS, concurrently herewith, the Issuer and the Company are entering into a First Amendment to Loan Agreement pursuant to which the Original Loan Agreement will be amended to provide for the LLC Conversion; and

WHEREAS, all things necessary have been done and performed to constitute this First Supplemental Indenture as a valid and binding agreement and the execution and delivery of this First Supplemental Indenture has in all respects been authorized;

NOW, THEREFORE, the Issuer hereby agrees and covenants with the Trustee and with the respective holders and owners, from time to time, of the Bonds as follows:

ARTICLE IAMENDMENTS TO ORIGINAL INDENTURE

Section 1.01Caption of the Bonds. All references in the Indenture to the caption of the Bonds are hereby amended to replace “(FirstEnergy Generation Corp. Project)” with “(FirstEnergy Generation Project)”.

Section 1.02Company Name. 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 Original Indenture and the Bond, in each case as amended by this First Supplemental Indenture, without the execution of an amended Bond or the filing of any instrument or any further act, deed or conveyance on the part of any of the parties hereto.

Section 1.03Definitions. 

(a)“Guaranty Agreement” means each of (i) the Guaranty Agreement dated as of March 26, 2007 executed and delivered by FirstEnergy Solutions Corp. (“FES”) and acknowledged by the Company in favor of the Guaranteed Parties as defined therein, including the Trustee as the holder of the Note, as the same may be amended, restated, supplemented or otherwise modified from time to time; and (ii) the Guaranty Agreement dated as of March 26, 2007 executed and delivered by FirstEnergy Generation Corp. and acknowledged by FES in favor of the Guaranteed Parties as defined therein, including the Trustee as the holder of the Note, as the same may be amended, restated, supplemented or otherwise modified from time to time.

(b)“Guarantor” means any Person designated as a guarantor under a Guaranty Agreement.

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EXHIBIT 10.1

(c)The definition of “Municipal Index” in Article 1 of the Original Indenture is hereby amended and restated to read as follows: “ “Municipal Index” shall mean the Securities Industry and Financial Markets Association Municipal Swap Index™ as of the most recent date for which such index was published or such other weekly, high-grade index comprised of seven-day, tax-exempt variable rate demand notes produced by Municipal Market Data, Inc., or its successor, or otherwise designated by the Securities Industry and Financial Markets Association; provided, however, that, if such index is no longer provided by Municipal Market Data, Inc. or its successor, the “Municipal Index” means such other reasonably comparable index selected by the Remarketing Agent.”

Section 1.04Failure to Set Interest Rate. Section 2.02(c)(xi) of the Original Indenture is hereby amended and restated in its entirety as follows: “In the event that the interest rate on a Bond is not or cannot be determined by the Remarketing Agent for whatever reason pursuant to (ii), (iii), (iv), (v), (vi), (vii), (viii) or (ix) above, the Interest Rate Mode of such Bond shall be converted automatically to the Weekly Rate (without the necessity of complying with the requirements of Section 2.02(e) including, but not limited to, the requirement of mandatory purchase) and the Weekly Rate shall be equal to the Municipal Index. Anything in this Section 2.02(c)(xi) to the contrary notwithstanding, if a Credit Facility is then in effect, the Rate Period determined shall not extend beyond the remaining term of such Credit Facility minus fifteen (15) days and if such fifteenth day is not a Business Day, then the immediately preceding Business Day.”

Section 1.05Long-Term Rate Period.

(a)The second sentence of Section 2.02(d)(i) of the Original Indenture is hereby amended and restated to read as follows: “Each Long-Term Rate Period shall be more than one year in duration, shall be for a period which is an integral multiple of six months, and shall end on the day next preceding an Interest Payment Date; provided that if a Long-Term Rate Period commences on a day other than a May 15 or a November 15, such Long-Term Rate Period may be for a period which is not an integral multiple of six months but shall be of a duration as close as possible to (but not in excess of) such Long-Term Rate Period established by the Company and shall terminate on a day preceding an Interest Payment Date, and each successive Long-Term Rate Period thereafter for such bonds shall be for the full period established by the Company until a different Long-Term Rate Period is specified by the Company in accordance with this Section or until the occurrence of a Conversion Date or the maturity of the Bonds; and further provided that no Long-Term Rate Period shall extend beyond the final Maturity Date of the Bonds (and any Long-Term Rate Period that extends to the day preceding the Maturity Date may be for a period which is not an integral multiple of six months).”

(b)Section 2.02(d)(ii) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Change of Long-Term Rate Period. The Company may change Bonds from one Long-Term Rate Period to another Long-Term Rate Period (provided that the portion thereof not changed to another Long-Term Rate Period shall also be in authorized denominations) on any Business Day on which such Bonds are subject to optional redemption pursuant to Section 9.01(a)(viii) by notifying the Issuer, the Trustee, the Paying Agent, the Credit Facility Issuer, the Tender Agent and the Remarketing Agent in writing at least four (4) Business

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EXHIBIT 10.1

Days prior to the thirtieth day prior to the proposed effective date of the change; provided that, if a Credit Facility is then in effect, the Company shall not be entitled to elect a change in the Long-Term Rate Period on a date on which the purchase price determined under Section 5.01(b)(i) includes any premium unless the Trustee has received written confirmation from the Credit Facility Issuer, on or before the date on which the Bond Registrar must provide notice of such change to the Bondholders under Section 2.02(d)(iii), that it can draw under a Credit Facility on the proposed effective date of the change in an aggregate amount sufficient to enable the Tender Agent to pay the premium due upon the mandatory purchase of such Bonds on such proposed effective date pursuant to Section 5.01(b)(i). Such notice shall specify (A) the aggregate principal amount of Bonds to be changed to a new Long-Term Rate Period, (B) the information required to be contained in the notice given by the Bond Registrar to the Bondholders pursuant to Section 2.02(d)(iii), (C) the anticipated last day of such new Long-Term Rate Period, which shall be the earlier of the day before the Maturity Date of the Bonds or the day immediately preceding any May 15 or November 15, and which is more than one year after the effective date of such change, (D) the purchase price for Bonds determined under Section 5.01(b)(i), and (E) if such change is conditional, the interest rate limitations. Any change by the Company of the Long-Term Rate Period may be conditional upon the establishment of an interest rate within certain limits chosen by the Company. The Remarketing Agent shall establish what would be the interest rate for the proposed Long-Term Rate Period as required by Section 2.02(c)(vi). If the interest rate established by the Remarketing Agent is not within the limits chosen by the Company, then the change in the Long-Term Rate Period may be cancelled by the Company, in which case the Company’s notice thereof shall be of no effect and no such change shall occur. Notwithstanding the foregoing, no change in the Long-Term Rate Period shall be effective unless the Credit Facility, if any, held or to be held by the Trustee after such change in the Long-Term Rate Period shall extend for the length of such Long-Term Rate Period plus fifteen (15) days.”

(c)Section 2.02(d)(iii) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Notice of Change in Long-Term Rate Period. The Bond Registrar shall notify the affected Bondholders of the mandatory tender in connection with any change in the Long-Term Rate Period pursuant to Section 2.02(d)(ii) by first class mail, postage prepaid, at least 30 but not more than 60 days before the effective date of such change. The notice will state the date of the mandatory tender associated with the change in Long-Term Rate Period, and that, on such date, Bonds will be purchased (and the purchase price therefor) and that if any owner of the Bonds shall fail to deliver a Bond for purchase with an appropriate instrument of transfer to the Tender Agent for purchase on said date, and if the Tender Agent is in receipt of the purchase price therefor, any such Bond not delivered shall nevertheless be deemed purchased on such effective date and shall cease to accrue interest on and from such date.”

(d)Section 2.02(d)(iv) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Cancellation of Change in Long-Term Rate Period. Notwithstanding any provision of this Section 2.02(d), the Long-Term Rate Period shall not be changed if: (A) the Remarketing Agent has not determined the interest rate for the new Long-Term Rate Period in accordance with this Section 2.02 or (B) all of the Bonds that are to be purchased pursuant to Section 5.01(b) are not remarketed or sold by the Remarketing Agent or (C) if such change is cancelled by the Company as provided in Section 2.02(d)(ii) above. If such change fails

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EXHIBIT 10.1

to occur, the Bonds shall be converted automatically to the Weekly Rate and the interest rate shall be equal to the Municipal Index. If the proposed change of the Long-Term Rate Period is cancelled as provided in this paragraph, any mandatory purchase of such Bonds will remain effective. Anything in this Section 2.02(d)(iv) to the contrary notwithstanding, if a Credit Facility is then in effect, the Rate Period determined upon a cancellation of a change in the Long-Term Rate Period shall not extend beyond the remaining term of such Credit Facility minus fifteen (15) days and if such fifteenth day is not a Business Day, then the immediately preceding Business Day.”

Section 1.06Conversion.

(a)Section 2.02(e)(i) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “(i)  Method of Conversion. The Interest Rate Mode for Bonds is subject to Conversion to a different Interest Rate Mode (provided that the portion thereof not converted shall also be in authorized denominations) from time to time by the Company, such right to be exercised by notifying the Issuer, the Trustee, the Paying Agent, the Credit Facility Issuer, the Tender Agent, the Remarketing Agent, the Auction Agent, the Broker-Dealer, and, in the case of a Conversion to or from the Commercial Paper Rate, the Bond Registrar at least four (4) Business Days prior to (x) in the cases of Conversion from the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate, the thirtieth day prior to the effective date of such proposed Conversion and (y) in all other cases, the fifteenth day prior to such proposed effective date; provided that, in any event, with respect to Conversion from the Commercial Paper Rate, the effective date of such Conversion may not occur until the latest Interest Payment Date relating to the Commercial Paper Rate Period then in effect for the Bonds to be converted, and, provided further, that no new Commercial Paper Rate Period for such Bonds may be established subsequent to such notice which would have an Interest Payment Date later than the proposed date of Conversion; and provided, further, that, if a Credit Facility is then in effect, the Company shall not be entitled to elect to convert Bonds to a different Interest Rate Mode on a date on which the purchase price determined under Section 5.01(b)(i) includes any premium, unless the Trustee has received written confirmation, on or before the date on which the Bond Registrar must provide notice of such Conversion to Bondholders under Section 2.02(e)(iii), from the Credit Facility Issuer that it can draw under the Credit Facility on the proposed effective date of the Conversion in an aggregate amount sufficient to enable the Tender Agent to pay any premium due upon any mandatory purchase of Bonds on such proposed effective date pursuant to Section 5.01(b)(i). Such notice shall specify (A) the effective date of such Conversion and the information required by Section 2.02(e)(iii), (B) the Interest Rate Mode into which the Company anticipates that the Bonds will be converted, (C) if such Conversion is conditional, the interest rate limitations, and (D) if it is anticipated that the Conversion will be to the Long-Term Rate, the last day of the anticipated Long-Term Rate Period, which Long-Term Rate Period shall meet the requirements of Section 2.02(d)(i). In addition, the notice shall confirm that Bond Counsel expects to be able to deliver, on the date of Conversion, an opinion of Bond Counsel stating such Conversion is authorized or permitted by the Act and is authorized by this Indenture and will not adversely affect the exclusion from gross income of interest on the Bonds for federal income tax purposes. Any Conversion by the Company of the Interest Rate Mode to the Semi-Annual Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate may be conditional upon the establishment of an initial interest rate determined for such Interest Rate Mode within certain limits chosen by the Company.

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EXHIBIT 10.1

The Remarketing Agent shall establish what would be the interest rate for the proposed Interest Rate Mode in accordance with Section 2.02(c). If the interest rate established by the Remarketing Agent is not within the limits chosen by the Company, then such Conversion may be cancelled by the Company by telephonic notice (to be confirmed in writing) to the Trustee, the Credit Facility Issuer, the Tender Agent and the Remarketing Agent by the close of business on the day on which the interest rate has been determined, in which case, the Company’s notice of Conversion shall be of no effect and the Conversion shall not occur.”

(b)Section 2.02(e)(ii)(A) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “the Conversion Date must be a date on which the Bonds are subject to optional redemption pursuant to Section 9.01(a); provided that if the Interest Rate Mode is the Daily Rate, the Weekly Rate or the Semi-Annual Rate, the Conversion Date may be any Business Day even if not an Interest Payment Date;”

(c)Section 2.02(e)(ii)(F) of the Original Indenture is hereby amended to replace the period at the end with “; and” and a new subsection (G) is hereby added as follows: “(G) the Trustee shall have received the opinion of Bond Counsel contemplated by Section 2.02(e)(i) by the opening of business at the Designated Office of the Trustee on the effective date of Conversion.”

(d)Section 2.02(e)(iii) of the Original Indenture is hereby amended and restated in its entirety to read as follows:

“Notice to Bondholders of Conversion of Interest Rate. The Bond Registrar shall notify the affected Bondholders of each Conversion by first class mail, postage prepaid, at least fifteen (15) days but not more than thirty (30) days before the Conversion Date if the Interest Rate Mode is the Commercial Paper Rate, the Dutch Auction Rate, the Daily Rate, the Weekly Rate, the Semi-Annual Rate or the Annual Rate and at least thirty (30) days but not more than sixty (60) days before the Conversion Date if the Interest Rate Mode is the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate. The notice shall state:

(A)    that the Interest Rate Mode will be converted;

(B)    the Conversion Date; and

(C)    (1) that Bonds will be subject to mandatory purchase on the Conversion Date in accordance with Section 5.01(b), (2) the purchase price, and (3) that if any owner of Bonds shall fail to deliver a Bond for purchase with an appropriate instrument of transfer to the Tender Agent on the Conversion Date, and if the Tender Agent is in receipt of the purchase price therefor, such Bond not delivered shall nevertheless be purchased on the Conversion Date and shall cease to accrue interest on and from such date.”

(e)Section 2.02(e)(iv) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Cancellation of Conversion of Interest Rate Mode. Notwithstanding any provision of this Section 2.02, the Interest Rate Mode for Bonds shall not be

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EXHIBIT 10.1

converted if: (A) the Remarketing Agent has not determined the initial interest rate for the new Interest Rate Mode in accordance with this Section 2.02 or (B) all of the Bonds that are to be purchased pursuant to Section 5.01(b) are not remarketed or sold by the Remarketing Agent or (C) the Conversion is cancelled by the Company as provided in Section 2.02(e)(i) above or (D) any other limitations on Conversion set forth in Section 2.02(e)(ii) shall not have been complied with. If such Conversion fails to occur, such Bonds in the Dutch Auction Rate shall remain in the Dutch Auction Rate and such Bonds in any other Interest Rate Mode shall be converted automatically to the Weekly Rate and the interest rate shall be equal to the Municipal Index. If the proposed Conversion of Bonds is cancelled as provided in this paragraph, any mandatory purchase of Bonds shall nevertheless be effective and such Bonds shall bear interest as provided in the preceding sentence. Anything in this Section 2.02(e)(iv) to the contrary notwithstanding, if a Credit Facility is then in effect, the Rate Period determined upon a failed Conversion shall not extend beyond the remaining term of such Credit Facility minus fifteen (15) days and if such fifteenth day is not a Business Day, then the immediately preceding Business Day.”

Section 1.07Drawings on Credit Facility.

(a)Section 5.06(a) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “If the Interest Rate Mode for the Bonds to be purchased is not the Commercial Paper Rate, then at or prior to 11:45 a.m. (New York City time) on each Purchase Date, the Tender Agent shall, by Electronic Notice, notify the Trustee of the amount of moneys delivered to it by the Remarketing Agent pursuant to Section 5.07 and which are held in the Remarketing Proceeds Account in the Purchase Fund. The Trustee shall by 12:00 noon (New York City time) draw under the Credit Facility, if any, held by the Trustee in accordance with its terms in a manner so as to furnish immediately available funds by 2:30 p.m. (New York City time) on such Purchase Date, in an amount sufficient, together with moneys described in Section 5.03(c)(i) and available for such purchase, to enable the Tender Agent to pay the purchase price of such Bonds to be purchased on such Purchase Date, directly to the Tender Agent which shall deposit those moneys directly into the Credit Facility Proceeds Account; provided, further, that if the Tender Agent is other than the Trustee and the Trustee does not receive the aforesaid Electronic Notice by the time set forth above, the Trustee shall draw under such Credit Facility the full amount of the purchase price of such Bonds to be purchased on such Purchase Date. If the Credit Facility has been repudiated or if such funds for whatever reason are not provided under the Credit Facility by 2:30 P.M. (New York City time) on such Purchase Date, then the Trustee shall immediately notify the Company and each Guarantor and demand payment (i) from the Company under the Agreement and the Note, and (ii) from each Guarantor under a Guaranty Agreement, of an amount, after taking into account any moneys then on deposit in the Company Fund, and in a manner so as to provide in the Company Fund immediately available funds sufficient to pay the purchase price of such Bonds to be purchased on such Purchase Date.”

(b)Section 5.06(c) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “If any Credit Facility permits any drawings to be made later than is provided herein, the Trustee shall make any drawing required under this Section 5.06 in accordance with the terms of the Credit Facility for drawing thereunder in a manner so as to be reasonably assured that immediately available funds will be available to the Tender Agent by 2:30 p.m. (New

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EXHIBIT 10.1

York City time) on a Purchase Date to pay the purchase price and the Tender Agent shall deposit those moneys directly into the Credit Facility Proceeds Account.”

Section 1.08Delivery of Proceeds of Sale. The first sentence of Section 5.07 of the Original Indenture is hereby amended and restated in its entirety to read as follows: “The proceeds of the remarketing of any Bonds by the Remarketing Agent shall be delivered by the Remarketing Agent directly to the Tender Agent no later than 11:30 a.m. (New York City time) on the Purchase Date except that such proceeds shall, if the Interest Rate Mode for such Bonds is, or is being converted to, the Commercial Paper Rate, be delivered to the Tender Agent no later than 1:00 p.m. (New York City time) on the Purchase Date, and, except as described in the next sentence, all such remarketing proceeds shall be deposited directly into the Remarketing Proceeds Account.”

Section 1.09Bond Fund. Section 6.02(d) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “(d)    Except with respect to payments of principal or redemption price of and interest on Bonds held pursuant to Section 5.05 or any other Bonds registered in the name of the Company, the Trustee shall, at or before 12:00 noon (New York City time) on the date on which such principal, redemption price or interest is due, draw upon or demand payment under the Credit Facility, if any, then held by the Trustee in accordance with its terms in an amount, after taking into account any moneys then on deposit in the Credit Facility Account, and in a manner so as to provide immediately available funds for principal or redemption price and interest by 2:30 p.m. (New York City time) on such due date. If the Credit Facility has been repudiated or if such funds for whatever reason are not provided under the Credit Facility by 2:30 p.m. (New York City time) on such date, then the Trustee shall immediately notify the Company and each Guarantor and demand payment (i) from the Company under the Agreement and the Note, and (ii) from each Guarantor under a Guaranty Agreement, of an amount, after taking into account any moneys then on deposit in the Company Account, and in a manner so as to provide in the Company Account immediately available funds sufficient to pay the principal or redemption price and interest on such due date.”

Section 1.10Alternate Credit Facilities. Section 7.03 of the Original Indenture is hereby amended and restated in its entirety to read as follows:

“Alternate Credit Facilities. Subject to the conditions of this Section 7.03, the Company may, at its option, provide for the delivery to the Trustee of an Alternate Credit Facility having administrative terms acceptable to the Trustee. The terms of the Alternate Credit Facility shall in all respects material to the Bondholders be the same (except for the term, maximum interest rate, number of days interest coverage and any redemption premium coverage, all as set forth in such Alternate Credit Facility) as any Credit Facility then in effect. Such Alternate Credit Facility shall have a term of not less than the greater of (a) 364 days, or (b) if the Interest Rate Mode for any Bonds then in effect is the Long-Term Rate, the then remaining portion of the then current Long-Term Rate Period, provided that such term shall end no earlier than a June 1 or a December 1 as the case may be. At least twenty five (25) days (forty (40) days if the Interest Rate Mode is the Long-Term Rate) prior to the proposed effective date of the proposed Alternate Credit Facility, the Company shall give notice, which notice, if the Interest Rate Mode is the Commercial Paper Rate, shall

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EXHIBIT 10.1

also contain a certification with respect to the length of each Commercial Paper Rate Period permitted hereunder after delivery of such Alternate Credit Facility, of such replacement to the Trustee, the Remarketing Agent, the Paying Agent, the Tender Agent and the then current Credit Facility Issuer, which notice shall confirm that (i) Bond Counsel expects to be able to deliver, on the date of delivery of the Alternate Credit Facility, an opinion of Bond Counsel stating that the delivery of such Alternate Credit Facility to the Trustee (x) is authorized under this Indenture and complies with the terms hereof and (y) will not adversely affect the exclusion from gross income of the interest on the Bonds for federal income tax purposes, and (ii) counsel to the Credit Facility Issuer of such Alternate Credit Facility expects to be able to deliver, on the date of delivery of such Alternate Credit Facility, an opinion stating that such Alternate Credit Facility is a legal, valid, binding and enforceable obligation of such Credit Facility Issuer in accordance with its terms. If (x) all of the Bonds are then subject to optional redemption pursuant to Section 9.01(a) and (y) if the purchase price of any Bonds to be purchased pursuant to Section 5.01(b)(ii) in connection with cancellation, termination or substitution of the existing Credit Facility, determined under such Section 5.01(b)(ii), includes any premium and the Trustee has received written confirmation from the Credit Facility Issuer that the Trustee can draw under the Credit Facility (other than the Alternate Credit Facility being delivered in connection with such cancellation) on the Purchase Date related to such purchase of Bonds in an aggregate amount sufficient to pay the premium due upon such purchase of Bonds on such Purchase Date, then the Trustee shall (i) accept such Alternate Credit Facility and surrender the previously held Credit Facility, if any, to the previous Credit Facility Issuer for cancellation promptly on the day the Alternate Credit Facility becomes effective and (ii) give the notice provided for in Section 7.05; provided, further, however, that such Credit Facility shall not be surrendered for cancellation until payment by the issuer of the Credit Facility to be surrendered shall have been made for any and all drawings by the Trustee effected on or before the date of such surrender for cancellation (including any drawings for payment of the purchase price of Bonds to be purchased pursuant to Section 5.01(b)(ii) in connection with such cancellation, termination or substitution). If the Interest Rate Mode for Bonds is the Commercial Paper Rate, and if the preceding sentence is applicable, the notices required under this Section 7.03 shall be delivered in sufficient time to permit the Remarketing Agent to establish a Commercial Paper Rate Period for each such Bond in accordance with Section 2.02(c)(i)(C)(1).

If a Credit Facility is in effect, the Company may at its option cause an Additional Credit Facility to be delivered to the Trustee to provide for any portion of the principal or redemption or purchase price of (including premium, if any), or interest on, the Bonds; provided that no Additional Credit Facility shall be delivered, shall become effective or shall be drawn upon for any payments hereunder unless the Trustee shall have also received (i) the opinion of Bond Counsel referred to in the preceding paragraph, (ii) an opinion of counsel to the Credit Facility Issuer of such Additional Credit Facility stating that such Additional Credit Facility is a legal, valid, binding and enforceable obligation of such issuer or obligor in accordance with its terms, (iii) the further opinion of Bond Counsel if required by the last paragraph of this Section 7.03 upon delivery of an Alternate Credit Facility, (iv) if such Bonds are then rated, notice from the Rating Agency to the effect that such Rating Agency

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has reviewed the proposed Additional Credit Facility and the provision of such Additional Credit Facility will not, by itself, result in (A) a permanent withdrawal of the rating on the Bonds or (B) a reduction in the then current rating on the Bonds, and (v) if such Additional Credit Facility is issued by an issuer other than the Credit Facility Issuer of the Credit Facility then in effect, then the written consent of such Credit Facility Issuer to the delivery of the Additional Credit Facility. The Company shall promptly give written notice to the Trustee and, if the Interest Rate Mode for Bonds is the Commercial Paper Rate, the Remarketing Agent of its intention to cause delivery of any Additional Credit Facility. If the Interest Rate Mode for Bonds is the Commercial Paper Rate, such notice from the Company shall contain a certification with respect to the maximum length of each Commercial Paper Rate Period permitted hereunder upon delivery of such Additional Credit Facility. Upon receipt of such notice, if the Additional Credit Facility is issued by an issuer other than the Credit Facility Issuer with respect to the other Credit Facility then in effect, the Trustee will promptly mail a notice of the delivery of the Additional Credit Facility by first class mail to the Issuer, the Remarketing Agent, the Tender Agent, the Paying Agent and each Bondholder at its registered address.

Any Alternate Credit Facility or Additional Credit Facility delivered to the Trustee must be accompanied by the opinions of Bond Counsel and counsel to the Credit Facility Issuer of such Alternate Credit Facility or Additional Credit Facility referred to above. In addition, if the Company grants a security interest in any cash, securities or investment property to the issuer or provider of such Alternate Credit Facility or Additional Credit Facility, the Company must furnish the Trustee with an opinion of Bond Counsel stating that such grant will not adversely affect the exclusion from gross income of interest on the Bonds for purposes of federal income taxation nor adversely affect any security interest created under this Indenture in favor of the holders of the Bonds.”

Section 1.11Amendment to Section 12.13. Section 12.13 of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Qualification of Successor. A successor trustee shall be a national banking association with trust powers or a state banking corporation with trust powers or a bank and trust company or a trust company, in each case having capital and surplus of at least $75,000,000 and a S&P short-term debt rating of at least “A-2” (or, if no short-term debt rating, a long-term debt rating of at least “BBB+”), if there be one able and willing to accept the trust on acceptable and customary terms. If any successor trustee, Paying Agent or Tender Agent on any date no longer meets the aforesaid criteria, such entity shall be deemed to have resigned from such position no later than the 30^th day following the aforesaid date (subject, however, to the appointment of a successor thereto pursuant to the provisions of this Indenture) and such entity shall promptly provide written notice thereof to the entities who are to receive such notice of resignation pursuant to the provisions of this Indenture.”

Section 1.12The Remarketing Agent. Section 13.01(c) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “At any time a Remarketing Agent may resign in accordance with the Remarketing Agreement. Any Remarketing Agent may be removed at any time in accordance with the Remarketing Agreement. Upon resignation or removal of a Remarketing Agent, the Company, with the consent of the Credit Facility Issuer if the Remarketing

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EXHIBIT 10.1

Agent was not the same as the Credit Facility Issuer or under common control with the Credit Facility Issuer, such consent not to be unreasonably withheld, shall either appoint a successor Remarketing Agent or authorize the remaining Remarketing Agent or Agents to act alone in such capacity, in which case all references in this Indenture to the Remarketing Agent shall mean the remaining Remarketing Agent or Agents. If the last remaining Remarketing Agent resigns or is removed, the Company shall appoint a successor Remarketing Agent. Any successor Remarketing Agent shall have combined capital stock, surplus and undivided profits of at least $50,000,000 and shall be acceptable to the Rating Agency as long as the Bonds continue to be rated; provided that the foregoing requirements shall not apply to any additional Remarketing Agents if, at the time such additional Remarketing Agents are appointed, there is currently a Remarketing Agent meeting such requirements.”

Section 1.13Acts of Bondholders. Section 14.01 of the Original Indenture is hereby amended to add an additional sentence at the end of the paragraph as follows: “Notwithstanding anything in this Indenture to the contrary, for so long as the Company holds all of the Outstanding Bonds, any action that may be taken by the registered holders of the Bonds may be taken by the Company as beneficial owner of the Bonds.”

Section 1.14Bond Form. The form of Bond set forth in the Original Indenture is hereby replaced with the form of Bond attached hereto as Exhibit A.

ARTICLE II
MISCELLANEOUS

Section 2.01    Effectiveness. This First Supplemental Indenture shall be effective upon mandatory purchase of the Bonds, and payment of the purchase price in connection therewith, on April 2, 2012.

Section 2.02    Original Indenture Confirmed. Except as amended by this First Supplemental Indenture, all of the provisions of the Original Indenture shall remain in full force and effect, and from and after the effective date of this First Supplemental Indenture shall be deemed to have been amended as herein set forth.

Section 2.03    Severability. If any provision of this First Supplemental Indenture shall be held or deemed to be or shall, in fact, be inoperative or unenforceable as applied in any particular case in any jurisdiction or jurisdictions or in all jurisdictions, or in all cases because it conflicts with any other provision or provisions hereof or any constitution or statute or rule of public policy, or for any other reason, such circumstances shall not have the effect of rendering the provision in question inoperative or unenforceable in any other case or circumstance, or of rendering any other provision or provisions herein contained invalid, inoperative, or unenforceable to any extent whatever.

Section 2.04    Counterparts. This First Supplemental Indenture may be simultaneously executed in several counterparts, each of which shall be an original and all of which shall constitute but one and the same instrument.

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EXHIBIT 10.1

Section 2.05    Applicable Provisions of Law. This First Supplemental Indenture shall be governed by and construed in accordance with the laws of the State of Ohio.

[remainder of page intentionally left blank]

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EXHIBIT 10.1

IN WITNESS WHEREOF, OHIO WATER DEVELOPMENT AUTHORITY has caused this First Supplemental Indenture to be executed by its Executive Director, and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. has caused this First Supplemental Indenture to be executed by one of its authorized officers, all as of the day and year first above written.

OHIO WATER DEVELOPMENT AUTHORITY

By: /s/ Steve Grossman    Executive Director

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

By: /s/ Biagio S. Impala    Authorized Signatory

CONSENT TO FIRST SUPPLEMENTAL TRUST INDENTURE

The undersigned, with respect to $90,140,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-A (FirstEnergy Generation Corp. Project) issued by the Ohio Water Development Authority (the “Issuer”), hereby consents to the execution and delivery of the First Supplemental Trust Indenture dated April 2, 2012 (the “First Supplemental Indenture”) amending and supplementing the Trust Indenture dated as of April 1, 2006 (the “Original Indenture”), between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee, in so far as the amendments made by the First Supplemental Indenture would affect or alter the duties or obligations of the Remarketing Agent. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to them in the Original Indenture, as amended and supplemented by the First Supplemental Indenture.

Dated:  April 2, 2012

MORGAN STANLEY & CO. LLC,
  as Remarketing Agent

By: /s/ F. J. Sweeney        

Name: F.J. Sweeney    

Title: Managing Director

Signature Page to First Supplemental Indenture

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EXHIBIT 10.1

CONSENT TO FIRST SUPPLEMENTAL TRUST INDENTURE

The undersigned, with respect to $90,140,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-A (FirstEnergy Generation Corp. Project) issued by the Ohio Water Development Authority (the “Issuer”), hereby consents to the execution and delivery of the First Supplemental Trust Indenture dated April 2, 2012 (the “First Supplemental Indenture”) amending and supplementing the Trust Indenture dated as of April 1, 2006 (the “Original Indenture”), between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to them in the Original Indenture, as amended and supplemented by the First Supplemental Indenture.

Dated:  April 2, 2012

FIRSTENERGY GENERATION CORP.,  as the “Company”

By: /s/ Steven R. Staub         Name: Steven R. Staub
Title: Assistant Treasurer

CONSENT TO FIRST SUPPLEMENTAL TRUST INDENTURE

The undersigned, with respect to $90,140,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-A (FirstEnergy Generation Corp. Project) issued by the Ohio Water Development Authority (the “Issuer”), hereby consents to the execution and delivery of the First Supplemental Trust Indenture dated April 2, 2012 (the “First Supplemental Indenture”) amending and supplementing the Trust Indenture dated as of April 1, 2006 (the “Original Indenture”), between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee, in so far as the amendments made by the First Supplemental Indenture would affect or alter the duties or obligations of the Tender Agent. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to them in the Original Indenture, as amended and supplemented by the First Supplemental Indenture.

Dated:  April 2, 2012

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

By: /s/ Biagio S. Impala        

Authorized Signatory

Signature Page to First Supplemental Indenture

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EXHIBIT 10.1

EXHIBIT A

[FORM OF BOND]

No. ____________    $

UNITED STATES OF AMERICA

STATE OF OHIO

POLLUTION CONTROL REVENUE REFUNDING BOND

SERIES 2006-A

(FIRSTENERGY GENERATION PROJECT)

MATURITY DATEINTEREST RATE MODEDATE OF THE BONDSCUSIP

[If Long-Term Rate also        Date of Original Issuance        ___

identify length of Long-

Term Rate Period]

[[TO BE FILLED IN ONLY IF INTEREST RATE MODE IDENTIFIED

ABOVE IS THE COMMERCIAL PAPER RATE AND CEDE & CO. IS

NOT THE REGISTERED OWNER:

Commercial        Commercial

Purchase        Paper Rate            Paper             Interest

Date         Period        Rate         Payable]]

Registered Owner:

Principal Sum:

THE STATE OF OHIO (the “State”), a state of the United States of America, by the Ohio Water Development Authority (the “Issuer”), a body corporate and politic organized and existing under the Constitution and laws of the State, for value received, hereby promises to pay (but only out of the sources hereinafter mentioned) to the Registered Owner named above, or registered assigns, the Principal Sum stated above on the Maturity Date stated above, unless this Bond shall have been called for redemption in whole or in part and payment of the redemption price shall have been duly made or provided for, upon surrender hereof, and to pay (but only out of the sources hereinafter mentioned) to such Registered Owner, interest thereon from the last date to which interest has accrued and been paid or duly provided for, or, if no interest has been paid or duly provided for, from the Date of the Bonds set forth above, until payment of said principal sum has been made or provided for, at the interest rate determined from time to time for the permitted Interest Rate Modes in the manner described herein and in the Indenture referred to below and

payable on the dates set forth herein and in the Indenture, commencing on the first such Interest Payment Date thereafter, and interest on overdue principal, and to the extent permitted by law, on overdue interest, as provided in the Indenture. Principal and interest shall be paid in any coin or currency of the United States of America which, at the time of payment, is legal tender for the payment of public and private debts. Interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will be paid to the Person in whose name this Bond is registered at the close of business on the Regular Record Date for such interest or, in the case of an Interest Payment Date for a Commercial Paper Rate Period, on such Interest Payment Date. Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the registered owner at the close of business on such Regular Record Date and may be paid to the Person in whose name this Bond is registered at the close of business on the Special Record Date for the payment of such defaulted interest to be fixed by the Trustee, or may be paid, at any time in any other lawful manner, all as more fully provided in the Indenture. The principal or redemption price of this Bond shall be paid upon presentation and surrender at the Designated Office of The Bank of New York Mellon Trust Company, N.A., or at the duly designated office of any duly appointed alternative or successor paying agent (the “Paying Agent”). Except when this Bond is registered in the name of a Depository, interest on this Bond shall be payable by check mailed on the applicable Interest Payment Date by first class mail, postage prepaid to the registered owner of this Bond at such owner's address as it appears on the Bond Register of the Issuer maintained by the Trustee; provided that if this Bond is registered in the name of other than a Depository and the Interest Rate Mode for this Bond is the Commercial Paper Rate, the Dutch Auction Rate, the Daily Rate or the Weekly Rate, interest payable on this Bond shall, at the written request of the registered owner received by the Bond Registrar at least one Business Day prior to the applicable Record Date (or on or prior to an Interest Payment Date if the Interest Rate Mode is the Commercial Paper Rate), be payable to the registered owner in immediately available funds by wire transfer to a bank account of such registered owner within the United States or by deposit into a bank account maintained by the Paying Agent; provided further however that, if the Interest Rate Mode is the Commercial Paper Rate and this Bond is registered in the name of other than a Depository, interest on this Bond payable on the Interest Payment Date following the end of the Commercial Paper Rate Period shall be paid only upon presentation and surrender of this Bond at the Designated Office of the Paying Agent. When this Bond is registered in the name of a Depository or its nominee, interest is payable in same day funds delivered or transmitted to the Depository.

This Bond is one of a duly authorized series (the “Bonds”) limited in aggregate principal amount to $90,140,000 issued under a Trust Indenture, dated as of April 1, 2006, between the Issuer and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”), a national banking association duly organized and validly existing under the laws of the United States of America, as amended by the First Supplemental Trust Indenture dated April 2, 2012 between the Issuer and the Trustee (as so amended, the “Indenture). The Bonds are issued by the Issuer pursuant to and in full compliance with the Constitution and laws of the State of Ohio, particularly Chapter 6121 of the Ohio Revised Code, as amended (the “Act”), in order to assist FirstEnergy Generation Corp. (the “Company”) in the refunding of the Refunded Bonds (as defined in the Agreement identified below), the proceeds of which were loaned by the Issuer to an Affiliate of the Company to assist that Affiliates in the refinancing of a portion of the cost of acquiring, constructing and installing certain facilities comprising “waste water facilities” as defined in Section 6121.01 of the

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EXHIBIT 10.1

Ohio Revised Code (the “Project”), all as set forth in the Agreement.

THE PRINCIPAL OR REDEMPTION PRICE OF AND INTEREST ON THE BONDS ARE PAYABLE SOLELY AND EXCLUSIVELY FROM THE REVENUES AND FUNDS PLEDGED FOR THEIR PAYMENT PURSUANT TO THE INDENTURE. THE BONDS ARE SPECIAL OBLIGATIONS OF THE STATE, ISSUED BY THE ISSUER AND ARE PAYABLE SOLELY FROM THE SOURCES REFERRED TO HEREIN. THE BONDS DO NOT CONSTITUTE A DEBT OR A PLEDGE OF THE FAITH AND CREDIT OF THE STATE OR ANY POLITICAL SUBDIVISION THEREOF AND THE HOLDERS OR OWNERS OF THE BONDS HAVE NO RIGHT TO HAVE TAXES LEVIED BY THE GENERAL ASSEMBLY OF THE STATE OR TAXING AUTHORITY OF ANY POLITICAL SUBDIVISION OF THE STATE FOR THE PAYMENT OF THE PRINCIPAL OR REDEMPTION PRICE OF AND INTEREST ON THE BONDS. THE ISSUER HAS NO TAXING POWER.

If an Event of Default as defined in the Indenture) occurs, the principal of and all unpaid and accrued interest on all Bonds issued under the Indenture may become due and payable upon the conditions and in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal or redemption price of, or interest on, this Bond, or for any claim based hereon or on the Indenture, against any member, officer or employee, past, present or future, of the Issuer or of any successor body, as such, either directly or through the Issuer or any such successor body, under any constitutional provision, statute or rule of law, or by the enforcement of any assessment or by any legal or equitable proceeding or otherwise.

The Bonds are payable solely from payments on the Company's Waste Water Facilities Note, Series 2006-A (the “Note”) dated the Date of the Bonds and delivered by the Company to the Trustee pursuant to a Waste Water Facilities Loan Agreement dated as of April 1, 2006, as amended by the First Amendment to Loan Agreement dated April 2, 2012, between the Issuer and the Company (as so amended, the “Agreement”) and from any other moneys held by the Trustee under the Indenture for such purpose, including moneys drawn by the Trustee under the Letter of Credit referred to herein or such other Credit Facility, if any, as may then be held by the Trustee under the Indenture for the benefit of the registered owners of the Bonds. The Company has caused to be delivered to the Trustee an irrevocable, direct pay, letter of credit (the “Letter of Credit”) issued by UBS AG, Stamford Branch (the “Bank”). Pursuant to the Indenture, the Letter of Credit may be replaced by an Alternate Credit Facility or an Additional Credit Facility may be provided. The term “Credit Facility” includes both the Letter of Credit and any such Additional or Alternate Credit Facility and the term “Credit Facility Issuer” includes any issuer of any Credit Facility in effect at the relevant time. There shall be no other recourse against the State or the Issuer or any other property now or hereafter owned by either the State or the Issuer.

The Bonds are issuable only as fully registered bonds in authorized denominations and, except as hereinafter provided, registered in the name of The Depository Trust Company, New York, New York (“DTC”) or its nominee, which shall be considered to be the Bondholder for all purposes of the Indenture, including, without limitation, payment by the Issuer of principal or

redemption price of and interest on the Bonds and receipt of notices and exercise of rights of Bondholders. There shall be a single Bond which shall be immobilized in the custody of DTC with the owners of book-entry interests in the Bonds (“book-entry interests”) having no right to receive Bonds in the form of physical securities or certificates. Ownership of book-entry interests shall be shown by book-entry on the system maintained and operated by DTC, its participants (the “Participants”) and certain Persons acting through the Participants. Transfers of ownership of book-entry interests are to be made only by DTC and the Participants by that book-entry system, the Issuer and the Trustee having no responsibility therefor. DTC is to maintain records of the positions of Participants in the Bonds, and the Participants and Persons acting through Participants are to maintain records of the purchasers and owners of book-entry interests. The Bonds as such shall not be transferable or exchangeable, except for transfer to another Depository or to another nominee of a Depository, without further action by the Issuer.

If any Depository determines not to continue to act as a Depository for the Bonds for use in a book-entry system, the Issuer may attempt to have established a securities depository/book-entry system relationship with another qualified Depository under the Indenture. If the Issuer does not or is unable to do so, the Issuer and the Trustee, after the Trustee has made provision for notification of the owners of the book-entry interests by the then Depository, shall permit withdrawal of the Bonds from the Depository, and authenticate and deliver Bond certificates in fully registered form in authorized denominations to the assignees of the Depository or its nominee, at the cost and expense (including costs of printing or otherwise preparing and delivering replacement Bonds), of the Company.

Except as otherwise specified in the Indenture, this Bond is entitled to the benefits of the Indenture equally and ratably both as to principal (and redemption price) and interest with all other Bonds issued and Outstanding under the Indenture. Reference is made to the Indenture for a description of the rights of the registered owners of the Bonds; the rights and obligations of the Issuer; the rights, duties and obligations of the Trustee; the provisions relating to amendments to and modifications of the Indenture; and for the meaning of capitalized terms not otherwise defined herein. The registered owner of this Bond shall have no right to enforce the provisions of the Indenture, the Agreement or the Note, or to institute action to enforce the covenants thereof or rights or remedies thereunder except as provided in the Indenture.

This Bond shall bear interest at the interest rate or rates determined for the “Interest Rate Mode” (as described more fully in Section 2.02 of the Indenture) selected from time to time by the Company. Until a Conversion to a different Interest Rate Mode is specified by the Company or until the Maturity Date stated above, the Interest Rate Mode for this Bond is as specified above. The Company may from time to time change the Interest Rate Mode for the Bonds, in whole or in part, to any other permitted Interest Rate Mode in accordance with the terms of the Indenture. The “Interest Rate Modes” which may be selected are as follows: (i) a Daily Rate in which the interest rate is determined each Business Day; (ii) a Weekly Rate in which the interest rate is determined on the day preceding each Weekly Rate Period or, if such day is not a Business Day, on the next succeeding Business Day; (iii) a Semi-Annual Rate in which the interest rate is determined not later than the Business Day preceding each Semi-Annual Rate Period; (iv) an Annual Rate in which the interest rate is determined not later than the Business Day preceding each Annual Rate Period; (v)

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EXHIBIT 10.1

a Two-Year Rate in which the interest rate is determined not later than the Business Day preceding each Two-Year Rate Period; (vi) a Three-Year Rate in which the interest rate is determined not later than the Business Day preceding each Three-Year Rate Period; (vii) a Five-Year Rate in which the interest rate is determined not later than the Business Day preceding each Five-Year Rate Period; (viii) a Long-Term Rate for a period selected by the Company of more than one year ending on the day preceding an Interest Payment Date, in which the interest rate is determined not later than the Business Day preceding such Long-Term Rate Period; (ix) a Commercial Paper Rate for Commercial Paper Rate Periods of one (1) day to not more than two hundred seventy (270) days (or such lower maximum number as is then permitted under the Indenture) ending on a day preceding a Business Day selected by the Remarketing Agent in which the interest rate is determined on the first day of such Commercial Paper Rate Period; and (x) a Dutch Auction Rate Period in which the interest rate for a Dutch Auction Rate Period is determined pursuant to the Dutch Auction Procedures set forth in the Indenture.

Interest on this Bond at the interest rate or rates for the Daily Rate and the Weekly Rate is payable on the first Business Day of each month; for the Semi-Annual Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate and the Long-Term Rate on May 15 and November 15, provided, however, if any May 15 or November 15 which is a Conversion Date for conversion to the Daily Rate, the Weekly Rate or the Commercial Paper Rate, is not a Business Day, then the first Business Day immediately succeeding such May 15 or November 15, as applicable; for the Commercial Paper Rate on the first Business Day following the last day of each Commercial Paper Rate Period for such Bond; for the Dutch Auction Rate, (i) for an Auction Period of 91 days or less, the Business Day immediately succeeding the last day of such Auction Period and (ii) for an Auction Period of more than 91 days, each 13^th weekly anniversary of the day immediately following the first day of such Auction Period and the Business Day immediately succeeding the last day of such Auction Period (in each case it being understood that in those instances where the immediately preceding Auction Date falls on a day that is not a Business Day, the Interest Payment Date with respect to the succeeding Auction Period shall be one Business Day immediately succeeding the next Auction Date); and for each Interest Rate Mode, on the Conversion Date to another Interest Rate Mode or on the effective date of a change in the Long-Term Rate Period. In any case, the final Interest Payment Date shall be the Maturity Date. Interest on this Bond shall be computed on the basis of a year of 365 or 366 days, as appropriate for the actual number of days elapsed, unless the Interest Rate Mode is the Semi-Annual Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate, in which case interest shall be computed on the basis of a 360-day year consisting of twelve 30-day months, or unless the Interest Rate Mode is the Dutch Auction Rate, in which case interest shall be computed on the basis of a 360‑day year for the actual number of days elapsed. The interest rate or rates for each Interest Rate Mode (and, if the Interest Rate Mode is the Commercial Paper Rate, the Commercial Paper Rate Periods) for this Bond shall be determined by the Remarketing Agent on the dates and at such times as specified in Section 2.02 of the Indenture. Except for the Auction Rate, each interest rate determined by the Remarketing Agent shall be the minimum rate of interest necessary, in the judgment of the Remarketing Agent taking into account Prevailing Market Conditions, to enable the Remarketing Agent to sell this Bond at a price equal to the principal amount hereof, plus accrued interest, if any. Notwithstanding the foregoing, the interest rate borne by this Bond shall not exceed the lesser of (i) twelve percent (12%) per annum and (ii) so long as

the Bonds are entitled to the benefit of a Credit Facility, the maximum interest rate specified in the Credit Facility.

In the event that the interest rate or rates for an Interest Rate Mode (other than the Commercial Paper Rate and the Dutch Auction Rate) are not or cannot be determined for whatever reason, the Interest Rate Mode on the Bonds shall be converted automatically to the Weekly Rate (without the necessity of complying with the requirements in the Indenture relating to conversions, including, but not limited to, the requirement of mandatory purchase) and the interest rate shall be equal to the Municipal Index. Any mandatory purchase of such Bonds will remain effective.

Subject to the provisions of the Indenture, the Company may, but is not required to, provide another Credit Facility upon cancellation, termination or expiration of the Letter of Credit or the then current Credit Facility. As described below, this Bond will become subject to mandatory purchase upon the cancellation, termination or expiration of that Credit Facility.

Redemption of Bonds

Whenever the Interest Rate Mode for this Bond is the Dutch Auction Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount thereof plus accrued interest, if any, on the Business Day immediately succeeding any Auction Date. Whenever the Interest Rate Mode for this Bond is the Daily Rate, the Weekly Rate or the Semi-Annual Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on any Interest Payment Date for this Bond. Whenever the Interest Rate Mode for this Bond is the Commercial Paper Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the Interest Payment Date for such Commercial Paper Rate Period. Whenever the Interest Rate Mode is the Annual Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Annual Rate Period. Whenever the Interest Rate Mode is the Two-Year Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Two-Year Rate Period. Whenever the Interest Rate Mode is the Three-Year Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Three-Year Rate Period. Whenever the Interest Rate Mode is the Five-Year Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Five-Year Rate Period. Whenever the Interest Rate Mode for this Bond is the Long-Term Rate, this Bond shall be subject to optional redemption, in whole or in part (i) on the final Interest Payment Date for such Long-Term Rate Period, at a redemption price equal to the principal amount hereof plus accrued interest, if any, to the date of redemption and (ii) during the then current Long-Term Rate Period at any time with accrued interest during the redemption periods and at the redemption prices set forth below.

Original Length of                Redemption Price    

Current Long-Term            Commencement of            as Percentage

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EXHIBIT 10.1

Rate Period (Years)Redemption Periodof Principal

More than 15 years    Tenth anniversary of            

commencement of Long-                

Term Rate Period                    100%

Greater than 10 years    Fifth anniversary of                

but equal to or less    commencement of Long-                

than 15 years        Term Rate Period                    100%

Equal to or less than 10 years    Non-callable                    Non-callable

If the Company has given notice of a change in the Long-Term Rate Period or notice of Conversion of the Interest Rate Mode for the Bonds to the Long-Term Rate and, at least forty (40) days prior to such change in the Long-Term Rate Period or such Conversion of an Interest Rate Mode for the Bonds to the Long-Term Rate, the Company has provided (i) a certification of the Remarketing Agent to the Trustee and the Issuer that the foregoing schedule is not consistent with Prevailing Market Conditions and (ii) an opinion of Bond Counsel that a change in the redemption provisions will not adversely affect the exclusion from gross income of interest on the Bonds for federal income tax purposes, the foregoing redemption periods and redemption prices may be revised, effective as of the date of such change in the Long-Term Rate Period or the Conversion Date, as determined by the Remarketing Agent in its judgment, taking into account the then Prevailing Market Conditions, as set forth in such certification.

Whenever the Interest Rate Mode for this Bond is the Long-Term Rate, this Bond shall also be subject to extraordinary optional redemption at any time, in whole, at a redemption price of 100% of the principal amount hereof, plus accrued interest to the date fixed for redemption, if any, if the Company has determined that:

(A)    any federal, state or local body exercising governmental or judicial authority has taken any action which results in the imposition of burdens or liabilities with respect to the Project, or any facilities serviced thereby, rendering impracticable or uneconomical the operation of all or a substantial portion of the Project (or the facilities serviced thereby) by the Company including, without limitation, the condemnation or taking by eminent domain of all or a substantial portion of the Project or any facilities serviced thereby; or

(B)    changes in the economic availability of raw materials, operating supplies, or facilities or technological or other changes have made the continued operation of all or a substantial portion of the Project, or the operation of the facilities serviced thereby, uneconomical; or

(C)    all or a substantial portion of the Project has been damaged or destroyed to such an extent that it is not practicable or desirable to rebuild, repair or restore such Project; or

(D)    as a result of any changes in the Constitution of the State of Ohio or the Constitution of the United States of America or by legislative or administrative action (whether state or federal) or by final decree, judgment or order of any court or administrative body (whether

state or federal) after any contest thereof by the Company in good faith, the Indenture, the Agreement, the Note or the Bonds shall become void or unenforceable or impossible of performance in accordance with the intent and purposes of the parties as expressed in the Indenture or the Agreement; or

(E)    any court or administrative body shall enter a judgment, order or decree, or shall take administrative action, requiring the Company to cease all or any substantial part of its operations served by the Project to such extent that the Company is or will be prevented from carrying on its normal operations at the facilities being served by such Project for a period of at least six (6) consecutive months; or

(F)    the Company has terminated operations at the facilities being served by the Project;

provided that any such redemption shall be made not more than one (1) year from the date of such determination by the Company.

Bonds subject to optional redemption as provided above may be purchased in lieu of redemption on the applicable redemption date at a purchase price equal to 100% of the principal amount thereof, plus accrued interest thereon to, but not including, the date of such purchase, if the Trustee has received a written request from the Company on or before the Business Day prior to the date the Bonds would otherwise be subject to redemption specifying that moneys provided or to be provided by the Company shall be used to purchase such Bonds in lieu of redemption. While a Credit Facility is in place, any such purchase will be made from moneys received from a drawing on such Credit Facility and applied as provided in the Indenture. In that instance, the date of such purchase shall be deemed to be a Purchase Date, and the Bonds so purchased shall be deemed to be Pledged Bonds and shall be held by the Tender Agent pursuant to the Indenture.

The Bonds shall be subject to special mandatory redemption in whole (or in part, if, in the opinion of Bond Counsel, such partial redemption will preserve the exclusion from gross income for federal income tax purposes of interest on the Bonds remaining Outstanding after such redemption) at any time at a redemption price equal to 100% of the principal amount thereof, plus interest accrued to the redemption date, if a “final determination” is made that the interest paid or payable on any Bond to other than a “substantial user” of the Project or a “related person” (within the meaning of to Section 147(a) of the Internal Revenue Code of 1986, as amended (the “Code”)) is or was includable in the gross income of the owner thereof for federal income tax purposes under the Code, as a result of the failure of the Company to observe or perform any covenant, condition or agreement on its part to be observed or performed under the Agreement or the inaccuracy of any representation or warranty of the Company under the Agreement. A “final determination” shall be deemed to have occurred upon the issuance of a published or private ruling, technical advice or determination by the Internal Revenue Service or a judicial decision in a proceeding by any court of competent jurisdiction in the United States (from which ruling, advice, determination or decision no further right of appeal exists), in all cases in which the Company, at its expense, has participated or been a party or has been given the opportunity to contest the same or to participate or be a party, or receipt by the Trustee of an opinion of Bond Counsel to such effect obtained by the Company

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EXHIBIT 10.1

and rendered at the request of the Company. Any special mandatory redemption shall be made as soon as practicable but in any event not more than one hundred eighty (180) days from the date of such “final determination”; provided that, not later than sixty (60) days after a “final determination” is so made, the Company may advise the Trustee of the date, which shall be not later than the 180th day from the date of such “final determination”, on which the Bonds are to be redeemed. If no date is so specified, the Trustee shall establish a redemption date which shall be the 120th day, or if such day is not a Business Day, the next succeeding Business Day, following the delivery of notice to the Trustee of the making of a “final determination”. Any special mandatory redemption of less than all of the Bonds shall be made in such manner as the Trustee, with the advice of Bond Counsel, shall deem proper. If the Indenture has been released prior to the occurrence of a “final determination”, the Bonds will not be redeemed as described in this paragraph.

Any notice of redemption, identifying the Bonds or portions thereof to be redeemed, shall be given by first class mail to the registered owner of each Bond to be redeemed in whole or in part at the address shown on the Bond Register of the Issuer maintained by the Bond Registrar not more than ninety (90) days and not fewer than thirty (30) days (fifteen (15) days when the Interest Rate Mode for the Bonds is the Dutch Auction Rate) prior to the redemption date. If, at the time of the mailing of a notice of any optional redemption, the Trustee shall not have received moneys sufficient to redeem all the Bonds called for redemption, such redemption may be conditioned on, and such notice may state that it is conditional in that it is subject to, the receipt of such moneys by the Trustee not later than the redemption date, and such notice shall be of no effect unless such moneys are so received. All Bonds so called for redemption will cease to bear interest on the specified redemption date, provided funds for their redemption and any accrued interest payable on the redemption date are on deposit with the Trustee or Paying Agent at that time.

Purchase of Bonds

This Bond shall be subject to mandatory purchase (i) on the effective date of (a) the Conversion of the Interest Rate Mode for this Bond or (b) a change by the Company of the length of the Long-Term Rate Period for this Bond, (ii) on the Business Day following the end of each Commercial Paper Rate Period, Annual Rate Period, Two-Year Rate Period, Three-Year Rate Period, Five-Year Rate Period and Long-Term Rate Period, (iii) on the second day (or if such day is not a Business Day, the preceding Business Day) preceding the date of the cancellation or termination by the Trustee at the request of the Company of the then current Credit Facility, if any, or the 15th day (or if such day is not a Business Day, the preceding Business Day) preceding the stated expiration of the then current Credit Facility, if any, (iv) at the direction of the Credit Facility Issuer on the third Business Day after notice from the Credit Facility Issuer to the Trustee stating that an event of default has occurred and is continuing under the Reimbursement Agreement (as defined in the Indenture), and (v) if the Interest Rate Mode for this Bond is the Dutch Auction Rate, upon an assignment by the Company under Section 5.12 of the Agreement, on the last Interest Payment Date for the current Dutch Auction Rate Period, in each case, at a purchase price equal to 100% of the principal amount hereof, plus, if the Interest Rate Mode for this Bond is the Long-Term Rate, the optional redemption premium, if any, which would be payable if the Bonds were redeemed on such date, plus accrued interest, if any, to the Purchase Date; provided that no premium shall be paid as

part of the purchase price upon a mandatory purchase described in either clause (iii) above resulting from the stated expiration of the term of the then current Credit Facility, if any, or clause (iv) above resulting from the direction of the Credit Facility Issuer of that then current Credit Facility, if any, that an event of default has occurred and is continuing under the Reimbursement Agreement for any such Credit Facility.

This Bond, or a portion hereof in an authorized denomination (provided that the portion of this Bond to be retained by the registered owner shall also be in an authorized denomination), shall be purchased on the demand of the registered owner hereof at the times and the prices set forth below for the applicable Interest Rate Mode; provided, that if the Interest Rate Mode for this Bond is the Dutch Auction Rate, Commercial Paper Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate, the registered owner shall have no right to demand purchase of this Bond. If the Interest Rate Mode for this Bond is the Daily Rate, this Bond shall be purchased on the demand of the registered owner hereof, on any Business Day at a purchase price equal to the principal amount hereof plus accrued interest, if any, to the Purchase Date upon written notice or electronic notice to the Tender Agent not later than 10:30 a.m. (New York City time) on such Business Day. If the Interest Rate Mode for this Bond is the Weekly Rate, this Bond shall be purchased on the demand of the registered owner hereof, on any Business Day at a purchase price equal to the principal amount hereof, plus accrued interest, if any, to the Purchase Date, upon written notice to the Tender Agent at or before 5:00 p.m. (New York City time) on a Business Day not later than the seventh day prior to the Purchase Date. If the Interest Rate Mode is the Semi-Annual Rate, this Bond shall be purchased on demand of the registered owner hereof, on any Interest Payment Date (or, if such Interest Payment Date is not a Business Day, on the next succeeding Business Day) at a purchase price equal to the principal amount hereof, plus accrued interest, if any, to the Purchase Date, upon written notice to the Tender Agent on a Business Day not later than 5:00 p.m. on the seventh day prior to the Purchase Date.

Any notice in connection with a demand for purchase of this Bond as set forth in the preceding paragraph hereof shall be given at the address of the Tender Agent designated to the Trustee and shall (A) state the number and principal amount (or portion hereof in an authorized denomination) of this Bond to be purchased; (B) state the Purchase Date on which this Bond shall be purchased and (C) irrevocably request such purchase and agree to deliver this Bond to the Tender Agent on the Purchase Date. ANY SUCH NOTICE SHALL BE IRREVOCABLE WITH RESPECT TO THE PURCHASE FOR WHICH SUCH DIRECTION WAS DELIVERED AND, UNTIL SURRENDERED TO THE TENDER AGENT, THIS BOND OR ANY PORTION HEREOF WITH RESPECT TO WHICH SUCH DIRECTION WAS DELIVERED SHALL NOT BE TRANSFERABLE. This Bond must be delivered (together with an appropriate instrument of transfer executed in blank with all signatures guaranteed and in form satisfactory to the Tender Agent) at the Designated Office of the Tender Agent at or prior to 12:00 noon New York City time on the date specified in the aforesaid notice in order for the owner hereof to receive payment of the purchase price due on such Purchase Date. NO REGISTERED OWNER SHALL BE ENTITLED TO PAYMENT OF THE PURCHASE PRICE DUE ON SUCH PURCHASE DATE EXCEPT UPON SURRENDER OF THIS BOND AS SET FORTH HEREIN. NOTWITHSTANDING THE FOREGOING, THIS BOND SHALL NOT BE PURCHASED IF THE BONDS HAVE BEEN DECLARED DUE AND PAYABLE PURSUANT TO THE INDENTURE. No purchase of Bonds

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EXHIBIT 10.1

pursuant to Section 5.01 of the Indenture shall be deemed to be a payment or redemption of such Bonds or any portion thereof within the meaning of the Indenture.

BY ACCEPTANCE OF THIS BOND, THE REGISTERED OWNER HEREOF AGREES THAT THIS BOND WILL BE PURCHASED, WHETHER OR NOT SURRENDERED, (A) ON THE APPLICABLE PURCHASE DATE IN CONNECTION WITH THE EXPIRATION OF EACH COMMERCIAL PAPER RATE PERIOD, ANNUAL RATE PERIOD, TWO-YEAR RATE PERIOD, THREE-YEAR RATE PERIOD, FIVE-YEAR RATE PERIOD OR LONG-TERM RATE PERIOD FOR THIS BOND OR ON A CHANGE OF THE LONG-TERM RATE PERIOD OR ON CONVERSION OF THE INTEREST RATE MODE OF THIS BOND OR ANY CANCELLATION, TERMINATION OR EXPIRATION OF ANY CREDIT FACILITY WHICH MAY THEN BE IN EFFECT OR AT THE DIRECTION OF ANY SUCH CREDIT FACILITY ISSUER AS DESCRIBED ABOVE, OR IF THE INTEREST RATE MODE FOR THIS BOND IS THE AUCTION RATE, UPON AN ASSIGNMENT BY THE COMPANY UNDER SECTION 5.12 OF THE AGREEMENT, OR (B) ON ANY PURCHASE DATE SPECIFIED BY THE REGISTERED OWNER HEREOF IN THE EXERCISE OF THE RIGHT TO DEMAND PURCHASE OF THIS BOND AS DESCRIBED ABOVE. IN SUCH EVENT, THE REGISTERED OWNER OF THIS BOND SHALL NOT BE ENTITLED TO RECEIVE ANY FURTHER INTEREST HEREON AND SHALL HAVE NO FURTHER RIGHTS UNDER THIS BOND OR THE INDENTURE EXCEPT TO PAYMENT OF THE PURCHASE PRICE HELD THEREFOR.

The current Remarketing Agent under the Indenture is Morgan Stanley & Co. LLC (formerly known as Morgan Stanley & Co. Incorporated). The current Tender Agent under the Indenture is The Bank of New York Mellon Trust Company, N.A. On or before the effective date of a Conversion to a Dutch Auction Rate, a Market Agent and an Auction Agent are to be appointed in accordance with the Indenture. The Remarketing Agent, the Market Agent, the Tender Agent and the Auction Agent may be changed at any time in accordance with the Indenture.

The Bonds are issuable only as fully registered Bonds in the denominations of $5,000 and any integral multiple thereof except that Bonds authenticated when the Interest Rate Mode is the Daily Rate, the Weekly Rate, the Commercial Paper Rate or the Semi-Annual Rate shall be in denominations of $100,000 and any larger denomination constituting an integral multiple of $5,000 and except that Bonds authenticated when the Interest Rate Mode is the Dutch Auction Rate shall be in denominations of $25,000 and any integral multiple thereof. Subject to the limitations provided in the Indenture and upon payment of any tax or government charge, if any, Bonds may be exchanged for a like aggregate principal amount of Bonds of other authorized denominations and in the same Interest Rate Mode.

This Bond is transferable by the registered owner hereof or his duly authorized attorney at the corporate trust office of the Bond Registrar, upon surrender of this Bond, accompanied by a duly executed instrument of transfer in form and with guaranty of signature satisfactory to the Bond Registrar, subject to such reasonable regulations as the Issuer, the Tender Agent, the Trustee or the Bond Registrar may prescribe, and upon payment of any tax or other governmental charge incident to such transfer, PROVIDED, THAT, IF MONEYS FOR THE PURCHASE OF THIS BOND HAVE BEEN DEPOSITED WITH THE TENDER AGENT UNDER THE INDENTURE,

THIS BOND SHALL NOT BE TRANSFERABLE TO ANYONE UNTIL DELIVERED TO THE TENDER AGENT AND PROVIDED FURTHER THAT NEITHER THE ISSUER NOR THE BOND REGISTRAR SHALL BE REQUIRED (i) TO REGISTER THE TRANSFER OF OR EXCHANGE ANY BOND DURING A PERIOD BEGINNING AT THE OPENING OF BUSINESS FIFTEEN (15) DAYS BEFORE THE DAY OF MAILING OF A NOTICE OF REDEMPTION OF BONDS SELECTED FOR REDEMPTION AND ENDING AT THE CLOSE OF BUSINESS ON THE DAY OF SUCH MAILING, (ii) TO REGISTER THE TRANSFER OF OR EXCHANGE ANY BOND SO SELECTED FOR REDEMPTION IN WHOLE OR IN PART, OR (iii) OTHER THAN PURSUANT TO ARTICLE V OF THE INDENTURE, TO REGISTER ANY TRANSFER OF OR EXCHANGE ANY BOND WITH RESPECT TO WHICH THE OWNER HAS SUBMITTED A DEMAND FOR PURCHASE IN ACCORDANCE WITH SECTION 5.01(a) OR WHICH HAS BEEN PURCHASED PURSUANT TO SECTION 5.01(b) OF THE INDENTURE. Upon any such transfer, a new Bond or Bonds in the same aggregate principal amount and in the same Interest Rate Mode will be issued to the transferee. Except as set forth in this Bond and as otherwise provided in the Indenture, the Person in whose name this Bond is registered shall be deemed the owner hereof for all purposes, and the Issuer, any Paying Agent, the Bond Registrar, the Tender Agent, the Remarketing Agent, the Market Agent, the Auction Agent and the Trustee shall not be affected by any notice to the contrary.

This Bond is not valid unless the Certificate of Authentication endorsed hereon has been executed by the manual signature of an authorized signatory of the Trustee.

IN WITNESS WHEREOF, the State of Ohio, by the Ohio Water Development Authority, has caused this Bond to be executed in its name by the facsimile signature of the Chairman and Vice-Chairman of the Issuer, and the facsimile of the corporate seal of the Issuer to be printed hereon and attested by the facsimile signature of the Secretary-Treasurer of the Issuer, all as of the Date of the Bonds shown above.

STATE OF OHIO, BY THE OHIO

WATER DEVELOPMENT AUTHORITY

By:

Chairman

By:

Vice-Chairman

ATTEST:

Secretary-Treasurer

[SEAL]

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EXHIBIT 10.1

[FORM OF CERTIFICATE OF AUTHENTICATION]

This Bond is one of the Bonds described in the within mentioned Indenture.

Date of Authentication:

THE BANK OF NEW YORK MELLON TRUST

COMPANY, N.A.

as Trustee

By:

Authorized Signatory

[FORM OF LEGAL OPINION]

The following is a true copy of the text of the opinion rendered to the original purchasers of the Bonds by Squire, Sanders & Dempsey L.L.P. in connection with the original issuance of the Bonds. That opinion is dated as of and premised on the transcript of proceedings examined and the law in effect on the date of original delivery of the Bonds. A signed copy of the opinion is on file in this office.

OHIO WATER DEVELOPMENT

AUTHORITY

By (facsimile)    

Secretary-Treasurer

[TEXT OF LEGAL OPINION]

Respectfully submitted,

SQUIRE, SANDERS & DEMPSEY L.L.P.

[FORM OF ASSIGNMENT]

For value received, the undersigned hereby sells, assigns and transfers unto ______________________________ the within bond and all rights thereunder, and hereby irrevocably constitutes and appoints _______________________________, attorney to transfer the said bond on the Bond Register, with full power of substitution in the premises.

Dated:

Social Security Number or

Employer Identification

Number of Transferee:

Signature guaranteed:                                         

Signature must be guaranteed by a

member of an approved Signature

Guarantee Medallion Program.

NOTICE: The assignor's signature to this Assignment must correspond with the name as it appears on the face of the within bond in every particular without alteration, enlargement or any change whatever.

[FORM OF ABBREVIATIONS]

The following abbreviations, when used in the inscription on the face of the within bond, shall be construed as though they were written out in full according to applicable laws or regulations.

TEN COM - as tenants in common

TEN ENT - as tenants by the entireties

JT TEN - as joint tenants with right of survivorship and not as tenants in common

UNIFORM TRANSFERS TO MIN ACT - ___________________ Custodian ________________

(Cust)    (Minor)

under Uniform Transfers to Minors Act _______________________

(State)

Additional abbreviations may also be used though not in the above list.

Unless this certificate is presented by an authorized representative of The Depository Trust Company, a New York corporation (“DTC”), to the Issuer or its agent for registration of transfer, exchange, or payment, and any certificate issued is registered in the name of Cede & Co. or in such other name as is requested by an authorized representative of DTC (and any payment is made to Cede & Co. or to such other entity as is requested by an authorized representative of DTC), ANY TRANSFER, PLEDGE, OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL inasmuch as the registered owner hereof, Cede & Co., has an interest herein.

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EX-10.2

EXHIBIT 10.2

FIRST AMENDMENT TO LOAN AGREEMENT

THIS FIRST AMENDMENT TO LOAN AGREEMENT (the “First Amendment”), dated April 2, 2012 by and between the OHIO WATER DEVELOPMENT AUTHORITY (the “Issuer”) and FIRSTENERGY GENERATION CORP. (the “Company”), to the Waste Water Facilities Loan Agreement, dated as of April 1, 2006, entered into by the Issuer and the Company in connection with the issuance by the Issuer of $90,140,000 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 $90,140,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-A (FirstEnergy Generation Corp. Project) (the “Bonds”) pursuant to Chapter 6121 of the Ohio Revised Code and a Trust Indenture dated as of April 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 “waste water facilities” as defined in Section 6121.01 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 (the “LLC Conversion”); and

WHEREAS, Section 6.5 of the Agreement provides that the Issuer and the Company may enter into, and the Trustee may consent to, amendments and supplements to the Agreement in any respect in connection with any mandatory purchase of all of the Bonds pursuant to Section 5.01(b) of the Original Indenture provided that such amendment shall not be effective until after such mandatory purchase or purchase in lieu of redemption and the payment of the purchase price in connection therewith; and

WHEREAS, the Company has directed that the Bonds be converted from a Daily Rate to a Weekly Rate on April 2, 2012, and in connection therewith the Bonds will be subject to mandatory purchase on such date; and

--

EXHIBIT 10.2

WHEREAS, consistent with the foregoing, and pursuant to the requirements of Section 15.03 of the Original Indenture, the Issuer and the Company have determined to amend the Agreement by removing references to maintaining its “corporate” existence, such amendment to be effective upon mandatory purchase of the Bonds on April 2, 2012 and payment of the purchase price in connection therewith; and

WHEREAS, concurrently herewith, the Issuer and the Trustee are entering into a First Supplemental Trust Indenture pursuant to which the Original Indenture will be amended to provide that conversions from the Daily Rate, the Weekly Rate or the Semi-Annual Rate may be made on any Business Day, and to make certain other amendments to the Original Indenture of an administrative nature (including amendments to the Original Indenture to provide for the LLC Conversion); and

WHEREAS, 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, as amended by this First Amendment, 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 shall be effective upon mandatory purchase of the Bonds, and payment of the purchase price in connection therewith, on April 2, 2012.

SECTION 4.    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

--

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     GENERATION CORP.

By: /s/ Steven R. Staub    

Assistant 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

OHIO WATER DEVELOPMENT AUTHORITY

to

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

FIRST SUPPLEMENTAL TRUST INDENTURE

Dated April 2, 2012

Supplementing and amending that certain Trust Indenture
dated as of December 1, 2006

Securing $135,550,000 of State of Ohio
Pollution Control Revenue Refunding Bonds
Series 2006-B
(FirstEnergy Nuclear Generation Corp. Project)

EXHIBIT 10.3

THIS FIRST SUPPLEMENTAL TRUST INDENTURE (the “First Supplemental Indenture”), dated April 2, 2012, is made by and between the Ohio Water Development Authority, a body politic and corporate duly organized and validly existing under the laws of the State of Ohio (the “Issuer”), and The Bank of New York Mellon Trust Company, N.A., a national banking association duly organized and existing under the laws of the United States of America and authorized to exercise trust powers under the laws of the State of Ohio, as the current trustee (the “Trustee”) under the Original Indenture (as defined below), with capitalized terms not otherwise defined herein having the same meaning as in the Original Indenture;

W I T N E S S E T H:

WHEREAS, the Issuer has issued $135,550,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-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, 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 FirstEnergy Nuclear Generation Corp. (the “Company”) in the refinancing of a portion of the cost of the acquiring, constructing and installing certain facilities comprising “waste water facilities” as defined in Section 6121.01 of the Ohio Revised Code and “solid waste facilities” as defined in Section 6123.01 of the Ohio Revised Code; and

WHEREAS, pursuant to the Original Indenture, the Issuer assigned to the Trustee the Issuer’s rights to receive loan payments under the Original Loan Agreement (defined below) and certain other rights of the Issuer thereunder; and

WHEREAS, the Issuer loaned the proceeds of the Bonds to the Company, pursuant to a Waste Water Facilities and Solid Waste Facilities Loan Agreement dated as of December 1, 2006 between the Issuer and the Company (the “Original Loan Agreement”), which provides for loan payments by the Company in amounts sufficient to pay, when due, the principal or redemption price of and interest on the Bonds; 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 (the “LLC Conversion”) and in connection therewith the Company desires to amend the Original Loan Agreement to allow for such LLC Conversion; and

WHEREAS, the Company has requested that the Issuer and the Trustee amend the Original Indenture to provide that conversions from the Daily Rate, the Weekly Rate or the Semi-Annual Rate may be made on any Business Day, and to make certain other amendments to the Original Indenture of an administrative nature (including amendments to the Original Indenture to provide for the LLC Conversion); and

WHEREAS, Section 15.01(j) of the Original Indenture provides that the Indenture may be amended or supplemented in any respect from time to time by a supplemental indenture entered into by the Issuer and the Trustee and authorized by a resolution of the Issuer filed with the

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Trustee, without the consent of the Bondholders, in connection with any mandatory purchase of all of the Bonds, provided that such amendment is not effective until after such mandatory purchase and payment of the purchase price in connection therewith; and

WHEREAS, the Company has directed that the Bonds be converted from a Daily Rate to a Weekly Rate on April 2, 2012, and in connection therewith the Bonds will be subject to mandatory purchase on such date; and

WHEREAS, the Trustee and the Issuer desire to amend the Original Indenture as requested by the Company, such amendment to be effective upon mandatory purchase of the Bonds on April 2, 2012 and payment of the purchase price in connection therewith; and

WHEREAS, concurrently herewith, the Issuer and the Company are entering into a First Amendment to Loan Agreement pursuant to which the Original Loan Agreement will be amended to provide for the LLC Conversion; and

WHEREAS, all things necessary have been done and performed to constitute this First Supplemental Indenture as a valid and binding agreement and the execution and delivery of this First Supplemental Indenture has in all respects been authorized;

NOW, THEREFORE, the Issuer hereby agrees and covenants with the Trustee and with the respective holders and owners, from time to time, of the Bonds as follows:

ARTICLE IAMENDMENTS TO ORIGINAL INDENTURE

Section 1.01Caption of the Bonds. All references in the Indenture to the caption of the Bonds are hereby amended to replace “(FirstEnergy Nuclear Generation Corp. Project)” with “(FirstEnergy Nuclear Generation Project)”.

Section 1.02Company Name. 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 Original Indenture and the Bond, in each case as amended by this First Supplemental Indenture, without the execution of an amended Bond or the filing of any instrument or any further act, deed or conveyance on the part of any of the parties hereto.

Section 1.03Definitions. 

(a)“Guaranty Agreement” means each of (i) the Guaranty Agreement dated as of March 26, 2007 executed and delivered by FirstEnergy Solutions Corp. (“FES”) and acknowledged by the Company in favor of the Guaranteed Parties as defined therein, including the Trustee as the holder of the Note, as the same may be amended, restated, supplemented or otherwise modified from time to time; and (ii) the Guaranty Agreement dated as of March 26, 2007 executed and delivered by FirstEnergy Generation Corp. and acknowledged by FES in favor of the Guaranteed Parties as defined therein, including the Trustee as the holder of the Note, as the same may be amended, restated, supplemented or otherwise modified from time to time.

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(b)“Guarantor” means any Person designated as a guarantor under a Guaranty Agreement.

(c)The definition of “Municipal Index” in Article 1 of the Original Indenture is hereby amended and restated to read as follows: “ “Municipal Index” shall mean the Securities Industry and Financial Markets Association Municipal Swap Index™ as of the most recent date for which such index was published or such other weekly, high-grade index comprised of seven-day, tax-exempt variable rate demand notes produced by Municipal Market Data, Inc., or its successor, or otherwise designated by the Securities Industry and Financial Markets Association; provided, however, that, if such index is no longer provided by Municipal Market Data, Inc. or its successor, the “Municipal Index” means such other reasonably comparable index selected by the Remarketing Agent.”

Section 1.04Failure to Set Interest Rate. Section 2.02(c)(xi) of the Original Indenture is hereby amended and restated in its entirety as follows: “In the event that the interest rate on a Bond is not or cannot be determined by the Remarketing Agent for whatever reason pursuant to (ii), (iii), (iv), (v), (vi), (vii), (viii) or (ix) above, the Interest Rate Mode of such Bond shall be converted automatically to the Weekly Rate (without the necessity of complying with the requirements of Section 2.02(e) including, but not limited to, the requirement of mandatory purchase) and the Weekly Rate shall be equal to the Municipal Index. Anything in this Section 2.02(c)(xi) to the contrary notwithstanding, if a Credit Facility is then in effect, the Rate Period determined shall not extend beyond the remaining term of such Credit Facility minus fifteen (15) days and if such fifteenth day is not a Business Day, then the immediately preceding Business Day.”

Section 1.05Long-Term Rate Period.

(a)The second sentence of Section 2.02(d)(i) of the Original Indenture is hereby amended and restated to read as follows: “Each Long-Term Rate Period shall be more than one year in duration, shall be for a period which is an integral multiple of six months, and shall end on the day next preceding an Interest Payment Date; provided that if a Long-Term Rate Period commences on a day other than a June 1 or a December 1, such Long-Term Rate Period may be for a period which is not an integral multiple of six months but shall be of a duration as close as possible to (but not in excess of) such Long-Term Rate Period established by the Company and shall terminate on a day preceding an Interest Payment Date, and each successive Long-Term Rate Period thereafter for such bonds shall be for the full period established by the Company until a different Long-Term Rate Period is specified by the Company in accordance with this Section or until the occurrence of a Conversion Date or the maturity of the Bonds; and further provided that no Long-Term Rate Period shall extend beyond the final Maturity Date of the Bonds (and any Long-Term Rate Period that extends to the day preceding the Maturity Date may be for a period which is not an integral multiple of six months).”

(b)Section 2.02(d)(ii) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Change of Long-Term Rate Period. The Company may change Bonds from one Long-Term Rate Period to another Long-Term Rate Period (provided that the portion thereof not changed to another Long-Term Rate Period shall also be in authorized denominations) on any Business Day on which such Bonds are subject to optional redemption

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pursuant to Section 9.01(a)(viii) by notifying the Issuer, the Trustee, the Paying Agent, the Credit Facility Issuer, the Tender Agent and the Remarketing Agent in writing at least four (4) Business Days prior to the thirtieth day prior to the proposed effective date of the change; provided that, if a Credit Facility is then in effect, the Company shall not be entitled to elect a change in the Long-Term Rate Period on a date on which the purchase price determined under Section 5.01(b)(i) includes any premium unless the Trustee has received written confirmation from the Credit Facility Issuer, on or before the date on which the Bond Registrar must provide notice of such change to the Bondholders under Section 2.02(d)(iii), that it can draw under a Credit Facility on the proposed effective date of the change in an aggregate amount sufficient to enable the Tender Agent to pay the premium due upon the mandatory purchase of such Bonds on such proposed effective date pursuant to Section 5.01(b)(i). Such notice shall specify (A) the aggregate principal amount of Bonds to be changed to a new Long-Term Rate Period, (B) the information required to be contained in the notice given by the Bond Registrar to the Bondholders pursuant to Section 2.02(d)(iii), (C) the anticipated last day of such new Long-Term Rate Period, which shall be the earlier of the day before the Maturity Date of the Bonds or the day immediately preceding any June 1 or December 1, and which is more than one year after the effective date of such change, (D) the purchase price for Bonds determined under Section 5.01(b)(i), and (E) if such change is conditional, the interest rate limitations. Any change by the Company of the Long-Term Rate Period may be conditional upon the establishment of an interest rate within certain limits chosen by the Company. The Remarketing Agent shall establish what would be the interest rate for the proposed Long-Term Rate Period as required by Section 2.02(c)(vi). If the interest rate established by the Remarketing Agent is not within the limits chosen by the Company, then the change in the Long-Term Rate Period may be cancelled by the Company, in which case the Company’s notice thereof shall be of no effect and no such change shall occur. Notwithstanding the foregoing, no change in the Long-Term Rate Period shall be effective unless the Credit Facility, if any, held or to be held by the Trustee after such change in the Long-Term Rate Period shall extend for the length of such Long-Term Rate Period plus fifteen (15) days.”

(c)Section 2.02(d)(iii) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Notice of Change in Long-Term Rate Period. The Bond Registrar shall notify the affected Bondholders of the mandatory tender in connection with any change in the Long-Term Rate Period pursuant to Section 2.02(d)(ii) by first class mail, postage prepaid, at least 30 but not more than 60 days before the effective date of such change. The notice will state the date of the mandatory tender associated with the change in Long-Term Rate Period, and that, on such date, Bonds will be purchased (and the purchase price therefor) and that if any owner of the Bonds shall fail to deliver a Bond for purchase with an appropriate instrument of transfer to the Tender Agent for purchase on said date, and if the Tender Agent is in receipt of the purchase price therefor, any such Bond not delivered shall nevertheless be deemed purchased on such effective date and shall cease to accrue interest on and from such date.”

(d)Section 2.02(d)(iv) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Cancellation of Change in Long-Term Rate Period. Notwithstanding any provision of this Section 2.02(d), the Long-Term Rate Period shall not be changed if: (A) the Remarketing Agent has not determined the interest rate for the new Long-Term Rate Period in accordance with this Section 2.02 or (B) all of the Bonds that are to be purchased

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pursuant to Section 5.01(b) are not remarketed or sold by the Remarketing Agent or (C) if such change is cancelled by the Company as provided in Section 2.02(d)(ii) above. If such change fails to occur, the Bonds shall be converted automatically to the Weekly Rate and the interest rate shall be equal to the Municipal Index. If the proposed change of the Long-Term Rate Period is cancelled as provided in this paragraph, any mandatory purchase of such Bonds will remain effective. Anything in this Section 2.02(d)(iv) to the contrary notwithstanding, if a Credit Facility is then in effect, the Rate Period determined upon a cancellation of a change in the Long-Term Rate Period shall not extend beyond the remaining term of such Credit Facility minus fifteen (15) days and if such fifteenth day is not a Business Day, then the immediately preceding Business Day.”

Section 1.06Conversion.

(a)Section 2.02(e)(i) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “(i)  Method of Conversion. The Interest Rate Mode for Bonds is subject to Conversion to a different Interest Rate Mode (provided that the portion thereof not converted shall also be in authorized denominations) from time to time by the Company, such right to be exercised by notifying the Issuer, the Trustee, the Paying Agent, the Credit Facility Issuer, the Tender Agent, the Remarketing Agent, the Auction Agent, the Broker-Dealer, and, in the case of a Conversion to or from the Commercial Paper Rate, the Bond Registrar at least four (4) Business Days prior to (x) in the cases of Conversion from the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate, the thirtieth day prior to the effective date of such proposed Conversion and (y) in all other cases, the fifteenth day prior to such proposed effective date; provided that, in any event, with respect to Conversion from the Commercial Paper Rate, the effective date of such Conversion may not occur until the latest Interest Payment Date relating to the Commercial Paper Rate Period then in effect for the Bonds to be converted, and, provided further, that no new Commercial Paper Rate Period for such Bonds may be established subsequent to such notice which would have an Interest Payment Date later than the proposed date of Conversion; and provided, further, that, if a Credit Facility is then in effect, the Company shall not be entitled to elect to convert Bonds to a different Interest Rate Mode on a date on which the purchase price determined under Section 5.01(b)(i) includes any premium, unless the Trustee has received written confirmation, on or before the date on which the Bond Registrar must provide notice of such Conversion to Bondholders under Section 2.02(e)(iii), from the Credit Facility Issuer that it can draw under the Credit Facility on the proposed effective date of the Conversion in an aggregate amount sufficient to enable the Tender Agent to pay any premium due upon any mandatory purchase of Bonds on such proposed effective date pursuant to Section 5.01(b)(i). Such notice shall specify (A) the effective date of such Conversion and the information required by Section 2.02(e)(iii), (B) the Interest Rate Mode into which the Company anticipates that the Bonds will be converted, (C) if such Conversion is conditional, the interest rate limitations, and (D) if it is anticipated that the Conversion will be to the Long-Term Rate, the last day of the anticipated Long-Term Rate Period, which Long-Term Rate Period shall meet the requirements of Section 2.02(d)(i). In addition, the notice shall confirm that Bond Counsel expects to be able to deliver, on the date of Conversion, an opinion of Bond Counsel stating such Conversion is authorized or permitted by the Act and is authorized by this Indenture and will not adversely affect the exclusion from gross income of interest on the Bonds for federal income tax purposes. Any Conversion by the Company of the Interest Rate Mode to the Semi-Annual Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate,

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the Five-Year Rate or the Long-Term Rate may be conditional upon the establishment of an initial interest rate determined for such Interest Rate Mode within certain limits chosen by the Company. The Remarketing Agent shall establish what would be the interest rate for the proposed Interest Rate Mode in accordance with Section 2.02(c). If the interest rate established by the Remarketing Agent is not within the limits chosen by the Company, then such Conversion may be cancelled by the Company by telephonic notice (to be confirmed in writing) to the Trustee, the Credit Facility Issuer, the Tender Agent and the Remarketing Agent by the close of business on the day on which the interest rate has been determined, in which case, the Company’s notice of Conversion shall be of no effect and the Conversion shall not occur.”

(b)Section 2.02(e)(ii)(A) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “the Conversion Date must be a date on which the Bonds are subject to optional redemption pursuant to Section 9.01(a); provided that if the Interest Rate Mode is the Daily Rate, the Weekly Rate or the Semi-Annual Rate, the Conversion Date may be any Business Day even if not an Interest Payment Date;”

(c)Section 2.02(e)(ii)(F) of the Original Indenture is hereby amended to replace the period at the end with “; and” and a new subsection (G) is hereby added as follows: “(G) the Trustee shall have received the opinion of Bond Counsel contemplated by Section 2.02(e)(i) by the opening of business at the Designated Office of the Trustee on the effective date of Conversion.”

(d)Section 2.02(e)(iii) of the Original Indenture is hereby amended and restated in its entirety to read as follows:

“Notice to Bondholders of Conversion of Interest Rate. The Bond Registrar shall notify the affected Bondholders of each Conversion by first class mail, postage prepaid, at least fifteen (15) days but not more than thirty (30) days before the Conversion Date if the Interest Rate Mode is the Commercial Paper Rate, the Dutch Auction Rate, the Daily Rate, the Weekly Rate, the Semi-Annual Rate or the Annual Rate and at least thirty (30) days but not more than sixty (60) days before the Conversion Date if the Interest Rate Mode is the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate. The notice shall state:

(A)    that the Interest Rate Mode will be converted;

(B)    the Conversion Date; and

(C)    (1) that Bonds will be subject to mandatory purchase on the Conversion Date in accordance with Section 5.01(b), (2) the purchase price, and (3) that if any owner of Bonds shall fail to deliver a Bond for purchase with an appropriate instrument of transfer to the Tender Agent on the Conversion Date, and if the Tender Agent is in receipt of the purchase price therefor, such Bond not delivered shall nevertheless be purchased on the Conversion Date and shall cease to accrue interest on and from such date.”

(e)Section 2.02(e)(iv) of the Original Indenture is hereby amended and restated

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in its entirety to read as follows: “Cancellation of Conversion of Interest Rate Mode. Notwithstanding any provision of this Section 2.02, the Interest Rate Mode for Bonds shall not be converted if: (A) the Remarketing Agent has not determined the initial interest rate for the new Interest Rate Mode in accordance with this Section 2.02 or (B) all of the Bonds that are to be purchased pursuant to Section 5.01(b) are not remarketed or sold by the Remarketing Agent or (C) the Conversion is cancelled by the Company as provided in Section 2.02(e)(i) above or (D) any other limitations on Conversion set forth in Section 2.02(e)(ii) shall not have been complied with. If such Conversion fails to occur, such Bonds in the Dutch Auction Rate shall remain in the Dutch Auction Rate and such Bonds in any other Interest Rate Mode shall be converted automatically to the Weekly Rate and the interest rate shall be equal to the Municipal Index. If the proposed Conversion of Bonds is cancelled as provided in this paragraph, any mandatory purchase of Bonds shall nevertheless be effective and such Bonds shall bear interest as provided in the preceding sentence. Anything in this Section 2.02(e)(iv) to the contrary notwithstanding, if a Credit Facility is then in effect, the Rate Period determined upon a failed Conversion shall not extend beyond the remaining term of such Credit Facility minus fifteen (15) days and if such fifteenth day is not a Business Day, then the immediately preceding Business Day.”

Section 1.07Drawings on Credit Facility.

(a)Section 5.06(a) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “If the Interest Rate Mode for the Bonds to be purchased is not the Commercial Paper Rate, then at or prior to 11:45 a.m. (New York City time) on each Purchase Date, the Tender Agent shall, by Electronic Notice, notify the Trustee of the amount of moneys delivered to it by the Remarketing Agent pursuant to Section 5.07 and which are held in the Remarketing Proceeds Account in the Purchase Fund. The Trustee shall by 12:00 noon (New York City time) draw under the Credit Facility, if any, held by the Trustee in accordance with its terms in a manner so as to furnish immediately available funds by 2:30 p.m. (New York City time) on such Purchase Date, in an amount sufficient, together with moneys described in Section 5.03(c)(i) and available for such purchase, to enable the Tender Agent to pay the purchase price of such Bonds to be purchased on such Purchase Date, directly to the Tender Agent which shall deposit those moneys directly into the Credit Facility Proceeds Account; provided, further, that if the Tender Agent is other than the Trustee and the Trustee does not receive the aforesaid Electronic Notice by the time set forth above, the Trustee shall draw under such Credit Facility the full amount of the purchase price of such Bonds to be purchased on such Purchase Date. If the Credit Facility has been repudiated or if such funds for whatever reason are not provided under the Credit Facility by 2:30 P.M. (New York City time) on such Purchase Date, then the Trustee shall immediately notify the Company and each Guarantor and demand payment (i) from the Company under the Agreement and the Note, and (ii) from each Guarantor under a Guaranty Agreement, of an amount, after taking into account any moneys then on deposit in the Company Fund, and in a manner so as to provide in the Company Fund immediately available funds sufficient to pay the purchase price of such Bonds to be purchased on such Purchase Date.”

(b)Section 5.06(c) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “If any Credit Facility permits any drawings to be made later than is provided herein, the Trustee shall make any drawing required under this Section 5.06 in accordance

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with the terms of the Credit Facility for drawing thereunder in a manner so as to be reasonably assured that immediately available funds will be available to the Tender Agent by 2:30 p.m. (New York City time) on a Purchase Date to pay the purchase price and the Tender Agent shall deposit those moneys directly into the Credit Facility Proceeds Account.”

Section 1.08Delivery of Proceeds of Sale. The first sentence of Section 5.07 of the Original Indenture is hereby amended and restated in its entirety to read as follows: “The proceeds of the remarketing of any Bonds by the Remarketing Agent shall be delivered by the Remarketing Agent directly to the Tender Agent no later than 11:30 a.m. (New York City time) on the Purchase Date except that such proceeds shall, if the Interest Rate Mode for such Bonds is, or is being converted to, the Commercial Paper Rate, be delivered to the Tender Agent no later than 1:00 p.m. (New York City time) on the Purchase Date, and, except as described in the next sentence, all such remarketing proceeds shall be deposited directly into the Remarketing Proceeds Account.”

Section 1.09Bond Fund. Section 6.02(d) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “(d)    Except with respect to payments of principal or redemption price of and interest on Bonds held pursuant to Section 5.05 or any other Bonds registered in the name of the Company, the Trustee shall, at or before 12:00 noon (New York City time) on the date on which such principal, redemption price or interest is due, draw upon or demand payment under the Credit Facility, if any, then held by the Trustee in accordance with its terms in an amount, after taking into account any moneys then on deposit in the Credit Facility Account, and in a manner so as to provide immediately available funds for principal or redemption price and interest by 2:30 p.m. (New York City time) on such due date. If the Credit Facility has been repudiated or if such funds for whatever reason are not provided under the Credit Facility by 2:30 p.m. (New York City time) on such date, then the Trustee shall immediately notify the Company and each Guarantor and demand payment (i) from the Company under the Agreement and the Note, and (ii) from each Guarantor under a Guaranty Agreement, of an amount, after taking into account any moneys then on deposit in the Company Account, and in a manner so as to provide in the Company Account immediately available funds sufficient to pay the principal or redemption price and interest on such due date.”

Section 1.10Alternate Credit Facilities. Section 7.03 of the Original Indenture is hereby amended and restated in its entirety to read as follows:

“Alternate Credit Facilities. Subject to the conditions of this Section 7.03, the Company may, at its option, provide for the delivery to the Trustee of an Alternate Credit Facility having administrative terms acceptable to the Trustee. The terms of the Alternate Credit Facility shall in all respects material to the Bondholders be the same (except for the term, maximum interest rate, number of days interest coverage and any redemption premium coverage, all as set forth in such Alternate Credit Facility) as any Credit Facility then in effect. Such Alternate Credit Facility shall have a term of not less than the greater of (a) 364 days, or (b) if the Interest Rate Mode for any Bonds then in effect is the Long-Term Rate, the then remaining portion of the then current Long-Term Rate Period, provided that such term shall end no earlier than a June 15 or a December 15 as the case may be. At least twenty five (25) days (forty (40) days if the Interest Rate Mode is the Long-Term Rate) prior

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to the proposed effective date of the proposed Alternate Credit Facility, the Company shall give notice, which notice, if the Interest Rate Mode is the Commercial Paper Rate, shall also contain a certification with respect to the length of each Commercial Paper Rate Period permitted hereunder after delivery of such Alternate Credit Facility, of such replacement to the Trustee, the Remarketing Agent, the Paying Agent, the Tender Agent and the then current Credit Facility Issuer, which notice shall confirm that (i) Bond Counsel expects to be able to deliver, on the date of delivery of the Alternate Credit Facility, an opinion of Bond Counsel stating that the delivery of such Alternate Credit Facility to the Trustee (x) is authorized under this Indenture and complies with the terms hereof and (y) will not adversely affect the exclusion from gross income of the interest on the Bonds for federal income tax purposes, and (ii) counsel to the Credit Facility Issuer of such Alternate Credit Facility expects to be able to deliver, on the date of delivery of such Alternate Credit Facility, an opinion stating that such Alternate Credit Facility is a legal, valid, binding and enforceable obligation of such Credit Facility Issuer in accordance with its terms. If (x) all of the Bonds are then subject to optional redemption pursuant to Section 9.01(a) and (y) if the purchase price of any Bonds to be purchased pursuant to Section 5.01(b)(ii) in connection with cancellation, termination or substitution of the existing Credit Facility, determined under such Section 5.01(b)(ii), includes any premium and the Trustee has received written confirmation from the Credit Facility Issuer that the Trustee can draw under the Credit Facility (other than the Alternate Credit Facility being delivered in connection with such cancellation) on the Purchase Date related to such purchase of Bonds in an aggregate amount sufficient to pay the premium due upon such purchase of Bonds on such Purchase Date, then the Trustee shall (i) accept such Alternate Credit Facility and surrender the previously held Credit Facility, if any, to the previous Credit Facility Issuer for cancellation promptly on the day the Alternate Credit Facility becomes effective and (ii) give the notice provided for in Section 7.05; provided, further, however, that such Credit Facility shall not be surrendered for cancellation until payment by the issuer of the Credit Facility to be surrendered shall have been made for any and all drawings by the Trustee effected on or before the date of such surrender for cancellation (including any drawings for payment of the purchase price of Bonds to be purchased pursuant to Section 5.01(b)(ii) in connection with such cancellation, termination or substitution). If the Interest Rate Mode for Bonds is the Commercial Paper Rate, and if the preceding sentence is applicable, the notices required under this Section 7.03 shall be delivered in sufficient time to permit the Remarketing Agent to establish a Commercial Paper Rate Period for each such Bond in accordance with Section 2.02(c)(i)(C)(1).

If a Credit Facility is in effect, the Company may at its option cause an Additional Credit Facility to be delivered to the Trustee to provide for any portion of the principal or redemption or purchase price of (including premium, if any), or interest on, the Bonds; provided that no Additional Credit Facility shall be delivered, shall become effective or shall be drawn upon for any payments hereunder unless the Trustee shall have also received (i) the opinion of Bond Counsel referred to in the preceding paragraph, (ii) an opinion of counsel to the Credit Facility Issuer of such Additional Credit Facility stating that such Additional Credit Facility is a legal, valid, binding and enforceable obligation of such issuer or obligor in accordance with its terms, (iii) the further opinion of Bond Counsel if required by the last

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paragraph of this Section 7.03 upon delivery of an Alternate Credit Facility, (iv) if such Bonds are then rated, notice from the Rating Agency to the effect that such Rating Agency has reviewed the proposed Additional Credit Facility and the provision of such Additional Credit Facility will not, by itself, result in (A) a permanent withdrawal of the rating on the Bonds or (B) a reduction in the then current rating on the Bonds, and (v) if such Additional Credit Facility is issued by an issuer other than the Credit Facility Issuer of the Credit Facility then in effect, then the written consent of such Credit Facility Issuer to the delivery of the Additional Credit Facility. The Company shall promptly give written notice to the Trustee and, if the Interest Rate Mode for Bonds is the Commercial Paper Rate, the Remarketing Agent of its intention to cause delivery of any Additional Credit Facility. If the Interest Rate Mode for Bonds is the Commercial Paper Rate, such notice from the Company shall contain a certification with respect to the maximum length of each Commercial Paper Rate Period permitted hereunder upon delivery of such Additional Credit Facility. Upon receipt of such notice, if the Additional Credit Facility is issued by an issuer other than the Credit Facility Issuer with respect to the other Credit Facility then in effect, the Trustee will promptly mail a notice of the delivery of the Additional Credit Facility by first class mail to the Issuer, the Remarketing Agent, the Tender Agent, the Paying Agent and each Bondholder at its registered address.

Any Alternate Credit Facility or Additional Credit Facility delivered to the Trustee must be accompanied by the opinions of Bond Counsel and counsel to the Credit Facility Issuer of such Alternate Credit Facility or Additional Credit Facility referred to above. In addition, if the Company grants a security interest in any cash, securities or investment property to the issuer or provider of such Alternate Credit Facility or Additional Credit Facility, the Company must furnish the Trustee with an opinion of Bond Counsel stating that such grant will not adversely affect the exclusion from gross income of interest on the Bonds for purposes of federal income taxation nor adversely affect any security interest created under this Indenture in favor of the holders of the Bonds.”

Section 1.11Amendment to Section 12.13. Section 12.13 of the Original Indenture is hereby amended and restated in its entirety to read as follows: “Qualification of Successor. A successor trustee shall be a national banking association with trust powers or a state banking corporation with trust powers or a bank and trust company or a trust company, in each case having capital and surplus of at least $75,000,000 and a S&P short-term debt rating of at least “A-2” (or, if no short-term debt rating, a long-term debt rating of at least “BBB+”), if there be one able and willing to accept the trust on acceptable and customary terms. If any successor trustee, Paying Agent or Tender Agent on any date no longer meets the aforesaid criteria, such entity shall be deemed to have resigned from such position no later than the 30^th day following the aforesaid date (subject, however, to the appointment of a successor thereto pursuant to the provisions of this Indenture) and such entity shall promptly provide written notice thereof to the entities who are to receive such notice of resignation pursuant to the provisions of this Indenture.”

Section 1.12The Remarketing Agent. Section 13.01(c) of the Original Indenture is hereby amended and restated in its entirety to read as follows: “At any time a Remarketing Agent may resign in accordance with the Remarketing Agreement. Any Remarketing Agent may be removed

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at any time in accordance with the Remarketing Agreement. Upon resignation or removal of a Remarketing Agent, the Company, with the consent of the Credit Facility Issuer if the Remarketing Agent was not the same as the Credit Facility Issuer or under common control with the Credit Facility Issuer, such consent not to be unreasonably withheld, shall either appoint a successor Remarketing Agent or authorize the remaining Remarketing Agent or Agents to act alone in such capacity, in which case all references in this Indenture to the Remarketing Agent shall mean the remaining Remarketing Agent or Agents. If the last remaining Remarketing Agent resigns or is removed, the Company shall appoint a successor Remarketing Agent. Any successor Remarketing Agent shall have combined capital stock, surplus and undivided profits of at least $50,000,000 and shall be acceptable to the Rating Agency as long as the Bonds continue to be rated; provided that the foregoing requirements shall not apply to any additional Remarketing Agents if, at the time such additional Remarketing Agents are appointed, there is currently a Remarketing Agent meeting such requirements.”

Section 1.13Acts of Bondholders. Section 14.01 of the Original Indenture is hereby amended to add an additional sentence at the end of the paragraph as follows: “Notwithstanding anything in this Indenture to the contrary, for so long as the Company holds all of the Outstanding Bonds, any action that may be taken by the registered holders of the Bonds may be taken by the Company as beneficial owner of the Bonds.”

Section 1.14Bond Form. The form of Bond set forth in the Original Indenture is hereby replaced with the form of Bond attached hereto as Exhibit A.

ARTICLE I
MISCELLANEOUS

Section 2.01Effectiveness. This First Supplemental Indenture shall be effective upon mandatory purchase of the Bonds, and payment of the purchase price in connection therewith, on April 2, 2012.

Section 2.02Original Indenture Confirmed. Except as amended by this First Supplemental Indenture, all of the provisions of the Original Indenture shall remain in full force and effect, and from and after the effective date of this First Supplemental Indenture shall be deemed to have been amended as herein set forth.

Section 2.03Severability. If any provision of this First Supplemental Indenture shall be held or deemed to be or shall, in fact, be inoperative or unenforceable as applied in any particular case in any jurisdiction or jurisdictions or in all jurisdictions, or in all cases because it conflicts with any other provision or provisions hereof or any constitution or statute or rule of public policy, or for any other reason, such circumstances shall not have the effect of rendering the provision in question inoperative or unenforceable in any other case or circumstance, or of rendering any other provision or provisions herein contained invalid, inoperative, or unenforceable to any extent whatever.

Section 2.04Counterparts. This First Supplemental Indenture may be simultaneously executed in several counterparts, each of which shall be an original and all of which shall constitute

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EXHIBIT 10.3

but one and the same instrument.

Section 2.05Applicable Provisions of Law. This First Supplemental Indenture shall be governed by and construed in accordance with the laws of the State of Ohio.

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EXHIBIT 10.3

IN WITNESS WHEREOF, OHIO WATER DEVELOPMENT AUTHORITY has caused this First Supplemental Indenture to be executed by its Executive Director, and THE BANK OF NEW YORK MELLON TRUST COMPANY, N.A. has caused this First Supplemental Indenture to be executed by one of its authorized officers, all as of the day and year first above written.

OHIO WATER DEVELOPMENT AUTHORITY

By: /s/_Steve Grossman    Executive Director

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

By: /s/ Biagio S. Impala    Authorized Signatory

CONSENT TO FIRST SUPPLEMENTAL TRUST INDENTURE

The undersigned, with respect to $135,550,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-B (FirstEnergy Nuclear Generation Corp. Project) issued by the Ohio Water Development Authority (the “Issuer”), hereby consents to the execution and delivery of the First Supplemental Trust Indenture dated April 2, 2012 (the “First Supplemental Indenture”) amending and supplementing the Trust Indenture dated as of December 1, 2006 (the “Original Indenture”), between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee, in so far as the amendments made by the First Supplemental Indenture would affect or alter the duties or obligations of the Remarketing Agent. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to them in the Original Indenture, as amended and supplemented by the First Supplemental Indenture.

Dated:  April 2, 2012

WELLS FARGO BANK, NATIONAL ASSOCIATION,
  as Remarketing Agent

By: /s/ Brian W. Hill    Name: Brian W. Hill
Title: Director

Signature Page to First Supplemental Indenture

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EXHIBIT 10.3

CONSENT TO FIRST SUPPLEMENTAL TRUST INDENTURE

The undersigned, with respect to $135,550,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-B (FirstEnergy Nuclear Generation Corp. Project) issued by the Ohio Water Development Authority (the “Issuer”), hereby consents to the execution and delivery of the First Supplemental Trust Indenture dated April 2, 2012 (the “First Supplemental Indenture”) amending and supplementing the Trust Indenture dated as of December 1, 2006 (the “Original Indenture”), between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to them in the Original Indenture, as amended and supplemented by the First Supplemental Indenture.

Dated:  April 2, 2012

FIRSTENERGY NUCLEAR GENERATION CORP.,  as the “Company”

By: /s/ Steven R. Staub     Name: Steven R. Staub
Title: Assistant Treasurer

CONSENT TO FIRST SUPPLEMENTAL TRUST INDENTURE

The undersigned, with respect to $135,550,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-B (FirstEnergy Nuclear Generation Corp. Project) issued by the Ohio Water Development Authority (the “Issuer”), hereby consents to the execution and delivery of the First Supplemental Trust Indenture dated April 2, 2012 (the “First Supplemental Indenture”) amending and supplementing the Trust Indenture dated as of December 1, 2006 (the “Original Indenture”), between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee, in so far as the amendments made by the First Supplemental Indenture would affect or alter the duties or obligations of the Tender Agent. Capitalized terms used herein and not otherwise defined shall have the meanings assigned to them in the Original Indenture, as amended and supplemented by the First Supplemental Indenture.

Dated:  April 2, 2012

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

By: /s/ Biagio S. Impala        

Authorized Signatory

Signature Page to First Supplemental Indenture

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EXHIBIT 10.3

EXHIBIT A

[FORM OF BOND]

No. ____________    $

UNITED STATES OF AMERICA

STATE OF OHIO

POLLUTION CONTROL REVENUE REFUNDING BOND

SERIES 2006-B

(FIRSTENERGY NUCLEAR GENERATION PROJECT)

MATURITY DATEINTEREST RATE MODEDATE OF THE BONDSCUSIP

[If Long-Term Rate also        Date of Original Issuance        ___

identify length of Long-

Term Rate Period]

[[TO BE FILLED IN ONLY IF INTEREST RATE MODE IDENTIFIED

ABOVE IS THE COMMERCIAL PAPER RATE AND CEDE & CO. IS

NOT THE REGISTERED OWNER:

Commercial        Commercial

Purchase        Paper Rate            Paper             Interest

Date         Period        Rate         Payable]]

Registered Owner:

Principal Sum:

THE STATE OF OHIO (the “State”), a state of the United States of America, by the Ohio Water Development Authority (the “Issuer”), a body corporate and politic organized and existing under the Constitution and laws of the State, for value received, hereby promises to pay (but only out of the sources hereinafter mentioned) to the Registered Owner named above, or registered assigns, the Principal Sum stated above on the Maturity Date stated above, unless this Bond shall have been called for redemption in whole or in part and payment of the redemption price shall have been duly made or provided for, upon surrender hereof, and to pay (but only out of the sources hereinafter mentioned) to such Registered Owner, interest thereon from the last date to which interest has accrued and been paid or duly provided for, or, if no interest has been paid or duly provided for, from the Date of the Bonds set forth above, until payment of said principal sum has been made or provided for, at the interest rate determined from time to time for the permitted Interest Rate Modes in the manner described herein and in the Indenture referred to below and

payable on the dates set forth herein and in the Indenture, commencing on the first such Interest Payment Date thereafter, and interest on overdue principal, and to the extent permitted by law, on overdue interest, as provided in the Indenture. Principal and interest shall be paid in any coin or currency of the United States of America which, at the time of payment, is legal tender for the payment of public and private debts. Interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will be paid to the Person in whose name this Bond is registered at the close of business on the Regular Record Date for such interest or, in the case of an Interest Payment Date for a Commercial Paper Rate Period, on such Interest Payment Date. Any such interest not so punctually paid or duly provided for shall forthwith cease to be payable to the registered owner at the close of business on such Regular Record Date and may be paid to the Person in whose name this Bond is registered at the close of business on the Special Record Date for the payment of such defaulted interest to be fixed by the Trustee, or may be paid, at any time in any other lawful manner, all as more fully provided in the Indenture. The principal or redemption price of this Bond shall be paid upon presentation and surrender at the Designated Office of The Bank of New York Mellon Trust Company, N.A., or at the duly designated office of any duly appointed alternative or successor paying agent (the “Paying Agent”). Except when this Bond is registered in the name of a Depository, interest on this Bond shall be payable by check mailed on the applicable Interest Payment Date by first class mail, postage prepaid to the registered owner of this Bond at such owner's address as it appears on the Bond Register of the Issuer maintained by the Trustee; provided that if this Bond is registered in the name of other than a Depository and the Interest Rate Mode for this Bond is the Commercial Paper Rate, the Dutch Auction Rate, the Daily Rate or the Weekly Rate, interest payable on this Bond shall, at the written request of the registered owner received by the Bond Registrar at least one Business Day prior to the applicable Record Date (or on or prior to an Interest Payment Date if the Interest Rate Mode is the Commercial Paper Rate), be payable to the registered owner in immediately available funds by wire transfer to a bank account of such registered owner within the United States or by deposit into a bank account maintained by the Paying Agent; provided further however that, if the Interest Rate Mode is the Commercial Paper Rate and this Bond is registered in the name of other than a Depository, interest on this Bond payable on the Interest Payment Date following the end of the Commercial Paper Rate Period shall be paid only upon presentation and surrender of this Bond at the Designated Office of the Paying Agent. When this Bond is registered in the name of a Depository or its nominee, interest is payable in same day funds delivered or transmitted to the Depository.

This Bond is one of a duly authorized series (the “Bonds”) limited in aggregate principal amount to $135,550,000 issued under a Trust Indenture, dated as of December 1, 2006, between the Issuer and The Bank of New York Mellon Trust Company, N.A., as trustee (the “Trustee”), a national banking association duly organized and validly existing under the laws of the United States of America, as amended by the First Supplemental Trust Indenture dated April 2, 2012 between the Issuer and the Trustee (as so amended, the “Indenture). The Bonds are issued by the Issuer pursuant to and in full compliance with the Constitution and laws of the State of Ohio, particularly Chapters 6121 and 6123 of the Ohio Revised Code, as amended (collectively, the “Act”), in order to assist FirstEnergy Nuclear Generation Corp. (the “Company”) in the refunding of the Refunded Bonds (as defined in the Agreement identified below), the proceeds of which were loaned by the Issuer to an Affiliates of the Company to assist those Affiliates in the refinancing of a portion of the cost of acquiring, constructing and installing certain facilities comprising “waste water

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EXHIBIT 10.3

facilities” and “solid waste facilities” as defined in Sections 6121.01 and 6123.01, respectively, of the Ohio Revised Code (the “Project”), all as set forth in the Agreement.

THE PRINCIPAL OR REDEMPTION PRICE OF AND INTEREST ON THE BONDS ARE PAYABLE SOLELY AND EXCLUSIVELY FROM THE REVENUES AND FUNDS PLEDGED FOR THEIR PAYMENT PURSUANT TO THE INDENTURE. THE BONDS ARE SPECIAL OBLIGATIONS OF THE STATE, ISSUED BY THE ISSUER AND ARE PAYABLE SOLELY FROM THE SOURCES REFERRED TO HEREIN. THE BONDS DO NOT CONSTITUTE A DEBT OR A PLEDGE OF THE FAITH AND CREDIT OF THE STATE OR ANY POLITICAL SUBDIVISION THEREOF AND THE HOLDERS OR OWNERS OF THE BONDS HAVE NO RIGHT TO HAVE TAXES LEVIED BY THE GENERAL ASSEMBLY OF THE STATE OR TAXING AUTHORITY OF ANY POLITICAL SUBDIVISION OF THE STATE FOR THE PAYMENT OF THE PRINCIPAL OR REDEMPTION PRICE OF AND INTEREST ON THE BONDS. THE ISSUER HAS NO TAXING POWER.

If an Event of Default as defined in the Indenture) occurs, the principal of and all unpaid and accrued interest on all Bonds issued under the Indenture may become due and payable upon the conditions and in the manner and with the effect provided in the Indenture.

No recourse shall be had for the payment of the principal or redemption price of, or interest on, this Bond, or for any claim based hereon or on the Indenture, against any member, officer or employee, past, present or future, of the Issuer or of any successor body, as such, either directly or through the Issuer or any such successor body, under any constitutional provision, statute or rule of law, or by the enforcement of any assessment or by any legal or equitable proceeding or otherwise.

The Bonds are payable solely from payments on the Company's Waste Water Facilities and Solid Waste Facilities Note, Series 2006-B (the “Note”) dated the Date of the Bonds and delivered by the Company to the Trustee pursuant to a Waste Water Facilities and Solid Waste Facilities Loan Agreement dated as of December 1, 2006, as amended by the First Amendment to Loan Agreement dated April 2, 2012, between the Issuer and the Company (as so amended, the “Agreement”) and from any other moneys held by the Trustee under the Indenture for such purpose, including moneys drawn by the Trustee under the Letter of Credit referred to herein or such other Credit Facility, if any, as may then be held by the Trustee under the Indenture for the benefit of the registered owners of the Bonds. The Company has caused to be delivered to the Trustee an irrevocable, direct pay, letter of credit (the “Letter of Credit”) issued by Wells Fargo Bank, N.A. (the “Bank”). Pursuant to the Indenture, the Letter of Credit may be replaced by an Alternate Credit Facility or an Additional Credit Facility may be provided. The term “Credit Facility” includes both the Letter of Credit and any such Additional or Alternate Credit Facility and the term “Credit Facility Issuer” includes any issuer of any Credit Facility in effect at the relevant time. There shall be no other recourse against the State or the Issuer or any other property now or hereafter owned by either the State or the Issuer.

The Bonds are issuable only as fully registered bonds in authorized denominations and, except as hereinafter provided, registered in the name of The Depository Trust Company, New

York, New York (“DTC”) or its nominee, which shall be considered to be the Bondholder for all purposes of the Indenture, including, without limitation, payment by the Issuer of principal or redemption price of and interest on the Bonds and receipt of notices and exercise of rights of Bondholders. There shall be a single Bond which shall be immobilized in the custody of DTC with the owners of book-entry interests in the Bonds (“book-entry interests”) having no right to receive Bonds in the form of physical securities or certificates. Ownership of book-entry interests shall be shown by book-entry on the system maintained and operated by DTC, its participants (the “Participants”) and certain Persons acting through the Participants. Transfers of ownership of book-entry interests are to be made only by DTC and the Participants by that book-entry system, the Issuer and the Trustee having no responsibility therefor. DTC is to maintain records of the positions of Participants in the Bonds, and the Participants and Persons acting through Participants are to maintain records of the purchasers and owners of book-entry interests. The Bonds as such shall not be transferable or exchangeable, except for transfer to another Depository or to another nominee of a Depository, without further action by the Issuer.

If any Depository determines not to continue to act as a Depository for the Bonds for use in a book-entry system, the Issuer may attempt to have established a securities depository/book-entry system relationship with another qualified Depository under the Indenture. If the Issuer does not or is unable to do so, the Issuer and the Trustee, after the Trustee has made provision for notification of the owners of the book-entry interests by the then Depository, shall permit withdrawal of the Bonds from the Depository, and authenticate and deliver Bond certificates in fully registered form in authorized denominations to the assignees of the Depository or its nominee, at the cost and expense (including costs of printing or otherwise preparing and delivering replacement Bonds), of the Company.

Except as otherwise specified in the Indenture, this Bond is entitled to the benefits of the Indenture equally and ratably both as to principal (and redemption price) and interest with all other Bonds issued and Outstanding under the Indenture. Reference is made to the Indenture for a description of the rights of the registered owners of the Bonds; the rights and obligations of the Issuer; the rights, duties and obligations of the Trustee; the provisions relating to amendments to and modifications of the Indenture; and for the meaning of capitalized terms not otherwise defined herein. The registered owner of this Bond shall have no right to enforce the provisions of the Indenture, the Agreement or the Note, or to institute action to enforce the covenants thereof or rights or remedies thereunder except as provided in the Indenture.

This Bond shall bear interest at the interest rate or rates determined for the “Interest Rate Mode” (as described more fully in Section 2.02 of the Indenture) selected from time to time by the Company. Until a Conversion to a different Interest Rate Mode is specified by the Company or until the Maturity Date stated above, the Interest Rate Mode for this Bond is as specified above. The Company may from time to time change the Interest Rate Mode for the Bonds, in whole or in part, to any other permitted Interest Rate Mode in accordance with the terms of the Indenture. The “Interest Rate Modes” which may be selected are as follows: (i) a Daily Rate in which the interest rate is determined each Business Day; (ii) a Weekly Rate in which the interest rate is determined on the day preceding each Weekly Rate Period or, if such day is not a Business Day, on the next succeeding Business Day; (iii) a Semi-Annual Rate in which the interest rate is determined not later

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EXHIBIT 10.3

than the Business Day preceding each Semi-Annual Rate Period; (iv) an Annual Rate in which the interest rate is determined not later than the Business Day preceding each Annual Rate Period; (v) a Two-Year Rate in which the interest rate is determined not later than the Business Day preceding each Two-Year Rate Period; (vi) a Three-Year Rate in which the interest rate is determined not later than the Business Day preceding each Three-Year Rate Period; (vii) a Five-Year Rate in which the interest rate is determined not later than the Business Day preceding each Five-Year Rate Period; (viii) a Long-Term Rate for a period selected by the Company of more than one year ending on the day preceding an Interest Payment Date, in which the interest rate is determined not later than the Business Day preceding such Long-Term Rate Period; (ix) a Commercial Paper Rate for Commercial Paper Rate Periods of one (1) day to not more than two hundred seventy (270) days (or such lower maximum number as is then permitted under the Indenture) ending on a day preceding a Business Day selected by the Remarketing Agent in which the interest rate is determined on the first day of such Commercial Paper Rate Period; and (x) a Dutch Auction Rate Period in which the interest rate for a Dutch Auction Rate Period is determined pursuant to the Dutch Auction Procedures set forth in the Indenture.

Interest on this Bond at the interest rate or rates for the Daily Rate and the Weekly Rate is payable on the first Business Day of each month; for the Semi-Annual Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate and the Long-Term Rate on June 1 and December 1, provided, however, if any June 1 or December 1 which is a Conversion Date for conversion to the Daily Rate, the Weekly Rate or the Commercial Paper Rate, is not a Business Day, then the first Business Day immediately succeeding such June 1 or December 1, as applicable; for the Commercial Paper Rate on the first Business Day following the last day of each Commercial Paper Rate Period for such Bond; for the Dutch Auction Rate, (i) for an Auction Period of 91 days or less, the Business Day immediately succeeding the last day of such Auction Period and (ii) for an Auction Period of more than 91 days, each 13^th weekly anniversary of the day immediately following the first day of such Auction Period and the Business Day immediately succeeding the last day of such Auction Period (in each case it being understood that in those instances where the immediately preceding Auction Date falls on a day that is not a Business Day, the Interest Payment Date with respect to the succeeding Auction Period shall be one Business Day immediately succeeding the next Auction Date); and for each Interest Rate Mode, on the Conversion Date to another Interest Rate Mode or on the effective date of a change in the Long-Term Rate Period. In any case, the final Interest Payment Date shall be the Maturity Date. Interest on this Bond shall be computed on the basis of a year of 365 or 366 days, as appropriate for the actual number of days elapsed, unless the Interest Rate Mode is the Semi-Annual Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate, in which case interest shall be computed on the basis of a 360-day year consisting of twelve 30-day months, or unless the Interest Rate Mode is the Dutch Auction Rate, in which case interest shall be computed on the basis of a 360‑day year for the actual number of days elapsed. The interest rate or rates for each Interest Rate Mode (and, if the Interest Rate Mode is the Commercial Paper Rate, the Commercial Paper Rate Periods) for this Bond shall be determined by the Remarketing Agent on the dates and at such times as specified in Section 2.02 of the Indenture. Except for the Auction Rate, each interest rate determined by the Remarketing Agent shall be the minimum rate of interest necessary, in the judgment of the Remarketing Agent taking into account Prevailing Market Conditions, to enable the Remarketing Agent to sell this Bond at a price equal to the principal amount hereof, plus accrued

interest, if any. Notwithstanding the foregoing, the interest rate borne by this Bond shall not exceed the lesser of (i) twelve percent (12%) per annum and (ii) so long as the Bonds are entitled to the benefit of a Credit Facility, the maximum interest rate specified in the Credit Facility.

In the event that the interest rate or rates for an Interest Rate Mode (other than the Commercial Paper Rate and the Dutch Auction Rate) are not or cannot be determined for whatever reason, the Interest Rate Mode on the Bonds shall be converted automatically to the Weekly Rate (without the necessity of complying with the requirements in the Indenture relating to conversions, including, but not limited to, the requirement of mandatory purchase) and the interest rate shall be equal to the Municipal Index. Any mandatory purchase of such Bonds will remain effective.

Subject to the provisions of the Indenture, the Company may, but is not required to, provide another Credit Facility upon cancellation, termination or expiration of the Letter of Credit or the then current Credit Facility. As described below, this Bond will become subject to mandatory purchase upon the cancellation, termination or expiration of that Credit Facility.

Redemption of Bonds

Whenever the Interest Rate Mode for this Bond is the Dutch Auction Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount thereof plus accrued interest, if any, on the Business Day immediately succeeding any Auction Date. Whenever the Interest Rate Mode for this Bond is the Daily Rate, the Weekly Rate or the Semi-Annual Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on any Interest Payment Date for this Bond. Whenever the Interest Rate Mode for this Bond is the Commercial Paper Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the Interest Payment Date for such Commercial Paper Rate Period. Whenever the Interest Rate Mode is the Annual Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Annual Rate Period. Whenever the Interest Rate Mode is the Two-Year Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Two-Year Rate Period. Whenever the Interest Rate Mode is the Three-Year Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Three-Year Rate Period. Whenever the Interest Rate Mode is the Five-Year Rate, this Bond shall be subject to optional redemption, in whole or in part, at a redemption price of 100% of the principal amount hereof on the final Interest Payment Date for each Five-Year Rate Period. Whenever the Interest Rate Mode for this Bond is the Long-Term Rate, this Bond shall be subject to optional redemption, in whole or in part (i) on the final Interest Payment Date for such Long-Term Rate Period, at a redemption price equal to the principal amount hereof plus accrued interest, if any, to the date of redemption and (ii) during the then current Long-Term Rate Period at any time with accrued interest during the redemption periods and at the redemption prices set forth below.

Original Length of                Redemption Price    

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EXHIBIT 10.3

Current Long-Term            Commencement of            as Percentage

Rate Period (Years)Redemption Periodof Principal

More than 15 years    Tenth anniversary of            

commencement of Long-                

Term Rate Period                    100%

Greater than 10 years    Fifth anniversary of                

but equal to or less    commencement of Long-                

than 15 years        Term Rate Period                    100%

Equal to or less than 10 years    Non-callable                    Non-callable

If the Company has given notice of a change in the Long-Term Rate Period or notice of Conversion of the Interest Rate Mode for the Bonds to the Long-Term Rate and, at least forty (40) days prior to such change in the Long-Term Rate Period or such Conversion of an Interest Rate Mode for the Bonds to the Long-Term Rate, the Company has provided (i) a certification of the Remarketing Agent to the Trustee and the Issuer that the foregoing schedule is not consistent with Prevailing Market Conditions and (ii) an opinion of Bond Counsel that a change in the redemption provisions will not adversely affect the exclusion from gross income of interest on the Bonds for federal income tax purposes, the foregoing redemption periods and redemption prices may be revised, effective as of the date of such change in the Long-Term Rate Period or the Conversion Date, as determined by the Remarketing Agent in its judgment, taking into account the then Prevailing Market Conditions, as set forth in such certification.

Whenever the Interest Rate Mode for this Bond is the Long-Term Rate, this Bond shall also be subject to extraordinary optional redemption at any time, in whole, at a redemption price of 100% of the principal amount hereof, plus accrued interest to the date fixed for redemption, if any, if the Company has determined that:

(A)    any federal, state or local body exercising governmental or judicial authority has taken any action which results in the imposition of burdens or liabilities with respect to the Project, or any facilities serviced thereby, rendering impracticable or uneconomical the operation of all or a substantial portion of the Project (or the facilities serviced thereby) by the Company including, without limitation, the condemnation or taking by eminent domain of all or a substantial portion of the Project or any facilities serviced thereby; or

(B)    changes in the economic availability of raw materials, operating supplies, or facilities or technological or other changes have made the continued operation of all or a substantial portion of the Project, or the operation of the facilities serviced thereby, uneconomical; or

(C)    all or a substantial portion of the Project has been damaged or destroyed to such an extent that it is not practicable or desirable to rebuild, repair or restore such Project; or

(D)    as a result of any changes in the Constitution of the State of Ohio or the Constitution of the United States of America or by legislative or administrative action (whether

state or federal) or by final decree, judgment or order of any court or administrative body (whether state or federal) after any contest thereof by the Company in good faith, the Indenture, the Agreement, the Note or the Bonds shall become void or unenforceable or impossible of performance in accordance with the intent and purposes of the parties as expressed in the Indenture or the Agreement; or

(E)    any court or administrative body shall enter a judgment, order or decree, or shall take administrative action, requiring the Company to cease all or any substantial part of its operations served by the Project to such extent that the Company is or will be prevented from carrying on its normal operations at the facilities being served by such Project for a period of at least six (6) consecutive months; or

(F)    the Company has terminated operations at the facilities being served by the Project;

provided that any such redemption shall be made not more than one (1) year from the date of such determination by the Company.

Bonds subject to optional redemption as provided above may be purchased in lieu of redemption on the applicable redemption date at a purchase price equal to 100% of the principal amount thereof, plus accrued interest thereon to, but not including, the date of such purchase, if the Trustee has received a written request from the Company on or before the Business Day prior to the date the Bonds would otherwise be subject to redemption specifying that moneys provided or to be provided by the Company shall be used to purchase such Bonds in lieu of redemption. While a Credit Facility is in place, any such purchase will be made from moneys received from a drawing on such Credit Facility and applied as provided in the Indenture. In that instance, the date of such purchase shall be deemed to be a Purchase Date, and the Bonds so purchased shall be deemed to be Pledged Bonds and shall be held by the Tender Agent pursuant to the Indenture.

The Bonds shall be subject to special mandatory redemption in whole (or in part, if, in the opinion of Bond Counsel, such partial redemption will preserve the exclusion from gross income for federal income tax purposes of interest on the Bonds remaining Outstanding after such redemption) at any time at a redemption price equal to 100% of the principal amount thereof, plus interest accrued to the redemption date, if a “final determination” is made that the interest paid or payable on any Bond to other than a “substantial user” of the Project or a “related person” (within the meaning of to Section 147(a) of the Internal Revenue Code of 1986, as amended (the “Code”)) is or was includable in the gross income of the owner thereof for federal income tax purposes under the Code, as a result of the failure of the Company to observe or perform any covenant, condition or agreement on its part to be observed or performed under the Agreement or the inaccuracy of any representation or warranty of the Company under the Agreement. A “final determination” shall be deemed to have occurred upon the issuance of a published or private ruling, technical advice or determination by the Internal Revenue Service or a judicial decision in a proceeding by any court of competent jurisdiction in the United States (from which ruling, advice, determination or decision no further right of appeal exists), in all cases in which the Company, at its expense, has participated or been a party or has been given the opportunity to contest the same or to participate or be a party,

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EXHIBIT 10.3

or receipt by the Trustee of an opinion of Bond Counsel to such effect obtained by the Company and rendered at the request of the Company. Any special mandatory redemption shall be made as soon as practicable but in any event not more than one hundred eighty (180) days from the date of such “final determination”; provided that, not later than sixty (60) days after a “final determination” is so made, the Company may advise the Trustee of the date, which shall be not later than the 180th day from the date of such “final determination”, on which the Bonds are to be redeemed. If no date is so specified, the Trustee shall establish a redemption date which shall be the 120th day, or if such day is not a Business Day, the next succeeding Business Day, following the delivery of notice to the Trustee of the making of a “final determination”. Any special mandatory redemption of less than all of the Bonds shall be made in such manner as the Trustee, with the advice of Bond Counsel, shall deem proper. If the Indenture has been released prior to the occurrence of a “final determination”, the Bonds will not be redeemed as described in this paragraph.

Any notice of redemption, identifying the Bonds or portions thereof to be redeemed, shall be given by first class mail to the registered owner of each Bond to be redeemed in whole or in part at the address shown on the Bond Register of the Issuer maintained by the Bond Registrar not more than ninety (90) days and not fewer than thirty (30) days (fifteen (15) days when the Interest Rate Mode for the Bonds is the Dutch Auction Rate) prior to the redemption date. If, at the time of the mailing of a notice of any optional redemption, the Trustee shall not have received moneys sufficient to redeem all the Bonds called for redemption, such redemption may be conditioned on, and such notice may state that it is conditional in that it is subject to, the receipt of such moneys by the Trustee not later than the redemption date, and such notice shall be of no effect unless such moneys are so received. All Bonds so called for redemption will cease to bear interest on the specified redemption date, provided funds for their redemption and any accrued interest payable on the redemption date are on deposit with the Trustee or Paying Agent at that time.

Purchase of Bonds

This Bond shall be subject to mandatory purchase (i) on the effective date of (a) the Conversion of the Interest Rate Mode for this Bond or (b) a change by the Company of the length of the Long-Term Rate Period for this Bond, (ii) on the Business Day following the end of each Commercial Paper Rate Period, Annual Rate Period, Two-Year Rate Period, Three-Year Rate Period, Five-Year Rate Period and Long-Term Rate Period, (iii) on the second day (or if such day is not a Business Day, the preceding Business Day) preceding the date of the cancellation or termination by the Trustee at the request of the Company of the then current Credit Facility, if any, or the 15th day (or if such day is not a Business Day, the preceding Business Day) preceding the stated expiration of the then current Credit Facility, if any, (iv) at the direction of the Credit Facility Issuer on the third Business Day after notice from the Credit Facility Issuer to the Trustee stating that an event of default has occurred and is continuing under the Reimbursement Agreement (as defined in the Indenture), and (v) if the Interest Rate Mode for this Bond is the Dutch Auction Rate, upon an assignment by the Company under Section 5.12 of the Agreement, on the last Interest Payment Date for the current Dutch Auction Rate Period, in each case, at a purchase price equal to 100% of the principal amount hereof, plus, if the Interest Rate Mode for this Bond is the Long-Term Rate, the optional redemption premium, if any, which would be payable if the Bonds were redeemed on such

date, plus accrued interest, if any, to the Purchase Date; provided that no premium shall be paid as part of the purchase price upon a mandatory purchase described in either clause (iii) above resulting from the stated expiration of the term of the then current Credit Facility, if any, or clause (iv) above resulting from the direction of the Credit Facility Issuer of that then current Credit Facility, if any, that an event of default has occurred and is continuing under the Reimbursement Agreement for any such Credit Facility.

This Bond, or a portion hereof in an authorized denomination (provided that the portion of this Bond to be retained by the registered owner shall also be in an authorized denomination), shall be purchased on the demand of the registered owner hereof at the times and the prices set forth below for the applicable Interest Rate Mode; provided, that if the Interest Rate Mode for this Bond is the Dutch Auction Rate, Commercial Paper Rate, the Annual Rate, the Two-Year Rate, the Three-Year Rate, the Five-Year Rate or the Long-Term Rate, the registered owner shall have no right to demand purchase of this Bond. If the Interest Rate Mode for this Bond is the Daily Rate, this Bond shall be purchased on the demand of the registered owner hereof, on any Business Day at a purchase price equal to the principal amount hereof plus accrued interest, if any, to the Purchase Date upon written notice or electronic notice to the Tender Agent not later than 10:30 a.m. (New York City time) on such Business Day. If the Interest Rate Mode for this Bond is the Weekly Rate, this Bond shall be purchased on the demand of the registered owner hereof, on any Business Day at a purchase price equal to the principal amount hereof, plus accrued interest, if any, to the Purchase Date, upon written notice to the Tender Agent at or before 5:00 p.m. (New York City time) on a Business Day not later than the seventh day prior to the Purchase Date. If the Interest Rate Mode is the Semi-Annual Rate, this Bond shall be purchased on demand of the registered owner hereof, on any Interest Payment Date (or, if such Interest Payment Date is not a Business Day, on the next succeeding Business Day) at a purchase price equal to the principal amount hereof, plus accrued interest, if any, to the Purchase Date, upon written notice to the Tender Agent on a Business Day not later than 5:00 p.m. on the seventh day prior to the Purchase Date.

Any notice in connection with a demand for purchase of this Bond as set forth in the preceding paragraph hereof shall be given at the address of the Tender Agent designated to the Trustee and shall (A) state the number and principal amount (or portion hereof in an authorized denomination) of this Bond to be purchased; (B) state the Purchase Date on which this Bond shall be purchased and (C) irrevocably request such purchase and agree to deliver this Bond to the Tender Agent on the Purchase Date. ANY SUCH NOTICE SHALL BE IRREVOCABLE WITH RESPECT TO THE PURCHASE FOR WHICH SUCH DIRECTION WAS DELIVERED AND, UNTIL SURRENDERED TO THE TENDER AGENT, THIS BOND OR ANY PORTION HEREOF WITH RESPECT TO WHICH SUCH DIRECTION WAS DELIVERED SHALL NOT BE TRANSFERABLE. This Bond must be delivered (together with an appropriate instrument of transfer executed in blank with all signatures guaranteed and in form satisfactory to the Tender Agent) at the Designated Office of the Tender Agent at or prior to 12:00 noon New York City time on the date specified in the aforesaid notice in order for the owner hereof to receive payment of the purchase price due on such Purchase Date. NO REGISTERED OWNER SHALL BE ENTITLED TO PAYMENT OF THE PURCHASE PRICE DUE ON SUCH PURCHASE DATE EXCEPT UPON SURRENDER OF THIS BOND AS SET FORTH HEREIN. NOTWITHSTANDING THE FOREGOING, THIS BOND SHALL NOT BE PURCHASED IF THE BONDS HAVE BEEN

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EXHIBIT 10.3

DECLARED DUE AND PAYABLE PURSUANT TO THE INDENTURE. No purchase of Bonds pursuant to Section 5.01 of the Indenture shall be deemed to be a payment or redemption of such Bonds or any portion thereof within the meaning of the Indenture.

BY ACCEPTANCE OF THIS BOND, THE REGISTERED OWNER HEREOF AGREES THAT THIS BOND WILL BE PURCHASED, WHETHER OR NOT SURRENDERED, (A) ON THE APPLICABLE PURCHASE DATE IN CONNECTION WITH THE EXPIRATION OF EACH COMMERCIAL PAPER RATE PERIOD, ANNUAL RATE PERIOD, TWO-YEAR RATE PERIOD, THREE-YEAR RATE PERIOD, FIVE-YEAR RATE PERIOD OR LONG-TERM RATE PERIOD FOR THIS BOND OR ON A CHANGE OF THE LONG-TERM RATE PERIOD OR ON CONVERSION OF THE INTEREST RATE MODE OF THIS BOND OR ANY CANCELLATION, TERMINATION OR EXPIRATION OF ANY CREDIT FACILITY WHICH MAY THEN BE IN EFFECT OR AT THE DIRECTION OF ANY SUCH CREDIT FACILITY ISSUER AS DESCRIBED ABOVE, OR IF THE INTEREST RATE MODE FOR THIS BOND IS THE AUCTION RATE, UPON AN ASSIGNMENT BY THE COMPANY UNDER SECTION 5.12 OF THE AGREEMENT, OR (B) ON ANY PURCHASE DATE SPECIFIED BY THE REGISTERED OWNER HEREOF IN THE EXERCISE OF THE RIGHT TO DEMAND PURCHASE OF THIS BOND AS DESCRIBED ABOVE. IN SUCH EVENT, THE REGISTERED OWNER OF THIS BOND SHALL NOT BE ENTITLED TO RECEIVE ANY FURTHER INTEREST HEREON AND SHALL HAVE NO FURTHER RIGHTS UNDER THIS BOND OR THE INDENTURE EXCEPT TO PAYMENT OF THE PURCHASE PRICE HELD THEREFOR.

The current Remarketing Agent under the Indenture is Wells Fargo Bank, National Association. The current Tender Agent under the Indenture is The Bank of New York Mellon Trust Company, N.A. On or before the effective date of a Conversion to a Dutch Auction Rate, a Market Agent and an Auction Agent are to be appointed in accordance with the Indenture. The Remarketing Agent, the Market Agent, the Tender Agent and the Auction Agent may be changed at any time in accordance with the Indenture.

The Bonds are issuable only as fully registered Bonds in the denominations of $5,000 and any integral multiple thereof except that Bonds authenticated when the Interest Rate Mode is the Daily Rate, the Weekly Rate, the Commercial Paper Rate or the Semi-Annual Rate shall be in denominations of $100,000 and any larger denomination constituting an integral multiple of $5,000 and except that Bonds authenticated when the Interest Rate Mode is the Dutch Auction Rate shall be in denominations of $25,000 and any integral multiple thereof. Subject to the limitations provided in the Indenture and upon payment of any tax or government charge, if any, Bonds may be exchanged for a like aggregate principal amount of Bonds of other authorized denominations and in the same Interest Rate Mode.

This Bond is transferable by the registered owner hereof or his duly authorized attorney at the corporate trust office of the Bond Registrar, upon surrender of this Bond, accompanied by a duly executed instrument of transfer in form and with guaranty of signature satisfactory to the Bond Registrar, subject to such reasonable regulations as the Issuer, the Tender Agent, the Trustee or the Bond Registrar may prescribe, and upon payment of any tax or other governmental charge incident to such transfer, PROVIDED, THAT, IF MONEYS FOR THE PURCHASE OF THIS

BOND HAVE BEEN DEPOSITED WITH THE TENDER AGENT UNDER THE INDENTURE, THIS BOND SHALL NOT BE TRANSFERABLE TO ANYONE UNTIL DELIVERED TO THE TENDER AGENT AND PROVIDED FURTHER THAT NEITHER THE ISSUER NOR THE BOND REGISTRAR SHALL BE REQUIRED (i) TO REGISTER THE TRANSFER OF OR EXCHANGE ANY BOND DURING A PERIOD BEGINNING AT THE OPENING OF BUSINESS FIFTEEN (15) DAYS BEFORE THE DAY OF MAILING OF A NOTICE OF REDEMPTION OF BONDS SELECTED FOR REDEMPTION AND ENDING AT THE CLOSE OF BUSINESS ON THE DAY OF SUCH MAILING, (ii) TO REGISTER THE TRANSFER OF OR EXCHANGE ANY BOND SO SELECTED FOR REDEMPTION IN WHOLE OR IN PART, OR (iii) OTHER THAN PURSUANT TO ARTICLE V OF THE INDENTURE, TO REGISTER ANY TRANSFER OF OR EXCHANGE ANY BOND WITH RESPECT TO WHICH THE OWNER HAS SUBMITTED A DEMAND FOR PURCHASE IN ACCORDANCE WITH SECTION 5.01(a) OR WHICH HAS BEEN PURCHASED PURSUANT TO SECTION 5.01(b) OF THE INDENTURE. Upon any such transfer, a new Bond or Bonds in the same aggregate principal amount and in the same Interest Rate Mode will be issued to the transferee. Except as set forth in this Bond and as otherwise provided in the Indenture, the Person in whose name this Bond is registered shall be deemed the owner hereof for all purposes, and the Issuer, any Paying Agent, the Bond Registrar, the Tender Agent, the Remarketing Agent, the Market Agent, the Auction Agent and the Trustee shall not be affected by any notice to the contrary.

This Bond is not valid unless the Certificate of Authentication endorsed hereon has been executed by the manual signature of an authorized signatory of the Trustee.

IN WITNESS WHEREOF, the State of Ohio, by the Ohio Water Development Authority, has caused this Bond to be executed in its name by the facsimile signature of the Chairman and Vice-Chairman of the Issuer, and the facsimile of the corporate seal of the Issuer to be printed hereon and attested by the facsimile signature of the Secretary-Treasurer of the Issuer, all as of the Date of the Bonds shown above.

STATE OF OHIO, BY THE OHIO

WATER DEVELOPMENT AUTHORITY

By:

Chairman

By:

Vice-Chairman

ATTEST:

Secretary-Treasurer

[SEAL]

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EXHIBIT 10.3

[FORM OF CERTIFICATE OF AUTHENTICATION]

This Bond is one of the Bonds described in the within mentioned Indenture.

Date of Authentication:

THE BANK OF NEW YORK MELLON TRUST

COMPANY, N.A.

as Trustee

By:

Authorized Signatory

[FORM OF LEGAL OPINION]

The following is a true copy of the text of the opinion rendered to the original purchasers of the Bonds by Squire, Sanders & Dempsey L.L.P. in connection with the original issuance of the Bonds. That opinion is dated as of and premised on the transcript of proceedings examined and the law in effect on the date of original delivery of the Bonds. A signed copy of the opinion is on file in this office.

OHIO WATER DEVELOPMENT

AUTHORITY

By (facsimile)    

Secretary-Treasurer

[TEXT OF LEGAL OPINION]

Respectfully submitted,

SQUIRE, SANDERS & DEMPSEY L.L.P.

[FORM OF ASSIGNMENT]

For value received, the undersigned hereby sells, assigns and transfers unto ______________________________ the within bond and all rights thereunder, and hereby irrevocably constitutes and appoints _______________________________, attorney to transfer the

said bond on the Bond Register, with full power of substitution in the premises.

Dated:

Social Security Number or

Employer Identification

Number of Transferee:

Signature guaranteed:                                         

Signature must be guaranteed by a

member of an approved Signature

Guarantee Medallion Program.

NOTICE: The assignor's signature to this Assignment must correspond with the name as it appears on the face of the within bond in every particular without alteration, enlargement or any change whatever.

[FORM OF ABBREVIATIONS]

The following abbreviations, when used in the inscription on the face of the within bond, shall be construed as though they were written out in full according to applicable laws or regulations.

TEN COM - as tenants in common

TEN ENT - as tenants by the entireties

JT TEN - as joint tenants with right of survivorship and not as tenants in common

UNIFORM TRANSFERS TO MIN ACT - ___________________ Custodian ________________

(Cust)    (Minor)

under Uniform Transfers to Minors Act _______________________

(State)

Additional abbreviations may also be used though not in the above list.

Unless this certificate is presented by an authorized representative of The Depository Trust Company, a New York corporation (“DTC”), to the Issuer or its agent for registration of transfer, exchange, or payment, and any certificate issued is registered in the name of Cede & Co. or in such other name as is requested by an authorized representative of DTC (and any payment is made to Cede & Co. or to such other entity as is requested by an authorized representative of DTC), ANY TRANSFER, PLEDGE, OR OTHER USE HEREOF FOR VALUE OR OTHERWISE BY OR TO ANY PERSON IS WRONGFUL inasmuch as the registered owner hereof, Cede & Co., has an interest herein.

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EX-10.4

EXHIBIT 10.4

FIRST AMENDMENT TO LOAN AGREEMENT

THIS FIRST AMENDMENT TO LOAN AGREEMENT (the “First Amendment”), dated April 2, 2012 by and between the OHIO WATER DEVELOPMENT AUTHORITY (the “Issuer”) and FIRSTENERGY NUCLEAR GENERATION CORP. (the “Company”), to the Waste Water Facilities and Solid Waste Facilities 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 $135,550,000 State of Ohio Pollution Control Revenue Refunding Bonds Series 2006-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 $135,550,000 aggregate principal amount of State of Ohio Pollution Control Revenue Refunding Bonds, Series 2006-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, 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 “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 (the “LLC Conversion”); and

WHEREAS, Section 6.5 of the Agreement provides that the Issuer and the Company may enter into, and the Trustee may consent to, amendments and supplements to the Agreement in any respect in connection with any mandatory purchase of all of the Bonds pursuant to Section 5.01(b) of the Original Indenture provided that such amendment shall not be effective until after such mandatory purchase or purchase in lieu of redemption and the payment of the purchase price in connection therewith; and

WHEREAS, the Company has directed that the Bonds be converted from a Daily Rate to a Weekly Rate on April 2, 2012, and in connection therewith the Bonds will be subject to mandatory purchase on

--

EXHIBIT 10.4

such date; and

WHEREAS, consistent with the foregoing, and pursuant to the requirements of Section 15.03 of the Original Indenture, the Issuer and the Company have determined to amend the Agreement by removing references to maintaining its “corporate” existence, such amendment to be effective upon mandatory purchase of the Bonds on April 2, 2012 and payment of the purchase price in connection therewith; and

WHEREAS, concurrently herewith, the Issuer and the Trustee are entering into a First Supplemental Trust Indenture pursuant to which the Original Indenture will be amended to provide that conversions from the Daily Rate, the Weekly Rate or the Semi-Annual Rate may be made on any Business Day, and to make certain other amendments to the Original Indenture of an administrative nature (including amendments to the Original Indenture to provide for the LLC Conversion); and

WHEREAS, 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, as amended by this First Amendment, 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 shall be effective upon mandatory purchase of the Bonds, and payment of the purchase price in connection therewith, on April 2, 2012.

SECTION 4.    This First Amendment may be executed in any number of counterparts, each

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EXHIBIT 10.4

of which shall be regarded as an original and all of which shall constitute but one and the same instrument.

--

EXHIBIT 10.4

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/ Steven R. Staub    

Assistant 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

	Six Months Ended June 30
	2012		2011
	(Dollars in millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Income before extraordinary items	$	494	$	240
Interest and other charges, before reduction for amounts capitalized and deferred	520		496
Provision for income taxes	349		225
Interest element of rentals charged to income (1)	71		74
Earnings as defined	$	1,434	$	1,035
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	520	$	496
Interest element of rentals charged to income (1)	71		74
Fixed charges as defined	$	591	$	570
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES	2.43		1.82

⁽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: August 7, 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: August 7, 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: August 7, 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: August 7, 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: August 7, 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: August 7, 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: August 7, 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: August 7, 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 June 30, 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: August 7, 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 June 30, 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: August 7, 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 June 30, 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: August 7, 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 June 30, 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: August 7, 2012

XML

Segment Information (Tables)

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

Segment Financial Information

Segment Financial Information

Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
June 30, 2012
External revenues	$	2,095	$	184	$	1,616	$	(24	)	$	(2	)	$	3,869
Internal revenues	—		—		209		—			(209		)	—
Total revenues	2,095		184		1,825		(24		)	(211		)	3,869
Depreciation and amortization	215		29		103		8			(1		)	354
Investment income	19		—		6		1			(13		)	13
Net interest charges	132		22		59		42			—			255
Income taxes	94		31		14		(25		)	13			127
Net income	161		52		25		(42		)	(8		)	188
Total assets	25,787		4,473		17,216		572			—			48,048
Total goodwill	5,025		526		893		—			—			6,444
Property additions	177		59		150		26			—			412
June 30, 2011
External revenues	$	2,409	$	182	$	1,495	$	(30	)	$	(8	)	$	4,048
Internal revenues	—		—		318		—			(306		)	12
Total revenues	2,409		182		1,813		(30		)	(314		)	4,060
Depreciation and amortization	232		28		109		8			—			377
Investment income	25		—		16		—			(10		)	31
Net interest charges	134		24		69		19			(1		)	245
Income taxes	100		33		12		(30		)	(1		)	114
Net income	171		57		21		(51		)	(5		)	193
Total assets	25,069		4,202		17,146		1,179			—			47,596
Total goodwill	5,025		526		885		—			—			6,436
Property additions	266		81		197		25			—			569
Six Months Ended
June 30, 2012
External revenues	$	4,420	$	370	$	3,222	$	(47	)	$	(20	)	$	7,945
Internal revenues	—		—		477		—			(475		)	2
Total revenues	4,420		370		3,699		(47		)	(495		)	7,947
Depreciation and amortization	435		61		203		16			(1		)	714
Investment income	42		1		12		1			(32		)	24
Net interest charges	264		45		113		63			(1		)	484
Income taxes	187		66		97		(41		)	40			349
Net income	318		112		166		(69		)	(33		)	494
Total assets	25,787		4,473		17,216		572			—			48,048
Total goodwill	5,025		526		893		—			—			6,444
Property additions	443		122		393		43			—			1,001
June 30, 2011
External revenues	$	4,632	$	295	$	2,736	$	(53	)	$	(18	)	$	7,592
Internal revenues	—		—		661		—			(617		)	44
Total revenues	4,632		295		3,397		(53		)	(635		)	7,636
Depreciation and amortization	473		50		197		14			—			734
Investment income	48		—		21		1			(18		)	52
Net interest charges	256		41		122		39			—			458
Income taxes	158		47		21		(30		)	29			225
Net income	267		80		36		(105		)	(38		)	240
Total assets	25,069		4,202		17,146		1,179			—			47,596
Total goodwill	5,025		526		885		—			—			6,436
Property additions	381		170		411		56			—			1,018

XML

Fair Value Measurements (Details 6) (USD $) In Millions, unless otherwise specified	Jun. 30, 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	$ 15,159	$ 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	16,571	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	18,998	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	2,500	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	3,617	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	3,862	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	1,157	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	1,157	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	1,493	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	1,720	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	1,762	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	$ 2,076	$ 2,080

XML

Fair Value Measurements (Details) (Recurring, USD $) In Millions, unless otherwise specified	Jun. 30, 2012		Dec. 31, 2011
Assets
Fair value, assets	$ 2,924		$ 2,863
Liabilities
Fair value, liabilities	(742)		(619)
Net assets (liabilities)	2,182	[1]	2,244	[1]
FES
Assets
Fair value, assets	1,594		1,530
Liabilities
Fair value, liabilities	(269)		(241)
Net assets (liabilities)	1,325	[2]	1,289	[2]
OE
Assets
Fair value, assets	141	[3]	137	[3]
JCP&L
Assets
Fair value, assets	425		414
Liabilities
Fair value, liabilities	(270)		(147)
Net assets (liabilities)	155	[4]	267	[4]
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(263)		(247)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(263)		(234)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(9)		(23)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(6)		(7)
Interest rate swaps | Derivative Liabilities
Liabilities
Fair value, liabilities	(23)		0
Non Utility Generation contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(302)	[5]	(349)	[5]
Non Utility Generation contract | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	(125)	[6]	(147)	[6]
LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(145)	[5]	0	[5]
LCAPP Contracts | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	(145)	[6]	0	[6]
Corporate debt securities
Assets
Fair value, assets	1,636		1,544
Corporate debt securities | FES
Assets
Fair value, assets	1,057		1,010
Corporate debt securities | OE
Assets
Fair value, assets	0		3
Corporate debt securities | JCP&L
Assets
Fair value, assets	149		144
Commodity contracts | Derivative Assets
Assets
Fair value, assets	341		264
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	330		248
FTRs | Derivative Assets
Assets
Fair value, assets	12		1
FTRs | Derivative Assets | FES
Assets
Fair value, assets	8		1
Interest rate swaps | Derivative Assets
Assets
Fair value, assets	3		0
Non Utility Generation contract | Derivative Assets
Assets
Fair value, assets	9	[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	280	[7]	259	[7]
Equity securities | FES
Assets
Fair value, assets	145	[7]	124	[7]
Equity securities | JCP&L
Assets
Fair value, assets	30	[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	144		148
U.S. government debt securities | FES
Assets
Fair value, assets	6		7
U.S. government debt securities | OE
Assets
Fair value, assets	138		132
U.S. government debt securities | JCP&L
Assets
Fair value, assets	0		2
U.S. state debt securities
Assets
Fair value, assets	308		314
U.S. state debt securities | FES
Assets
Fair value, assets	0		5
U.S. state debt securities | JCP&L
Assets
Fair value, assets	223		219
Other
Assets
Fair value, assets	191	[8]	274	[8]
Other | FES
Assets
Fair value, assets	48	[8]	132	[8]
Other | OE
Assets
Fair value, assets	3	[8]	2	[8]
Other | JCP&L
Assets
Fair value, assets	19	[8]	15	[8]
Level 1
Assets
Fair value, assets	347		308
Liabilities
Fair value, liabilities	(1)		0
Net assets (liabilities)	346	[1]	308	[1]
Level 1 | FES
Assets
Fair value, assets	149		124
Liabilities
Fair value, liabilities	(1)		0
Net assets (liabilities)	148	[2]	124	[2]
Level 1 | OE
Assets
Fair value, assets	0	[3]	0	[3]
Level 1 | JCP&L
Assets
Fair value, assets	30		30
Liabilities
Fair value, liabilities	0		0
Net assets (liabilities)	30	[4]	30	[4]
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(1)		0
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(1)		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 | Interest rate swaps | Derivative Liabilities
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 | LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[5]	0	[5]
Level 1 | LCAPP Contracts | 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 | OE
Assets
Fair value, assets	0		0
Level 1 | Corporate debt securities | JCP&L
Assets
Fair value, assets	0		0
Level 1 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	4		0
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	4		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 | Interest rate swaps | Derivative Assets
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	280	[7]	259	[7]
Level 1 | Equity securities | FES
Assets
Fair value, assets	145	[7]	124	[7]
Level 1 | Equity securities | JCP&L
Assets
Fair value, assets	30	[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 | OE
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. 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	63	[8]	49	[8]
Level 1 | Other | FES
Assets
Fair value, assets	0	[8]	0	[8]
Level 1 | Other | OE
Assets
Fair value, assets	0	[8]	0	[8]
Level 1 | Other | JCP&L
Assets
Fair value, assets	0	[8]	0	[8]
Level 2
Assets
Fair value, assets	2,556		2,498
Liabilities
Fair value, liabilities	(285)		(247)
Net assets (liabilities)	2,271	[1]	2,251	[1]
Level 2 | FES
Assets
Fair value, assets	1,437		1,405
Liabilities
Fair value, liabilities	(262)		(234)
Net assets (liabilities)	1,175	[2]	1,171	[2]
Level 2 | OE
Assets
Fair value, assets	141	[3]	137	[3]
Level 2 | JCP&L
Assets
Fair value, assets	391		380
Liabilities
Fair value, liabilities	0		0
Net assets (liabilities)	391	[4]	380	[4]
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(262)		(247)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(262)		(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 | Interest rate swaps | Derivative Liabilities
Liabilities
Fair value, liabilities	(23)		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 | LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[5]	0	[5]
Level 2 | LCAPP Contracts | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	0	[6]	0	[6]
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,636		1,544
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	1,057		1,010
Level 2 | Corporate debt securities | OE
Assets
Fair value, assets	0		3
Level 2 | Corporate debt securities | JCP&L
Assets
Fair value, assets	149		144
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	337		264
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	326		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 | Interest rate swaps | Derivative Assets
Assets
Fair value, assets	3		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	[7]	0	[7]
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	144		148
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	6		7
Level 2 | U.S. government debt securities | OE
Assets
Fair value, assets	138		132
Level 2 | U.S. government debt securities | JCP&L
Assets
Fair value, assets	0		2
Level 2 | U.S. state debt securities
Assets
Fair value, assets	308		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	223		219
Level 2 | Other
Assets
Fair value, assets	128	[8]	225	[8]
Level 2 | Other | FES
Assets
Fair value, assets	48	[8]	132	[8]
Level 2 | Other | OE
Assets
Fair value, assets	3	[8]	2	[8]
Level 2 | Other | JCP&L
Assets
Fair value, assets	19	[8]	15	[8]
Level 3
Assets
Fair value, assets	21		57
Liabilities
Fair value, liabilities	(456)		(372)
Net assets (liabilities)	(435)	[1]	(315)	[1]
Level 3 | FES
Assets
Fair value, assets	8		1
Liabilities
Fair value, liabilities	(6)		(7)
Net assets (liabilities)	2	[2]	(6)	[2]
Level 3 | OE
Assets
Fair value, assets	0	[3]	0	[3]
Level 3 | JCP&L
Assets
Fair value, assets	4		4
Liabilities
Fair value, liabilities	(270)		(147)
Net assets (liabilities)	(266)	[4]	(143)	[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	(9)		(23)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(6)		(7)
Level 3 | Interest rate swaps | Derivative Liabilities
Liabilities
Fair value, liabilities	0		0
Level 3 | Non Utility Generation contract | Derivative Liabilities
Liabilities
Fair value, liabilities	(302)	[5]	(349)	[5]
Level 3 | Non Utility Generation contract | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	(125)	[6]	(147)	[6]
Level 3 | LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(145)	[5]	0	[5]
Level 3 | LCAPP Contracts | Derivative Liabilities | JCP&L
Liabilities
Fair value, liabilities	(145)	[6]	0	[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 | OE
Assets
Fair value, assets	0		0
Level 3 | Corporate debt securities | JCP&L
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	12		1
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	8		1
Level 3 | Interest rate swaps | Derivative Assets
Assets
Fair value, assets	0		0
Level 3 | Non Utility Generation contract | Derivative Assets
Assets
Fair value, assets	9	[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	[7]	0	[7]
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 | OE
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. 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	[8]	0	[8]
Level 3 | Other | FES
Assets
Fair value, assets	0	[8]	0	[8]
Level 3 | Other | OE
Assets
Fair value, assets	0	[8]	0	[8]
Level 3 | Other | JCP&L
Assets
Fair value, assets	$ 0	[8]	$ 0	[8]

[1] Excludes $(7) million and $(52) million as of June 30, 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 $(6) million and $(58) million as of June 30, 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 $1 million as of June 30, 2012 and December 31, 2011, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

[4] Excludes $2 million as of June 30, 2012 and December 31, 2011 of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

[5] NUG and LCAPP contracts are generally subject to regulatory accounting treatment and do not impact earnings.

[6] NUG and LCAPP contracts are subject to regulatory accounting treatment and do not impact earnings.

[7] NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index.

[8] Primarily consists of short-term cash investments.

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Fair Value Measurements (Details Textuals) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ (7)	$ (52)
Cash balance excluded from available for sale securities	113	164
Investments not required to be disclosed	716	693
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	(6)	(58)
Cash balance excluded from available for sale securities	42	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	3	2
JCP&L
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	2	2
Cash balance excluded from available for sale securities	$ 23	$ 19

XML

Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,318
Discounted Lease Payments, net	1,111	[1]
Variable Interest Entities Net Exposure	207
OE
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	574
Discounted Lease Payments, net	384	[1]
Variable Interest Entities Net Exposure	190
Other First Energy Subsidiaries
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	599
Discounted Lease Payments, net	333	[1]
Variable Interest Entities Net Exposure	$ 266

[1] The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.5 billion.

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Pensions and Other Postemployment Benefits (Tables)

6 Months Ended

Jun. 30, 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 June 30,	2012			2011			2012			2011
	(In millions)
Service cost	$	40		$	34		$	3		$	3
Interest cost	97			96			12			12
Expected return on plan assets	(121		)	(115		)	(9		)	(10		)
Amortization of prior service cost	3			4			(51		)	(51		)
Other adjustments (settlements, curtailments, etc)	—			—			—			—
Net periodic costs (credits)	$	19		$	19		$	(45	)	$	(46	)

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Six Months Ended June 30,	2012			2011			2012			2011
	(In millions)
Service cost	$	80		$	63		$	6		$	6
Interest cost	194			180			24			23
Expected return on plan assets	(242		)	(217		)	(18		)	(20		)
Amortization of prior service cost	6			8			(102		)	(99		)
Other adjustments (settlements, curtailments, etc)	—			7			—			—
Net periodic costs (credits)	$	38		$	41		$	(90	)	$	(90	)

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 June 30,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	14		$	14		$	(32	)	$	(34	)
FES	11			7			(8		)	(9		)
OE	(1		)	(2		)	(6		)	(5		)
JCP&L	(2		)	(3		)	(2		)	(2		)

Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Six Months Ended June 30,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	27		$	34		$	(62	)	$	(66	)
FES	21			14			(16		)	(16		)
OE	(2		)	(4		)	(11		)	(11		)
JCP&L	(3		)	(5		)	(4		)	(5		)

XML

Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012 MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases, in ones	29,000,000
Sales, in ones	40,000,000
Net, in ones	(11,000,000)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases, in ones	82,000,000
Sales, in ones	0
Net, in ones	82,000,000
Interest rate swaps
Volume of First Energy's outstanding derivative transactions
Volume of Derivatives, Purchases	1,600
Volume of Derivatives, Sales	0
Volume of Derivatives, Net	1,600
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases, in ones	22,000,000
Sales, in ones	0
Net, in ones	22,000,000
LCAPP
Volume of First Energy's outstanding derivative transactions
Volume of Derivatives, Purchases, in ones	408,000,000
Volume of Derivatives, Sales, in ones	0
Volume of Derivatives, Net, in ones	408,000,000
Natural Gas Futures
Volume of First Energy's outstanding derivative transactions
Purchases, in ones	26,000,000
Sales, in ones	0
Net, in ones	26,000,000

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Fair Value Measurements

6 Months Ended

Jun. 30, 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 quarterly basis, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. 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.

LCAPP contracts are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. LCAPP contracts are recorded at fair value using a mark-to-model methodology on a quarterly basis, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Quarterly pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices for the 2015/2016 delivery year and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2015/2016 delivery year are developed through a simulation of future PJM RPM auctions. The capacity price forecast assumes a continuation of the current PJM RPM market design and is reflective of the regional peak demand growth and generation fleet additions and retirements that underlie FirstEnergy’s long-term energy price forecast. 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 June 30, 2012 from those used as of 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 transfers between levels during the six months ended June 30, 2012. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy.

FE CONSOLIDATED
Recurring Fair Value Measurements	June 30, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,636		$	—		1,636			$	—	$	1,544		$	—		$	1,544
Derivative assets - commodity contracts	4			337			—			341			—		264			—			264
Derivative assets - FTRs	—			—			12			12			—		—			1			1
Derivative assets - interest rate swaps	—			3			—			3			—		—			—			—
Derivative assets - NUG contracts(1)	—			—			9			9			—		—			56			56
Equity securities(2)	280			—			—			280			259		—			—			259
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			144			—			144			—		148			—			148
U.S. state debt securities	—			308			—			308			—		314			—			314
Other(3)	63			128			—			191			49		225			—			274
Total assets	347			2,556			21			2,924			308		2,498			57			2,863
Liabilities
Derivative liabilities - commodity contracts	(1		)	(262		)	—			(263		)	—		(247		)	—			(247		)
Derivative liabilities - FTRs	—			—			(9		)	(9		)	—		—			(23		)	(23		)
Derivative liabilities - interest rate swaps	—			(23		)	—			(23		)	—		—			—			—
Derivative liabilities - NUG contracts(1)	—			—			(302		)	(302		)	—		—			(349		)	(349		)
Derivative liabilities - LCAPP contracts(1)	—			—			(145		)	(145		)	—		—			—			—
Total liabilities	(1		)	(285		)	(456		)	(742		)	—		(247		)	(372		)	(619		)
Net assets (liabilities)(4)	$	346		$	2,271		$	(435	)	$	2,182		$	308	$	2,251		$	(315	)	$	2,244

⁽¹⁾  NUG and LCAPP contracts are generally subject to regulatory accounting treatment 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 $(7) million and $(52) million as of June 30, 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 and LCAPP contracts held by certain Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:

	NUG Contracts(1)									LCAPP Contracts(1)								FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
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)	(48		)	(86		)	(134		)	—		—			—			—			(2		)	(2		)
Purchases	—			—			—			—		(145		)	(145		)	12			(9		)	3
Issues	—			—			—			—		—			—			—			—			—
Sales	—			—			—			—		—			—			—			—			—
Settlements	—			133			133			—		—			—			(1		)	25			24
Transfers in (out) of Level 3	—			—			—			—		—			—			—			—			—
June 30, 2012 Balance	$	9		$	(302	)	$	(293	)	$	—	$	(145	)	$	(145	)	$	12		$	(9	)	$	3

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

Level 3 Quantitative Information

The following table provides quantitative information for FTRs, NUG contracts and LCAPP contracts that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	3		Model	RTO auction clearing prices	($3.60) to $4.90	$	0.70	Dollars/MWH
NUG Contracts	$	(293	)	Model	Generation Electricity regional prices	500 to 6,609,000 $49.50 to $84.90	2,665,000 $63.70		MWH Dollars/MWH
LCAPP Contracts	$	(145	)	Model	Regional capacity prices	$94.90 to $248.40	$183.90		Dollars/MW-Day

FES
Recurring Fair Value Measurements	June 30, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,057		$	—		$	1,057		$	—	$	1,010		$	—		$	1,010
Derivative assets - commodity contracts	4			326			—			330			—		248			—			248
Derivative assets - FTRs	—			—			8			8			—		—			1			1
Equity securities(1)	145			—			—			145			124		—			—			124
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			6			—			6			—		7			—			7
U.S. state debt securities	—			—			—			—			—		5			—			5
Other(2)	—			48			—			48			—		132			—			132
Total assets	149			1,437			8			1,594			124		1,405			1			1,530
Liabilities
Derivative liabilities - commodity contracts	(1		)	(262		)	—			(263		)	—		(234		)	—			(234		)
Derivative liabilities - FTRs	—			—			(6		)	(6		)	—		—			(7		)	(7		)
Total liabilities	(1		)	(262		)	(6		)	(269		)	—		(234		)	(7		)	(241		)
Net assets (liabilities)(3)	$	148		$	1,175		$	2		$	1,325		$	124	$	1,171		$	(6	)	$	1,289

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

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

⁽³⁾  Excludes $(6) million and $(58) million as of June 30, 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 June 30, 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	8			(7		)	1
Issues	—			—			—
Sales	—			—			—
Settlements	(1		)	9			8
Transfers in (out) of Level 3	—			—			—
June 30, 2012 Balance	$	8		$	(6	)	$	2

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 June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)		Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	2	Model	RTO auction clearing prices	($3.60) to $4.90	$0.50	Dollars/MWH

OE
Recurring Fair Value Measurements	June 30, 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	—		138		—		138		—		132		—		132
Other(1)	—		3		—		3		—		2		—		2
Total assets(2)	$	—	$	141	$	—	$	141	$	—	$	137	$	—	$	137

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

⁽²⁾  Excludes $1 million as of June 30, 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	June 30, 2012										December 31, 2011
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	149	$	—		$	149		$	—	$	144	$	—		$	144
Derivative assets - NUG contracts(1)	—		—		4			4			—		—		4			4
Equity securities(2)	30		—		—			30			30		—		—			30
U.S. government debt securities	—		—		—			—			—		2		—			2
U.S. state debt securities	—		223		—			223			—		219		—			219
Other(3)	—		19		—			19			—		15		—			15
Total assets	30		391		4			425			30		380		4			414
Liabilities
Derivative liabilities - NUG contracts(1)	—		—		(125		)	(125		)	—		—		(147		)	(147		)
Derivative liabilities - LCAPP contracts(1)	—		—		(145		)	(145		)	—		—		—			—
Total liabilities	—		—		(270		)	(270		)	—		—		(147		)	(147		)
Net assets (liabilities)(4)	$	30	$	391	$	(266	)	$	155		$	30	$	380	$	(143	)	$	267

⁽¹⁾  NUG and LCAPP contracts are subject to regulatory accounting treatment 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 June 30, 2012 and 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 and LCAPP contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:

	NUG Contracts(1)									LCAPP Contracts(1)
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net
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 Balance	$	4		$	(147	)	$	(143	)	$	—	$	—		$	—
Realized gain (loss)	—			—			—			—		—			—
Unrealized gain (loss)	—			(7		)	(7		)	—		—			—
Purchases	—			—			—			—		(145		)	(145		)
Issues	—			—			—			—		—			—
Sales	—			—			—			—		—			—
Settlements	—			29			29			—		—			—
Transfers in (out) of Level 3	—			—			—			—		—			—
June 30, 2012 Balance	$	4		$	(125	)	$	(121	)	$	—	$	(145	)	$	(145	)

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

Level 3 Quantitative Information

The following table provides quantitative information for NUG and LCAPP contracts held by JCP&L that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
NUG Contracts	$	(121	)	Model	Generation Electricity regional prices	63,000 to 715,000 $49.50 to $84.90	166,000 $65.80	MWH Dollars/MWH
LCAPP Contracts	$	(145	)	Model	Regional capacity prices	$94.90 to $248.40	$183.90	Dollars/MW-Day

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 June 30, 2012 and December 31, 2011:

	June 30, 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	$	2,032	$	52	$	—	$	2,084	$	1,980	$	25	25	$	—	—	$	2,005
FES	1,034		29		—		1,063		1,012		13			—			1,025
OE	138		—		—		138		134		—			—			134
JCP&L	358		12		—		370		356		7			—			363
Equity securities
FE Consolidated	$	243	$	36	$	—	$	279	$	222	$	36		$	—		$	258
FES	125		19		—		144		104		20			—			124
JCP&L	27		3		—		30		27		3			—			30

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $113 million; FES - $42 million; OE - $3 million; JCP&L - $23 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 and six months ended June 30, 2012 and 2011 were as follows:

Three Months Ended
June 30, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	131	$	17	$	(18	)	$	18
FES	25		13		(14		)	11
OE	20		—		—			1
JCP&L	70		1		(1		)	3
June 30, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	734	$	22	$	(16	)	$	28
FES	297		10		(7		)	17
OE	12		—		—			1
JCP&L	159		4		(2		)	4

Six Months Ended
June 30, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	382	$	37	$	(35	)	$	33
FES	109		26		(25		)	18
OE	57		—		—			1
JCP&L	165		2		(2		)	7
June 30, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	1,703	$	122	$	(45	)	$	52
FES	513		22		(23		)	32
OE	20		—		—			2
JCP&L	376		26		(6		)	8

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 June 30, 2012 and December 31, 2011:

	June 30, 2012						December 31, 2011
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FE Consolidated	$	326	$	55	$	381	$	402	$	50	$	452
OE	148		32		180		163		21		184

Investments in emission allowances, employee benefit trusts and cost and equity method investments totaling $716 million as of June 30, 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 in "Short-term borrowings" on the Consolidated Balance Sheets at cost, which approximates their fair market value. 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 June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FE Consolidated	$	16,571	$	18,998	$	17,165	$	19,320
FES	3,617		3,862		3,675		3,931
OE	1,157		1,493		1,157		1,434
JCP&L	1,762		2,076		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 June 30, 2012 and December 31, 2011.

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Fair Value Measurements (Details 2) (USD $) In Millions, unless otherwise specified																																					6 Months Ended
	Jun. 30, 2012 FTRs	Dec. 31, 2011 FTRs	Dec. 31, 2010 FTRs	Jun. 30, 2012 FTRs FES	Dec. 31, 2011 FTRs FES	Dec. 31, 2010 FTRs FES	Jun. 30, 2012 Non Utility Generation contract		Dec. 31, 2011 Non Utility Generation contract		Dec. 31, 2010 Non Utility Generation contract		Jun. 30, 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		Dec. 31, 2011 LCAPP Contracts		Dec. 31, 2010 LCAPP Contracts		Jun. 30, 2012 LCAPP Contracts JCP&L		Dec. 31, 2011 LCAPP Contracts JCP&L		Dec. 31, 2010 LCAPP Contracts JCP&L		Jun. 30, 2012 Model Level 3 FTRs	Jun. 30, 2012 Model Level 3 FTRs FES	Jun. 30, 2012 Model Level 3 Non Utility Generation contract		Jun. 30, 2012 Model Level 3 LCAPP Contracts		Jun. 30, 2012 Model Level 3 LCAPP Contracts JCP&L		Jun. 30, 2012 Model Level 3 Minimum FTRs	Jun. 30, 2012 Model Level 3 Minimum FTRs FES	Jun. 30, 2012 Model Level 3 Minimum Non Utility Generation contract MWh	Jun. 30, 2012 Model Level 3 Minimum Non Utility Generation contract JCP&L MWh	Jun. 30, 2012 Model Level 3 Minimum LCAPP Contracts	Jun. 30, 2012 Model Level 3 Minimum LCAPP Contracts JCP&L	Jun. 30, 2012 Model Level 3 Maximum FTRs	Jun. 30, 2012 Model Level 3 Maximum FTRs FES	Jun. 30, 2012 Model Level 3 Maximum Non Utility Generation contract MWh	Jun. 30, 2012 Model Level 3 Maximum Non Utility Generation contract JCP&L MWh	Jun. 30, 2012 Model Level 3 Maximum LCAPP Contracts	Jun. 30, 2012 Model Level 3 Maximum LCAPP Contracts JCP&L	Jun. 30, 2012 Model Level 3 Weighted Average [Member] FTRs	Jun. 30, 2012 Model Level 3 Weighted Average [Member] FTRs FES	Jun. 30, 2012 Model Level 3 Weighted Average [Member] Non Utility Generation contract MWh	Jun. 30, 2012 Model Level 3 Weighted Average [Member] Non Utility Generation contract JCP&L MWh	Jun. 30, 2012 Model Level 3 Weighted Average [Member] LCAPP Contracts	Jun. 30, 2012 Model Level 3 Weighted Average [Member] LCAPP Contracts JCP&L
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value	$ 3	$ (22)	$ 0	$ 2	$ (6)	$ 0	$ (293)	[1]	$ (292)	[1]	$ (344)	[1]	$ (121)	[1]	$ (143)	[1]	$ (227)	[1]	$ 0	[1]	$ 0	[1]	$ (145)	[1]	$ 0	[1]	$ 0	[1]	$ 3	$ 2	$ (293)	[1]	$ (145)	[1]	$ (145)	[1]
Fair Value Inputs, RTO Auction Clearing Prices																																					(3.60)	(3.6)					4.90	4.9					0.70	0.50
Fair Value Inputs, Generation																																							500	63,000					6,609,000	715,000					2,665,000	166,000
Fair Value Inputs, Power, Regional Prices																																							49.50	49.5	94.9	94.9			84.90	84.9	248.40	248.40			63.70	65.80	183.90	183.90

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

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Pensions and Other Postemployment Benefits (Details Textuals) (Qualified Pension Plan, USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012
Qualified Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Employer Contribution for qualified Plans	$ 600

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Commitments, Guarantees and Contingencies (Tables)

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations

The following chart discloses the additional credit contingent contractual obligations as ofJune 30, 2012:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	373	$	6	$	40	$	419
BB+/Ba1 Credit Ratings	$	429	$	6	$	59	$	494
Full impact of credit contingent contractual obligations	$	658	$	73	$	73	$	804

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Fair Value Measurements (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 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	$ 131	$ 734	$ 382	$ 1,703
Realized gains	17	22	37	122
Realized losses	(18)	(16)	(35)	(45)
Interest and dividend income	18	28	33	52
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	25	297	109	513
Realized gains	13	10	26	22
Realized losses	(14)	(7)	(25)	(23)
Interest and dividend income	11	17	18	32
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	20	12	57	20
Realized gains	0	0	0	0
Realized losses	0	0	0	0
Interest and dividend income	1	1	1	2
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	70	159	165	376
Realized gains	1	4	2	26
Realized losses	(1)	(2)	(2)	(6)
Interest and dividend income	$ 3	$ 4	$ 7	$ 8

XML

Supplemental Guarantor Information (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			$ 62	$ 1,031
New Financing-
Long-term debt			182	503
Short-term borrowings, net			1,890	0
Redemptions and Repayments-
Long-term debt			(746)	(1,002)
Short-term borrowings, net			0	(44)
Other			(35)	(76)
Net cash provided from (used for) financing activities			831	(1,039)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(412)	(569)	(1,001)	(1,018)
Sales of investment securities held in trusts			382	1,703
Purchases of investment securities held in trusts			(420)	(1,807)
Other			(49)	(53)
Net cash used for investing activities			(1,001)	(535)
Net change in cash and cash equivalents			(108)	(543)
Cash and cash equivalents at beginning of period			202	1,019
Cash and cash equivalents at end of period	94	476	94	476
FES Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			(525)	(329)
New Financing-
Long-term debt			0	0
Short-term borrowings, net			532	453
Redemptions and Repayments-
Long-term debt			0	(135)
Short-term borrowings, net			0
Other			(1)	(9)
Net cash provided from (used for) financing activities			531	309
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(5)	(6)
Proceeds from assets sale			0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Loans to affiliated companies, net			1	28
Other			(2)	(2)
Net cash used for investing activities			(6)	20
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	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			308	321
New Financing-
Long-term debt			52	140
Short-term borrowings, net			46	77
Redemptions and Repayments-
Long-term debt			(63)	(192)
Short-term borrowings, net			0
Other			(4)	(1)
Net cash provided from (used for) financing activities			31	24
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(44)	(109)
Proceeds from assets sale			17
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Loans to affiliated companies, net			(308)	(221)
Other			(4)	(18)
Net cash used for investing activities			(339)	(348)
Net change in cash and cash equivalents			0	(3)
Cash and cash equivalents at beginning of period			7	9
Cash and cash equivalents at end of period	7	6	7	6
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			446	200
New Financing-
Long-term debt			30	107
Short-term borrowings, net			0	0
Redemptions and Repayments-
Long-term debt			(87)	(155)
Short-term borrowings, net			(32)
Other			(1)	(1)
Net cash provided from (used for) financing activities			(90)	(49)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(254)	(219)
Proceeds from assets sale			0
Sales of investment securities held in trusts			109	513
Purchases of investment securities held in trusts			(127)	(545)
Loans to affiliated companies, net			(84)	100
Other			0	0
Net cash used for investing activities			(356)	(151)
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	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			(10)	(10)
New Financing-
Long-term debt			0	0
Short-term borrowings, net			(578)	0
Redemptions and Repayments-
Long-term debt			10	10
Short-term borrowings, net			32
Other				0
Net cash provided from (used for) financing activities			(536)	10
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			0	0
Proceeds from assets sale			0
Sales of investment securities held in trusts			0	0
Purchases of investment securities held in trusts			0	0
Loans to affiliated companies, net			546	0
Other			0	0
Net cash used for investing activities			546	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	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			219	182
New Financing-
Long-term debt			82	247
Short-term borrowings, net			0	530
Redemptions and Repayments-
Long-term debt			(140)	(472)
Short-term borrowings, net			0
Other			(6)	(11)
Net cash provided from (used for) financing activities			(64)	294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions			(303)	(334)
Proceeds from assets sale			17	0
Sales of investment securities held in trusts			109	513
Purchases of investment securities held in trusts			(127)	(545)
Loans to affiliated companies, net			155	(93)
Other			(6)	(20)
Net cash used for investing activities			(155)	(479)
Net change in cash and cash equivalents			0	(3)
Cash and cash equivalents at beginning of period			7	9
Cash and cash equivalents at end of period	$ 7	$ 6	$ 7	$ 6

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Derivative Instruments (Details Textuals) (USD $)	3 Months Ended		6 Months Ended
	Jun. 30, 2012 counterparty agreements	Jun. 30, 2011	Jun. 30, 2012 agreements	Jun. 30, 2011	Dec. 31, 2011
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 15,000,000		$ 15,000,000		$ 19,000,000
Reclassifications from AOCL into other operating expense	1,000,000	(14,000,000)	(4,000,000)	(19,000,000)
Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months			9,000,000
Forward starting swap agreements outstanding	0		0
Unamortized gains or losses associated with prior interest rate hedges	74,000,000		74,000,000
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	91,000,000		91,000,000
Net asset position under commodity derivative contracts	78,000,000		78,000,000
Expected adverse change in quoted market prices of derivative instruments	10.00%		10.00%
Decrease net income due to adverse change in commodity prices			2,000,000
Number of counterparties to interest rate derivatives executed in period	16
Notional amount of interest rate derivatives executed in period	1,600,000,000
Period In Which LSEs May Request Direct Allocation Of FTRs			2 years
JCP&L
Derivative [Line Items]
Number of LCAPP contracts	2		2
FES
Derivative [Line Items]
Collateral posted	34,000,000		34,000,000
Additional collateral related to commodity derivatives	12,000,000		12,000,000
Cash Flow Hedges
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months			9,000,000
Reclassifications from accumulated other comprehensive loss	2,000,000	3,000,000	5,000,000	6,000,000
Fair Value Hedging
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months			23,000,000
Number of Interest Rate Swap Agreements	0		0
Reclassifications from long-term debt	$ 6,000,000	$ 6,000,000	$ 11,000,000	$ 11,000,000
Interest rate swaps
Derivative [Line Items]
Average remaining maturity	10 years		10 years
Weighted average fixed interest rate	2.315%		2.315%

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Variable Interest Entities (Details Textuals) (USD $)	3 Months Ended		6 Months Ended				3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended				6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012 contracts	Jun. 30, 2012 entities	Jun. 30, 2011	Jun. 30, 2012 Power Purchase Agreements agreements	Jun. 30, 2012 JCP&L	Jun. 30, 2011 JCP&L	Jun. 30, 2012 JCP&L	Jun. 30, 2011 JCP&L contracts	Jun. 30, 2012 JCP&L Power Purchase Agreements	Jun. 30, 2011 JCP&L Power Purchase Agreements	Jun. 30, 2012 JCP&L Power Purchase Agreements	Jun. 30, 2011 JCP&L Power Purchase Agreements	Jun. 30, 2012 PE Power Purchase Agreements	Jun. 30, 2011 PE Power Purchase Agreements	Jun. 30, 2012 PE Power Purchase Agreements	Jun. 30, 2011 PE Power Purchase Agreements	Jun. 30, 2012 WP Power Purchase Agreements	Jun. 30, 2011 WP Power Purchase Agreements	Jun. 30, 2012 WP Power Purchase Agreements	Jun. 30, 2011 WP Power Purchase Agreements	Jun. 30, 2012 Signal Peak FEV	Oct. 18, 2011 Signal Peak FEV	Jun. 30, 2012 Variable Interest Entity, Not Primary Beneficiary	Jun. 30, 2012 PATH-WV	Jun. 30, 2012 PATH-WV Allegheny	Jun. 30, 2012 Oyster Creek Nuclear Generating Station
Variable Interest Entities (Textuals) [Abstract]
Bondable stranded costs																												$ 262,000,000
Environmental control bond	503,000,000		503,000,000	503,000,000
Income (loss) attributable to noncontrolling interest	1,000,000	(10,000,000)		1,000,000	(15,000,000)																				1,000,000
Distributions to owners																									5,000,000
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																											31,000,000
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities						21
Number of contracts that may contain variable interest			3	3						4
Purchased power	1,156,000,000	1,220,000,000		2,503,000,000	2,406,000,000		254,000,000	328,000,000	518,000,000	698,000,000	14,000,000	55,000,000	26,000,000	120,000,000	27,000,000	47,000,000	59,000,000	58,000,000	17,000,000	21,000,000	33,000,000	26,000,000
Reserve for adverse purchase power commitment																			48,000,000		48,000,000
Current liability included in adverse purchase power commitment																			11,000,000		11,000,000
Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments	$ 1,500,000,000		$ 1,500,000,000	$ 1,500,000,000

XML

Consolidated Balance Sheets (Unaudited) (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 202
Receivables-
Customers, net of allowance for uncollectible accounts	1,635	1,525
Other, net of allowance for uncollectible accounts	263	269
Materials and supplies	921	811
Derivatives	276	235
Prepayments and other	171	122
Total current assets	3,608	3,355
PROPERTY, PLANT AND EQUIPMENT:
In service	41,167	40,122
Less - Accumulated provision for depreciation	12,336	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,831	28,283
Construction work in progress	1,937	2,054
Total net property, plant and equipment	30,768	30,337
INVESTMENTS:
Nuclear plant decommissioning trusts	2,153	2,112
Other	1,039	1,008
Total other property and investments	3,518	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444	6,441
Other	1,588	1,641
Total deferred charges and other assets	10,154	10,112
Total assets	48,048	47,326
CURRENT LIABILITIES:
Currently payable long-term debt	1,577	1,621
Accounts payable-
Accrued taxes	436	558
Derivatives	222	218
Other	617	900
Total current liabilities	6,082	4,855
Common stockholders' equity-
Common stock	42	42
Accumulated other comprehensive income	389	426
Retained earnings (Accumulated deficit)	3,310	3,047
Total common stockholders' equity	13,497	13,280
Long-term debt and other long-term obligations	15,159	15,716
Total capitalization	28,671	29,015
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	909	925
Accumulated deferred income taxes	6,042	5,670
Asset retirement obligations	1,548	1,497
Retirement benefits	2,257	2,823
Other	1,980	2,072
Total noncurrent liabilities	13,295	13,456
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	48,048	47,326
FES
CURRENT ASSETS:
Cash and cash equivalents	7	7
Receivables-
Customers, net of allowance for uncollectible accounts	457	424
Affiliated companies	537	600
Other, net of allowance for uncollectible accounts	96	61
Notes receivable from affiliated companies	228	383
Materials and supplies	548	492
Derivatives	265	219
Prepayments and other	19	38
Total current assets	2,157	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	11,375	10,983
Less - Accumulated provision for depreciation	4,314	4,110
Property, plant and equipment in service net of accumulated provision for depreciation	7,061	6,873
Construction work in progress	919	1,014
Total net property, plant and equipment	7,980	7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	1,250	1,223
Other	7	7
Total other property and investments	1,257	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	118	123
Goodwill	24	24
Property taxes	43	43
Unamortized sale and leaseback costs	118	80
Derivatives	110	79
Other	137	129
Total deferred charges and other assets	550	478
Total assets	11,944	11,819
CURRENT LIABILITIES:
Currently payable long-term debt	1,144	905
Accounts payable-
Affiliated companies	608	436
Other	306	220
Accrued taxes	62	227
Derivatives	219	189
Other	242	261
Total current liabilities	2,581	2,238
Common stockholders' equity-
Common stock	1,568	1,570
Accumulated other comprehensive income	84	76
Retained earnings (Accumulated deficit)	2,052	1,931
Total common stockholders' equity	3,704	3,577
Long-term debt and other long-term obligations	2,500	2,799
Total capitalization	6,204	6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	909	925
Accumulated deferred income taxes	436	286
Asset retirement obligations	934	904
Retirement benefits	179	356
Lease market valuation liability	148	171
Other	553	563
Total noncurrent liabilities	3,159	3,205
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	$ 11,944	$ 11,819

XML

Regulatory Matters (Details) (USD $)	0 Months Ended	6 Months Ended	1 Months Ended	6 Months Ended			6 Months Ended				6 Months Ended	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended	30 Months Ended	36 Months Ended		6 Months Ended			6 Months Ended	12 Months Ended				1 Months Ended			1 Months Ended			6 Months Ended	3 Months Ended	6 Months Ended											6 Months Ended			6 Months Ended
	Dec. 09, 2008	Jun. 30, 2012 entities	Apr. 30, 2007 FERC kv	Jun. 30, 2012 FERC	Jan. 21, 2010 FERC issues	Jun. 30, 2012 FERC PJM	Jun. 30, 2012 FERC PATH kv	Dec. 28, 2011 FERC PJM Calculation Error	Dec. 28, 2011 FERC PJM Calculation Error FES	Dec. 28, 2011 FERC PJM Calculation Error AE Supply	Jun. 30, 2012 The Seneca Pumped Storage Project Relicensing	Aug. 31, 2011 OHIO proposals	Oct. 31, 2009 OHIO proposals	Jun. 30, 2012 OHIO	Dec. 31, 2009 OHIO	Jun. 30, 2012 OHIO	Dec. 31, 2011 OHIO	Dec. 31, 2010 OHIO	Jun. 30, 2012 MARYLAND	Aug. 31, 2011 MARYLAND	Oct. 06, 2009 MARYLAND	Jun. 30, 2012 PENNSYLVANIA smart_meter	Dec. 31, 2010 PENNSYLVANIA	Jun. 30, 2011 PENNSYLVANIA Party	May 31, 2011 PENNSYLVANIA	Apr. 29, 2011 PENNSYLVANIA questions	Apr. 30, 2010 WEST VIRGINIA	Feb. 28, 2011 WEST VIRGINIA Facilities	Jan. 31, 2011 WEST VIRGINIA Facilities	Feb. 28, 2011 WEST VIRGINIA City of New Martinsville entities	Feb. 28, 2011 WEST VIRGINIA Morgantown Energy entities	Oct. 31, 2006 California Claims Matters FERC Proceedings	Jun. 30, 2012 California Claims Matters FERC	Jun. 30, 2012 Yards Creek Pumped Storage Project FERC MW	Jun. 30, 2012 Yards Creek Pumped Storage Project FERC JCP&L	Jun. 30, 2012 The Seneca Pumped Storage Project FERC MW	Jun. 30, 2012 Year 2014 [Member] OHIO GWh	Jun. 30, 2012 Annually Through 2025 [Member] OHIO GWh	Jun. 30, 2012 Annually Through 2018 [Member] OHIO	Jun. 30, 2012 Year 2012 OHIO GWh MWh	Jun. 30, 2012 Year 2013 OHIO GWh	Jun. 30, 2012 Year 2013 PENNSYLVANIA	Jun. 30, 2012 Delivery Year 2011-2012 [Member] FERC PJM Calculation Error	Jun. 30, 2012 Delivery Year 2011-2012 [Member] FERC PJM Calculation Error FES	Jun. 30, 2012 Delivery Year 2011-2012 [Member] FERC PJM Calculation Error AE Supply	Jun. 30, 2012 Supporting Application OHIO Party	Jun. 30, 2012 Not Opposing Application OHIO Party	Jul. 13, 2012 Plant Deactivation WEST VIRGINIA plant	Jun. 30, 2012 FTR Allocation Complaint FERC PJM
Regulatory Matters [Line Items]
Proposed electric consumption reduction percentage																			10.00%
Proposed electric demand reduction percentage																			15.00%
Expenditures for cost recovery program																				$ 66,000,000	$ 101,000,000
Maximum penalty assessed, in dollars per day per violation																			25,000
Recovery period for expenditures for cost recovery program																				3 years	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	7
ESP extension term														2 years
Generation supply auction period, after approval														3 years
Generation supply auction period, before approval														1 year
Annual energy savings																																					2,306	2,903		1,211	1,726
Increase (decrease) in annual energy savings																																								416,000
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
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
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
Compliance Filing, Period																																																	60 days
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
Number of approved plant deactivations																																																3
Power threshold for cost methodology			500
Identified issues for written comments					9
Hybrid methodology, postage stamp cost allocation						50.00%
Hybrid methodology, beneficiary pays cost allocation						50.00%
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								35,000,000	500,000	34,500,000																																	11,500,000	11,400,000	100,000
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	11 hours

XML

Pensions and Other Postemployment Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pensions
Components of Net Periodic Benefit Costs (Credits)
Service cost	$ 40	$ 34	$ 80	$ 63
Interest cost	97	96	194	180
Expected return on plan assets	(121)	(115)	(242)	(217)
Amortization of prior service cost	3	4	6	8
Other adjustments (settlements, curtailments, etc)	0	0	0	7
Net periodic cost (credit)	19	19	38	41
OPEB
Components of Net Periodic Benefit Costs (Credits)
Service cost	3	3	6	6
Interest cost	12	12	24	23
Expected return on plan assets	(9)	(10)	(18)	(20)
Amortization of prior service cost	(51)	(51)	(102)	(99)
Other adjustments (settlements, curtailments, etc)	0	0	0	0
Net periodic cost (credit)	$ (45)	$ (46)	$ (90)	$ (90)

XML

Supplemental Guarantor Information

6 Months Ended

Jun. 30, 2012

Supplemental Guarantor Information [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

SUPPLEMENTAL GUARANTOR INFORMATION

In 2007, FGCO completed a sale and leaseback transaction for its 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 and six months ended June 30, 2012 and 2011, Consolidating Balance Sheets as of June 30, 2012 and December 31, 2011, and Consolidating Statements of Cash Flows for the six months ended June 30, 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 June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,430		$	636		$	473		$	(1,083	)	$	1,456
OPERATING EXPENSES:
Fuel	—			336			44			—			380
Purchased power from affiliates	1,156			—			60			(1,083		)	133
Purchased power from non-affiliates	434			—			—			—			434
Other operating expenses	107			100			172			14			393
Provision for depreciation	1			30			39			(1		)	69
General taxes	20			8			4			—			32
Total operating expenses	1,718			474			319			(1,070		)	1,441
OPERATING INCOME (LOSS)	(288		)	162			154			(13		)	15
OTHER INCOME (EXPENSE):
Investment income	—			5			7			(6		)	6
Miscellaneous income, including net income from equity investees	279			19			—			(278		)	20
Interest expense — affiliates	(5		)	(2		)	(1		)	6			(2		)
Interest expense — other	(24		)	(26		)	(14		)	16			(48		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	250			(3		)	—			(262		)	(15		)
INCOME (LOSS) BEFORE INCOME TAXES	(38		)	159			154			(275		)	—
INCOME TAXES (BENEFITS)	(37		)	(7		)	42			3			1
NET INCOME (LOSS)	$	(1	)	$	166		$	112		$	(278	)	$	(1	)
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	$	(1	)	$	166		$	112		$	(278	)	$	(1	)
OTHER COMPREHENSIVE INCOME:
Pensions and OPEB prior service costs	8			7			—			(7		)	8
Amortized gain on derivative hedges	1			—			—			—			1
Change in unrealized gain on available for sale securities	3			—			3			(3		)	3
Other comprehensive income	12			7			3			(10		)	12
Income taxes on other comprehensive income	2			3			1			(4		)	2
Other comprehensive income, net of tax	10			4			2			(6		)	10
COMPREHENSIVE INCOME	$	9		$	170		$	114		$	(284	)	$	9

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Six Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	2,920		$	1,178		$	867		$	(1,993	)	$	2,972
OPERATING EXPENSES:
Fuel	—			576			99			—			675
Purchased power from affiliates	2,121			—			122			(1,993		)	250
Purchased power from non-affiliates	921			—			—			—			921
Other operating expenses	183			192			288			25			688
Provision for depreciation	2			60			73			(3		)	132
General taxes	40			18			11			—			69
Total operating expenses	3,267			846			593			(1,971		)	2,735
OPERATING INCOME (LOSS)	(347		)	332			274			(22		)	237
OTHER INCOME (EXPENSE):
Investment income	1			9			12			(10		)	12
Miscellaneous income, including net income from equity investees	537			19			—			(532		)	24
Interest expense — affiliates	(9		)	(3		)	(2		)	10			(4		)
Interest expense — other	(47		)	(52		)	(21		)	31			(89		)
Capitalized interest	—			2			16			—			18
Total other income (expense)	482			(25		)	5			(501		)	(39		)
INCOME BEFORE INCOME TAXES	135			307			279			(523		)	198
INCOME TAXES (BENEFITS)	14			(8		)	65			6			77
NET INCOME	$	121		$	315		$	214		$	(529	)	$	121
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	121		$	315		$	214		$	(529	)	$	121
OTHER COMPREHENSIVE INCOME
Pensions and OPEB prior service costs	3			3			—			(3		)	3
Amortized loss on derivative hedges	(4		)	—			—			—			(4		)
Change in unrealized gain on available for sale securities	13			—			13			(13		)	13
Other comprehensive income	12			3			13			(16		)	12
Income taxes on other comprehensive income	4			1			5			(6		)	4
Other comprehensive income, net of tax	8			2			8			(10		)	8
COMPREHENSIVE INCOME	$	129		$	317		$	222		$	(539	)	$	129

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,275		$	535		$	393		$	(911	)	$	1,292
OPERATING EXPENSES:
Fuel	6			266			44			—			316
Purchased power from affiliates	902			9			65			(911		)	65
Purchased power from non-affiliates	332			(3		)	—			—			329
Other operating expenses	159			108			134			12			413
Provision for depreciation	1			32			37			(1		)	69
General taxes	16			8			6			—			30
Impairment of long-lived assets	—			7			—			—			7
Total operating expenses	1,416			427			286			(900		)	1,229
OPERATING INCOME (LOSS)	(141		)	108			107			(11		)	63
OTHER INCOME (EXPENSE):
Investment income	—			1			15			—			16
Miscellaneous income, including net income from equity investees	132			1			—			(129		)	4
Interest expense — affiliates	—			(1		)	(1		)	—			(2		)
Interest expense — other	(24		)	(28		)	(16		)	16			(52		)
Capitalized interest	—			5			5			—			10
Total other income (expense)	108			(22		)	3			(113		)	(24		)
INCOME (LOSS) BEFORE INCOME TAXES	(33		)	86			110			(124		)	39
INCOME TAXES (BENEFITS)	(62		)	28			41			3			10
NET INCOME	$	29		$	58		$	69		$	(127	)	$	29
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	29		$	58		$	69		$	(127	)	$	29
OTHER COMPREHENSIVE INCOME (LOSS)
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	14			—			—			—			14
Change in unrealized gain on available for sale securities	8			—			8			(8		)	8
Other comprehensive income (loss)	17			(4		)	8			(4		)	17
Income taxes (benefits) on other comprehensive income (loss)	8			(2		)	3			(1		)	8
Other comprehensive income (loss), net of tax	9			(2		)	5			(3		)	9
COMPREHENSIVE INCOME	$	38		$	56		$	74		$	(130	)	$	38

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	2,642		$	1,278		$	862		$	(2,098	)	$	2,684
OPERATING EXPENSES:
Fuel	7			560			92			—			659
Purchased power from affiliates	2,087			11			134			(2,098		)	134
Purchased power from non-affiliates	629			(3		)	—			—			626
Other operating expenses	321			219			313			25			878
Provision for depreciation	2			63			76			(3		)	138
General taxes	27			19			14			—			60
Impairment of long-lived assets	—			20			—			—			20
Total operating expenses	3,073			889			629			(2,076		)	2,515
OPERATING INCOME (LOSS)	(431		)	389			233			(22		)	169
OTHER INCOME (EXPENSE):
Investment income	1			1			20			—			22
Miscellaneous income, including net income from equity investees	374			2			—			(368		)	8
Interest expense — affiliates	(1		)	(1		)	(1		)	—			(3		)
Interest expense — other	(48		)	(56		)	(33		)	32			(105		)
Capitalized interest	—			10			10			—			20
Total other income (expense)	326			(44		)	(4		)	(336		)	(58		)
INCOME (LOSS) BEFORE INCOME TAXES	(105		)	345			229			(358		)	111
INCOME TAXES (BENEFITS)	(179		)	125			86			5			37
NET INCOME	$	74		$	220		$	143		$	(363	)	$	74
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	74		$	220		$	143		$	(363	)	$	74
OTHER COMPREHENSIVE INCOME (LOSS)
Pensions and OPEB prior service costs	(9		)	(8		)	—			8			(9		)
Amortized gain on derivative hedges	5			—			—			—			5
Change in unrealized gain on available for sale securities	15			—			15			(15		)	15
Other comprehensive income (loss)	11			(8		)	15			(7		)	11
Income taxes (benefits) on other comprehensive income (loss)	4			(4		)	6			(2		)	4
Other comprehensive income (loss), net of tax	7			(4		)	9			(5		)	7
COMPREHENSIVE INCOME	$	81		$	216		$	152		$	(368	)	$	81

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of June 30, 2012	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	457		—		—		—			457
Affiliated companies	464		482		297		(706		)	537
Other	67		25		4		—			96
Notes receivable from affiliated companies	155		1,653		152		(1,732		)	228
Materials and supplies, at average cost	68		272		208		—			548
Derivatives	265		—		—		—			265
Prepayments and other	3		15		1		—			19
	1,479		2,454		662		(2,438		)	2,157
PROPERTY, PLANT AND EQUIPMENT:
In service	89		5,620		6,051		(385		)	11,375
Less — Accumulated provision for depreciation	30		1,872		2,594		(182		)	4,314
	59		3,748		3,457		(203		)	7,061
Construction work in progress	28		187		704		—			919
	87		3,935		4,161		(203		)	7,980
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,250		—			1,250
Investment in affiliated companies	6,241		—		—		(6,241		)	—
Other	—		7		—		—			7
	6,241		7		1,250		(6,241		)	1,257
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		261		—		(261		)	—
Customer intangibles	118				—		—			118
Goodwill	24				—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		4		—		114			118
Derivatives	110				—		—			110
Other	86		160		1		(110		)	137
	338		445		24		(257		)	550
	$	8,145	$	6,841	$	6,097	$	(9,139	)	$	11,944
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	646	$	518	$	(21	)	$	1,144
Short-term borrowings-
Affiliated companies	1,597		135		—		(1,732		)	—
Accounts payable-
Affiliated companies	739		279		305		(715		)	608
Other	173		133		—		—			306
Accrued taxes	23		20		27		(8		)	62
Derivatives	219		—		—		—			219
Other	68		124		13		37			242
	2,820		1,337		863		(2,439		)	2,581
CAPITALIZATION:
Total equity	3,704		3,413		2,810		(6,223		)	3,704
Long-term debt and other long-term obligations	1,482		1,657		580		(1,219		)	2,500
	5,186		5,070		3,390		(7,442		)	6,204
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		909			909
Accumulated deferred income taxes	28		—		572		(164		)	436
Asset retirement obligations	—		29		905		—			934
Retirement benefits	34		145		—		—			179
Lease market valuation liability	—		148		—		—			148
Other	77		112		367		(3		)	553
	139		434		1,844		742			3,159
	$	8,145	$	6,841	$	6,097	$	(9,139	)	$	11,944

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	5,700		—		—		(5,700		)	—
Other	—		7		—		—			7
	5,700		7		1,223		(5,700		)	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
	$	7,483	$	6,667	$	5,846	$	(8,177	)	$	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:
Total equity	3,577		3,097		2,587		(5,684		)	3,577
Long-term debt and other long-term obligations	1,483		1,905		641		(1,230		)	2,799
	5,060		5,002		3,228		(6,914		)	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
	$	7,483	$	6,667	$	5,846	$	(8,177	)	$	11,819

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Six Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(525	)	$	308		$	446		$	(10	)	$	219
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			52			30			—			82
Short-term borrowings, net	532			46			—			(578		)	—
Redemptions and Repayments-
Long-term debt	—			(63		)	(87		)	10			(140		)
Short-term borrowings, net	—			—			(32		)	32			—
Other	(1		)	(4		)	(1		)	—			(6		)
Net cash provided from (used for) financing activities	531			31			(90		)	(536		)	(64		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(44		)	(254		)	—			(303		)
Proceeds from assets sale	—			17			—			—			17
Sales of investment securities held in trusts	—			—			109			—			109
Purchases of investment securities held in trusts	—			—			(127		)	—			(127		)
Loans to affiliated companies, net	1			(308		)	(84		)	546			155
Other	(2		)	(4		)	—			—			(6		)
Net cash provided from (used for) investing activities	(6		)	(339		)	(356		)	546			(155		)
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 Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(329	)	$	321		$	200		$	(10	)	$	182
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			140			107			—			247
Short-term borrowings, net	453			77			—			—			530
Redemptions and Repayments-
Long-term debt	(135		)	(192		)	(155		)	10			(472		)
Other	(9		)	(1		)	(1		)	—			(11		)
Net cash used for financing activities	309			24			(49		)	10			294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(6		)	(109		)	(219		)	—			(334		)
Sales of investment securities held in trusts	—			—			513			—			513
Purchases of investment securities held in trusts	—			—			(545		)	—			(545		)
Loans to affiliated companies, net	28			(221		)	100			—			(93		)
Other	(2		)	(18		)	—			—			(20		)
Net cash provided from (used for) investing activities	20			(348		)	(151		)	—			(479		)
Net change in cash and cash equivalents	—			(3		)	—			—			(3		)
Cash and cash equivalents at beginning of period	—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	6		$	—		$	—		$	6

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Commitments, Guarantees and Contingencies

6 Months Ended

Jun. 30, 2012

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party.

As of June 30, 2012, outstanding guarantees and other assurances aggregated approximately $4.1 billion, consisting of parental guarantees ($0.9 billion), subsidiaries' guarantees ($2.4 billion) and other guarantees ($0.7 billion).

Of this amount, substantially all relates to guarantees of wholly-owned consolidated entities. 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.

COLLATERAL AND CONTINGENT-RELATED FEATURES

As part of the normal course of business, FirstEnergy and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuels, and emissions allowances. Certain bilateral agreements and derivative instruments contain provisions that require FirstEnergy or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FirstEnergy's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements.

Bilateral agreements and derivative instruments entered into by FirstEnergy and its subsidiaries have margining provisions that require posting of collateral.Based on FES' and AE Supply's power portfolio exposure as ofJune 30, 2012, FES has posted collateral of$36 million. The Regulated Distribution segment has posted collateral of$9 million.

These credit-risk-related contingent features stipulate that if the subsidiaries were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining could be required.

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 FirstEnergy or its subsidiaries.The following chart discloses the additional credit contingent contractual obligations as ofJune 30, 2012:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	373	$	6	$	40	$	419
BB+/Ba1 Credit Ratings	$	429	$	6	$	59	$	494
Full impact of credit contingent contractual obligations	$	658	$	73	$	73	$	804

Excluded from the preceding chart are the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Segment.As ofJune 30, 2012neither 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$46 millionand$13 million, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

Signal Peak and Global Rail are borrowers under a$350 millionsyndicated 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, continued to guarantee the borrowers' obligations under the current facility. 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.Global Holding is involved in negotiations to refinance the current facility with a bank facility under which it would be the borrower. In connection with such proposed refinancing, FirstEnergy expects to provide the new lenders with a guarantee of Global Holding's obligations, and FirstEnergy and WMB Marketing Ventures, LLC expect to pledge not less than two-thirds of the equity interests in Global Holding and its subsidiaries.

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.On July 27, 2012, FirstEnergy filed a motion for summary judgment arguing the Plaintiff's remaining claims for civil penalties are barred by the statute of limitations. 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. On June 29, 2012, EPA issued another CAA section 114 request for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007. 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 June 12, 2012, the EPA revised certain CSAPR 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 deactivation 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.MATS has been challenged in the U.S. Court of Appeals for the District of Columbia Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1. FirstEnergy and other entities have also petitioned EPA to reconsider and revise various regulatory requirements under MATS.Depending on the outcome of these proceedings and how the MATS are ultimately implemented, FirstEnergy's future cost of compliance with MATS is estimated to be$975 millionand 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 system832megawatts of new combustion turbine peaking generation at its existing Eastlake Plant in Eastlake, Ohio, to help ensure reliable electric service in the region. However, when these units did not clear the May PJM capacity auction, the decision was made to not proceed with the project at this time. On April 25, 2012, PJM concluded its initial analysis of the reliability impacts from our previously announced plant deactivations and requested RMR arrangements for Eastlake 1-3, Ashtabula 5 and Lake Shore 18.On July 10, 2012, FirstEnergy filed with FERC, for informational purposes, the compensation arrangements for these units which will remain in effect for as long as these generating units continue to operate. On July 16, 2012, FGCO and ATSI filed an application with FERC for authorization to transfer from FGCO to ATSI certain assets associated with Eastlake Units 1-5 and Lakeshore Unit 18 for conversion to synchronous condensers by ATSI for transmission reliability purposes as directed by PJM. Upon FERC approval, it is expected that the assets will be transferred in staggered closings when the units are no longer needed for RMR purposes. During the three months and six months ended June 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately$10 million($6 million by FES) and $17 million ($10 million by FES), respectively, as a result of the deactivations. These costs are included in "other operating expenses" in the Consolidated Statements of Income.

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 deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates 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, South 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 U.S. 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. In July 2012, the period for finalizing the Section 316(b) regulation was extendedto July 27, 2013.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 June 5, 2012, FirstEnergy executed a tolling agreement with the EPA extending the statute of limitations for civil liability claims for those petroleum spills toJanuary 31, 2013. 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 proposed settlement, in the form of a Consent Decree, was lodged with the Commonwealth Court of Pennsylvania and published in the June 23, 2012, Pennsylvania Bulletin for a 30-day public comment period. 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 setting deadlines for MP to meet certain of the effluent limits that were 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. In June 2011, the West Virginia Highlands Conservancy, the West Virginia Rivers Coalition, and the Sierra Club served a 60-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. 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 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.

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.On July 27, 2012, the PA DEP filed a complaint against FGCO in the U.S. District Court for the Western District of Pennsylvania with claims under the Resource Conservation and Recovery Act and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FGCO to resolve those claims. The Consent Decree will be published to allow for a 30-day public comment period and requires FGCO to conduct monitoring, studies and submit a closure plan to the PA DEP, no later than March 31, 2013, and discontinue disposal to LBR as currently permitted by December 31, 2016. The Consent Decree also requires payment of civil penalties of $800,000 to resolve claims under the Solid Waste Management Act. BMP is pursuing several options for disposal of CCB following December 31, 2016.

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 ofJune 30, 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$122 million(including$86 millionapplicable to JCP&L) have been accrued throughJune 30, 2012. Included in the total are accrued liabilities of approximately$79 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 ofJune 30, 2012, FirstEnergy had approximately$2 billioninvested 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 intervenors supplemented their petition for a contention on the shield building on multiple occasions. On July 9, 2012, the intervenors petitioned the ASLB for a new contention on the environmental impacts of temporary spent fuel storage at Davis-Besse due to the lack of a repository and the disposal of these wastes. The ASLB has yet to rule on the admission of these latest requests for new contentions.

Similarly, on June 18 and 19, 2012, the intervenors in the Davis-Besse license renewal proceeding and other petitioners requested that the NRC suspends the issuance of final decisions in all pending reactor licensing proceedings as a result of the decision in the case of State of New York v. NRC, No. 11-1045. (D.C. Cir. June 8, 2012). In this case, the D.C. Circuit vacated the NRC's updated Waste Confidence Decision and its Temporary Storage Rule and remanded those rulemakings to the NRC for further consideration. FENOC and other Licensees opposed the suspension request. By order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the D.C. Circuit decision and all pending contentions on this topic should be held in abeyance until further order. The NRC also directed that all licensing reviews and proceedings should continue to move forward.

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.On June 21, 2012, the NRC issued an Inspection Report that concluded that FENOC established a sufficient basis for the causes of the shield building laminar cracking.

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. Additional adverse findings by the NRC could result in further inspection activities.

On March 12, 2012, the NRC 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 has concluded and an oral argument was held on May 16, 2012. A decision from the Appellate court is expected in the fourth quarter of 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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Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Fair value of commodity derivatives
Economic Hedges Derivative assets	$ 366	$ 321
Economic Hedges Derivative liabilities	(742)	(619)
Power Contracts | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	232	185
Power Contracts | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(213)	(196)
Power Contracts | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	106	79
Power Contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(49)	(51)
FTRs | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	12	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(8)	(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	(1)	(1)
NUGs
Fair value of commodity derivatives
Economic Hedges Derivative assets	9	56
Economic Hedges Derivative liabilities	(302)	(349)
LCAPP
Fair value of commodity derivatives
Economic Hedges Derivative assets	0	0
Economic Hedges Derivative liabilities	(145)	0
Interest rate swaps | Noncurrent Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	3	0
Interest rate swaps | Noncurrent Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	(23)	0
Other | Current Assets
Fair value of commodity derivatives
Economic Hedges Derivative assets	4	0
Other | Current Liabilities
Fair value of commodity derivatives
Economic Hedges Derivative liabilities	$ (1)	$ 0

XML

Pensions and Other Postemployment Benefits (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Pensions
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	$ 14	$ 14	$ 27	$ 34
Pensions | FES
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	11	7	21	14
Pensions | OE
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(1)	(2)	(2)	(4)
Pensions | JCP&L
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(2)	(3)	(3)	(5)
OPEB
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(32)	(34)	(62)	(66)
OPEB | FES
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(8)	(9)	(16)	(16)
OPEB | OE
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	(6)	(5)	(11)	(11)
OPEB | JCP&L
Net Periodic Pension and OPEB Costs (Credits)
Net periodic benefit costs (credits)	$ (2)	$ (2)	$ (4)	$ (5)

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Segment Information

6 Months Ended

Jun. 30, 2012

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

During the second quarter of 2012, FirstEnergy successfully completed the integration of AE into its IT business networks and financial systems. An important element of this system integration was the capability to modify the segment reporting to reflect how management now views and makes investment decisions regarding the distribution and transmission operations of FirstEnergy. The external segment reporting is now consistent with the internal financial reports used by FirstEnergy's chief executive officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources. Disclosures for FirstEnergy's operating segments for 2011 have been reclassified to conform to the current presentation.

The key changes in FirstEnergy's reportable segments during the second quarter of 2012 consisted principally of including the federally-regulated transmission assets and operations of JCP&L, ME, PN, MP, PE and WP, that were previously reported within the Regulated Distribution segment, with the renamed Regulated Transmission Segment. There were no changes to the Competitive Energy Services or Other / Corporate Segments. FirstEnergy continues to havethreereportable operating segments — Regulated Distribution, Regulated 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’stenutility operating companies, serving approximatelysix millioncustomers within65,000square 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 regulated electric generation facilities in West Virginia and New Jersey that 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 Transmission segment, previously known in part as the Regulated Independent Transmission Segment, transmits electricity through transmission lines owned and operated by certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and independent transmission companies (ATSI, TrAIL and PATH). Its revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Revenues are also derived from providing transmission services to electric energy providers, power marketers and revenue from operating 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 approximately17,000MWs of capacity, excluding approximately2,700MWs from unregulated plants expected to be deactivated, (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.

The Other / Corporate Segment 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		Regulated Transmission		Competitive Energy Services		Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
June 30, 2012
External revenues	$	2,095	$	184	$	1,616	$	(24	)	$	(2	)	$	3,869
Internal revenues	—		—		209		—			(209		)	—
Total revenues	2,095		184		1,825		(24		)	(211		)	3,869
Depreciation and amortization	215		29		103		8			(1		)	354
Investment income	19		—		6		1			(13		)	13
Net interest charges	132		22		59		42			—			255
Income taxes	94		31		14		(25		)	13			127
Net income	161		52		25		(42		)	(8		)	188
Total assets	25,787		4,473		17,216		572			—			48,048
Total goodwill	5,025		526		893		—			—			6,444
Property additions	177		59		150		26			—			412
June 30, 2011
External revenues	$	2,409	$	182	$	1,495	$	(30	)	$	(8	)	$	4,048
Internal revenues	—		—		318		—			(306		)	12
Total revenues	2,409		182		1,813		(30		)	(314		)	4,060
Depreciation and amortization	232		28		109		8			—			377
Investment income	25		—		16		—			(10		)	31
Net interest charges	134		24		69		19			(1		)	245
Income taxes	100		33		12		(30		)	(1		)	114
Net income	171		57		21		(51		)	(5		)	193
Total assets	25,069		4,202		17,146		1,179			—			47,596
Total goodwill	5,025		526		885		—			—			6,436
Property additions	266		81		197		25			—			569
Six Months Ended
June 30, 2012
External revenues	$	4,420	$	370	$	3,222	$	(47	)	$	(20	)	$	7,945
Internal revenues	—		—		477		—			(475		)	2
Total revenues	4,420		370		3,699		(47		)	(495		)	7,947
Depreciation and amortization	435		61		203		16			(1		)	714
Investment income	42		1		12		1			(32		)	24
Net interest charges	264		45		113		63			(1		)	484
Income taxes	187		66		97		(41		)	40			349
Net income	318		112		166		(69		)	(33		)	494
Total assets	25,787		4,473		17,216		572			—			48,048
Total goodwill	5,025		526		893		—			—			6,444
Property additions	443		122		393		43			—			1,001
June 30, 2011
External revenues	$	4,632	$	295	$	2,736	$	(53	)	$	(18	)	$	7,592
Internal revenues	—		—		661		—			(617		)	44
Total revenues	4,632		295		3,397		(53		)	(635		)	7,636
Depreciation and amortization	473		50		197		14			—			734
Investment income	48		—		21		1			(18		)	52
Net interest charges	256		41		122		39			—			458
Income taxes	158		47		21		(30		)	29			225
Net income	267		80		36		(105		)	(38		)	240
Total assets	25,069		4,202		17,146		1,179			—			47,596
Total goodwill	5,025		526		885		—			—			6,436
Property additions	381		170		411		56			—			1,018

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Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2012

Significant Accounting Policies [Abstract]

Earnings Per Share, Policy

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

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

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

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Consolidated Statements of Income and Comprehensive Income (Unaudited) (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
REVENUES:
Electric sales	$ 1,590	$ 1,470	$ 3,157	$ 2,711
Total revenues	2,279	2,590	4,790	4,925
OPERATING EXPENSES:
Fuel	656	635	1,197	1,088
Purchased power	1,156	1,220	2,503	2,406
Other operating expenses	914	1,065	1,726	2,058
Provision for depreciation	292	287	577	512
General taxes	232	242	504	479
Total operating expenses	3,312	3,539	6,644	6,765
OPERATING INCOME (LOSS)	557	521	1,303	871
OTHER INCOME (EXPENSE):
Investment income	13	31	24	52
Interest expense	(274)	(265)	(520)	(496)
Capitalized interest	19	20	36	38
Total other income (expense)	(242)	(214)	(460)	(406)
INCOME BEFORE INCOME TAXES	315	307	843	465
INCOME TAXES (BENEFITS)	127	114	349	225
NET INCOME	188	193	494	240
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	188	193	494	240
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(48)	48	(101)	4
Amortized gain (loss) on derivative hedges	3	17	1	11
Change in unrealized gain on available-for-sale securities	2	10	12	19
Other comprehensive income (loss)	(43)	75	(88)	34
Income taxes (benefits) on other comprehensive income (loss)	(27)	33	(51)	14
Other comprehensive income (loss), net of tax	(16)	42	(37)	20
COMPREHENSIVE INCOME	172	235	457	260
FES
REVENUES:
Other	54	70	117	156
Total revenues	1,456	1,292	2,972	2,684
OPERATING EXPENSES:
Fuel	380	316	675	659
Other operating expenses	393	413	688	878
Provision for depreciation	69	69	132	138
General taxes	32	30	69	60
Impairment of long-lived assets	0	7	0	20
Total operating expenses	1,441	1,229	2,735	2,515
OPERATING INCOME (LOSS)	15	63	237	169
OTHER INCOME (EXPENSE):
Investment income	6	16	12	22
Miscellaneous income	20	4	24	8
Capitalized interest	9	10	18	20
Total other income (expense)	(15)	(24)	(39)	(58)
INCOME BEFORE INCOME TAXES	0	39	198	111
INCOME TAXES (BENEFITS)	1	10	77	37
NET INCOME	(1)	29	121	74
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	(1)	29	121	74
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	8	(5)	3	(9)
Amortized gain (loss) on derivative hedges	1	14	(4)	5
Change in unrealized gain on available-for-sale securities	3	8	13	15
Other comprehensive income (loss)	12	17	12	11
Income taxes (benefits) on other comprehensive income (loss)	2	8	4	4
Other comprehensive income (loss), net of tax	10	9	8	7
COMPREHENSIVE INCOME	9	38	129	81
FES | Affiliates
REVENUES:
Electric sales	109	170	230	431
OPERATING EXPENSES:
Purchased power	133	65	250	134
OTHER INCOME (EXPENSE):
Interest expense	(2)	(2)	(4)	(3)
FES | Non-Affiliates
REVENUES:
Electric sales	1,293	1,052	2,625	2,097
OPERATING EXPENSES:
Purchased power	434	329	921	626
OTHER INCOME (EXPENSE):
Interest expense	$ (48)	$ (52)	$ (89)	$ (105)

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Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 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 June 30				Six Months Ended June 30
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2012		2011		2012		2011
	(In millions, except per share amounts)
Weighted average number of basic shares outstanding	417		418		418		380
Assumed exercise of dilutive stock options and awards(1)	2		2		1		2
Weighted average number of diluted shares outstanding	419		420		419		382
Earnings Available to FirstEnergy Corp.	$	187	$	203	$	493	$	255
Basic earnings per share of common stock	$	0.45	$	0.48	$	1.18	$	0.67
Diluted earnings per share of common stock	$	0.45	$	0.48	$	1.18	$	0.67

⁽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 and six months ended June 30, 2012 and 2011.

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Organization and Basis of Presentation (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended
	Dec. 31, 2011	Jun. 30, 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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Fair Value Measurements (Details 5) (Debt Securities, USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 326	$ 402
Unrealized Gains	55	50
Fair Value	381	452
OE
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	148	163
Unrealized Gains	32	21
Fair Value	$ 180	$ 184

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Consolidated Statements of Income (Unaudited) (FirstEnergy Corp.) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
REVENUES:
Electric utilities	$ 2,279		$ 2,590		$ 4,790		$ 4,925
Unregulated businesses	1,590		1,470		3,157		2,711
Total revenues	3,869	[1]	4,060	[1]	7,947	[1]	7,636	[1]
OPERATING EXPENSES:
Fuel	656		635		1,197		1,088
Purchased power	1,156		1,220		2,503		2,406
Other operating expenses	914		1,065		1,726		2,058
Provision for depreciation	292		287		577		512
Amortization of regulatory assets, net	62		90		137		222
General taxes	232		242		504		479
Total operating expenses	3,312		3,539		6,644		6,765
OPERATING INCOME (LOSS)	557		521		1,303		871
OTHER INCOME (EXPENSE):
Investment income	13		31		24		52
Interest expense	(274)		(265)		(520)		(496)
Capitalized interest	19		20		36		38
Total other income (expense)	(242)		(214)		(460)		(406)
INCOME BEFORE INCOME TAXES	315		307		843		465
INCOME TAXES (BENEFITS)	127		114		349		225
NET INCOME	188		193		494		240
Income (loss) attributable to noncontrolling interest	1		(10)		1		(15)
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$ 187		$ 203		$ 493		$ 255
EARNINGS PER SHARE OF COMMON STOCK:
Basic, in dollars per share	$ 0.45		$ 0.48		$ 1.18		$ 0.67
Diluted, in dollars per share	$ 0.45		$ 0.48		$ 1.18		$ 0.67
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares	417		418		418		380
Diluted, in shares	419		420		419		382
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$ 0		$ 0		$ 0.55		$ 0.55

[1] Includes excise tax collections of $107 million and $116 million in the three months ended June 30, 2012 and 2011, respectively, and $228 million and $235 million in the six months ended June 30, 2012 and 2011, respectively.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended			3 Months Ended	6 Months Ended
	Jun. 30, 2011	Jun. 30, 2011	Jun. 30, 2012	Dec. 31, 2011	Mar. 31, 2011 Allegheny	Jun. 30, 2012 Allegheny
Income Tax Contingency [Line Items]
Previously unrecognized tax benefit, impact on effective tax rate from settlement with authorities		$ 3
Decrease in unrecognized tax benefits						21
Income tax benefits on settlement of recognized research and development claim	30
Tax benefits arising from favorable affected tax rate included in Research and development settlement	5	5
Unrecognized tax benefits expected to resolved within the next twelve month			42
Unrecognized benefits (if recognized) affecting effective tax rate	6	6	7
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		$ 28

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Consolidated Balance Sheets (Unaudited) (FirstEnergy Corp.) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 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	$ 36	$ 37
Other [Member]
Receivables-
Allowance for uncollectible accounts	$ 2	$ 3

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Derivative Instruments (Details 3) (Not Designated as Hedging Instrument [Member], Subject to Regulatory Accounting, Excluded from Earnings, USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Derivative [Line Items]
Unrealized Gain (Loss) to Derivative Instrument	$ (199)	$ (145)	$ (279)	$ (234)
Realized Gain (Loss) to Derivative Instrument	66	62	142	124
NUGs
Derivative [Line Items]
Unrealized Gain (Loss) to Derivative Instrument	(54)	(147)	(133)	(236)
Realized Gain (Loss) to Derivative Instrument	61	62	133	134
LCAPP
Derivative [Line Items]
Unrealized Gain (Loss) to Derivative Instrument	(145)	0	(145)	0
Realized Gain (Loss) to Derivative Instrument	0	0	0	0
Regulated FTRs
Derivative [Line Items]
Unrealized Gain (Loss) to Derivative Instrument	0	2	(1)	2
Realized Gain (Loss) to Derivative Instrument	5	0	9	(10)
Other
Derivative [Line Items]
Unrealized Gain (Loss) to Derivative Instrument	0	0	0	0
Realized Gain (Loss) to Derivative Instrument	$ 0	$ 0	$ 0	$ 0

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2012

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FE CONSOLIDATED
Recurring Fair Value Measurements	June 30, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,636		$	—		1,636			$	—	$	1,544		$	—		$	1,544
Derivative assets - commodity contracts	4			337			—			341			—		264			—			264
Derivative assets - FTRs	—			—			12			12			—		—			1			1
Derivative assets - interest rate swaps	—			3			—			3			—		—			—			—
Derivative assets - NUG contracts(1)	—			—			9			9			—		—			56			56
Equity securities(2)	280			—			—			280			259		—			—			259
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			144			—			144			—		148			—			148
U.S. state debt securities	—			308			—			308			—		314			—			314
Other(3)	63			128			—			191			49		225			—			274
Total assets	347			2,556			21			2,924			308		2,498			57			2,863
Liabilities
Derivative liabilities - commodity contracts	(1		)	(262		)	—			(263		)	—		(247		)	—			(247		)
Derivative liabilities - FTRs	—			—			(9		)	(9		)	—		—			(23		)	(23		)
Derivative liabilities - interest rate swaps	—			(23		)	—			(23		)	—		—			—			—
Derivative liabilities - NUG contracts(1)	—			—			(302		)	(302		)	—		—			(349		)	(349		)
Derivative liabilities - LCAPP contracts(1)	—			—			(145		)	(145		)	—		—			—			—
Total liabilities	(1		)	(285		)	(456		)	(742		)	—		(247		)	(372		)	(619		)
Net assets (liabilities)(4)	$	346		$	2,271		$	(435	)	$	2,182		$	308	$	2,251		$	(315	)	$	2,244

⁽¹⁾  NUG and LCAPP contracts are generally subject to regulatory accounting treatment 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 $(7) million and $(52) million as of June 30, 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 and LCAPP contracts held by certain Utilities and FTRs held by FirstEnergy and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:

	NUG Contracts(1)									LCAPP Contracts(1)								FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
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)	(48		)	(86		)	(134		)	—		—			—			—			(2		)	(2		)
Purchases	—			—			—			—		(145		)	(145		)	12			(9		)	3
Issues	—			—			—			—		—			—			—			—			—
Sales	—			—			—			—		—			—			—			—			—
Settlements	—			133			133			—		—			—			(1		)	25			24
Transfers in (out) of Level 3	—			—			—			—		—			—			—			—			—
June 30, 2012 Balance	$	9		$	(302	)	$	(293	)	$	—	$	(145	)	$	(145	)	$	12		$	(9	)	$	3

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

Quantitative information for level 3 valuation

The following table provides quantitative information for FTRs, NUG contracts and LCAPP contracts that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average		Units
FTRs	$	3		Model	RTO auction clearing prices	($3.60) to $4.90	$	0.70	Dollars/MWH
NUG Contracts	$	(293	)	Model	Generation Electricity regional prices	500 to 6,609,000 $49.50 to $84.90	2,665,000 $63.70		MWH Dollars/MWH
LCAPP Contracts	$	(145	)	Model	Regional capacity prices	$94.90 to $248.40	$183.90		Dollars/MW-Day

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 June 30, 2012 and December 31, 2011:

	June 30, 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	$	2,032	$	52	$	—	$	2,084	$	1,980	$	25	25	$	—	—	$	2,005
FES	1,034		29		—		1,063		1,012		13			—			1,025
OE	138		—		—		138		134		—			—			134
JCP&L	358		12		—		370		356		7			—			363
Equity securities
FE Consolidated	$	243	$	36	$	—	$	279	$	222	$	36		$	—		$	258
FES	125		19		—		144		104		20			—			124
JCP&L	27		3		—		30		27		3			—			30

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $113 million; FES - $42 million; OE - $3 million; JCP&L - $23 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 and six months ended June 30, 2012 and 2011 were as follows:

Three Months Ended
June 30, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	131	$	17	$	(18	)	$	18
FES	25		13		(14		)	11
OE	20		—		—			1
JCP&L	70		1		(1		)	3
June 30, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	734	$	22	$	(16	)	$	28
FES	297		10		(7		)	17
OE	12		—		—			1
JCP&L	159		4		(2		)	4

Six Months Ended
June 30, 2012	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	382	$	37	$	(35	)	$	33
FES	109		26		(25		)	18
OE	57		—		—			1
JCP&L	165		2		(2		)	7
June 30, 2011	Sales Proceeds		Realized Gains		Realized Losses			Interest and Dividend Income
	(In millions)
FE Consolidated	$	1,703	$	122	$	(45	)	$	52
FES	513		22		(23		)	32
OE	20		—		—			2
JCP&L	376		26		(6		)	8

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 June 30, 2012 and December 31, 2011:

	June 30, 2012						December 31, 2011
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FE Consolidated	$	326	$	55	$	381	$	402	$	50	$	452
OE	148		32		180		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 June 30, 2012 and December 31, 2011:

	June 30, 2012				December 31, 2011
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FE Consolidated	$	16,571	$	18,998	$	17,165	$	19,320
FES	3,617		3,862		3,675		3,931
OE	1,157		1,493		1,157		1,434
JCP&L	1,762		2,076		1,777		2,080

FES

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FES
Recurring Fair Value Measurements	June 30, 2012												December 31, 2011
	Level 1			Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,057		$	—		$	1,057		$	—	$	1,010		$	—		$	1,010
Derivative assets - commodity contracts	4			326			—			330			—		248			—			248
Derivative assets - FTRs	—			—			8			8			—		—			1			1
Equity securities(1)	145			—			—			145			124		—			—			124
Foreign government debt securities	—			—			—			—			—		3			—			3
U.S. government debt securities	—			6			—			6			—		7			—			7
U.S. state debt securities	—			—			—			—			—		5			—			5
Other(2)	—			48			—			48			—		132			—			132
Total assets	149			1,437			8			1,594			124		1,405			1			1,530
Liabilities
Derivative liabilities - commodity contracts	(1		)	(262		)	—			(263		)	—		(234		)	—			(234		)
Derivative liabilities - FTRs	—			—			(6		)	(6		)	—		—			(7		)	(7		)
Total liabilities	(1		)	(262		)	(6		)	(269		)	—		(234		)	(7		)	(241		)
Net assets (liabilities)(3)	$	148		$	1,175		$	2		$	1,325		$	124	$	1,171		$	(6	)	$	1,289

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

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

⁽³⁾  Excludes $(6) million and $(58) million as of June 30, 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 June 30, 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	8			(7		)	1
Issues	—			—			—
Sales	—			—			—
Settlements	(1		)	9			8
Transfers in (out) of Level 3	—			—			—
June 30, 2012 Balance	$	8		$	(6	)	$	2

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 June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)		Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	2	Model	RTO auction clearing prices	($3.60) to $4.90	$0.50	Dollars/MWH

OE

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

OE
Recurring Fair Value Measurements	June 30, 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	—		138		—		138		—		132		—		132
Other(1)	—		3		—		3		—		2		—		2
Total assets(2)	$	—	$	141	$	—	$	141	$	—	$	137	$	—	$	137

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

⁽²⁾  Excludes $1 million as of June 30, 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	June 30, 2012										December 31, 2011
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	149	$	—		$	149		$	—	$	144	$	—		$	144
Derivative assets - NUG contracts(1)	—		—		4			4			—		—		4			4
Equity securities(2)	30		—		—			30			30		—		—			30
U.S. government debt securities	—		—		—			—			—		2		—			2
U.S. state debt securities	—		223		—			223			—		219		—			219
Other(3)	—		19		—			19			—		15		—			15
Total assets	30		391		4			425			30		380		4			414
Liabilities
Derivative liabilities - NUG contracts(1)	—		—		(125		)	(125		)	—		—		(147		)	(147		)
Derivative liabilities - LCAPP contracts(1)	—		—		(145		)	(145		)	—		—		—			—
Total liabilities	—		—		(270		)	(270		)	—		—		(147		)	(147		)
Net assets (liabilities)(4)	$	30	$	391	$	(266	)	$	155		$	30	$	380	$	(143	)	$	267

⁽¹⁾  NUG and LCAPP contracts are subject to regulatory accounting treatment 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 June 30, 2012 and 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 and LCAPP contracts held by JCP&L and classified as Level 3 in the fair value hierarchy for the periods ended June 30, 2012 and December 31, 2011:

	NUG Contracts(1)									LCAPP Contracts(1)
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net
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 Balance	$	4		$	(147	)	$	(143	)	$	—	$	—		$	—
Realized gain (loss)	—			—			—			—		—			—
Unrealized gain (loss)	—			(7		)	(7		)	—		—			—
Purchases	—			—			—			—		(145		)	(145		)
Issues	—			—			—			—		—			—
Sales	—			—			—			—		—			—
Settlements	—			29			29			—		—			—
Transfers in (out) of Level 3	—			—			—			—		—			—
June 30, 2012 Balance	$	4		$	(125	)	$	(121	)	$	—	$	(145	)	$	(145	)

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

Quantitative information for level 3 valuation

The following table provides quantitative information for NUG and LCAPP contracts held by JCP&L that are classified as Level 3 in the fair value hierarchy for the period ended June 30, 2012:

	Fair Value as of June 30, 2012 (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
NUG Contracts	$	(121	)	Model	Generation Electricity regional prices	63,000 to 715,000 $49.50 to $84.90	166,000 $65.80	MWH Dollars/MWH
LCAPP Contracts	$	(145	)	Model	Regional capacity prices	$94.90 to $248.40	$183.90	Dollars/MW-Day

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Supplemental Guarantor Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Consolidating Statements of Income
Revenues	$ 2,279	$ 2,590	$ 4,790	$ 4,925
OPERATING EXPENSES:
Fuel	656	635	1,197	1,088
Purchased power	1,156	1,220	2,503	2,406
Other operating expenses	914	1,065	1,726	2,058
Provision for depreciation	292	287	577	512
General taxes	232	242	504	479
Total operating expenses	3,312	3,539	6,644	6,765
OPERATING INCOME (LOSS)	557	521	1,303	871
OTHER INCOME (EXPENSE):
Investment income	13	31	24	52
Interest expense	(274)	(265)	(520)	(496)
Capitalized interest	19	20	36	38
Total other income (expense)	(242)	(214)	(460)	(406)
INCOME (LOSS) BEFORE INCOME TAXES	315	307	843	465
INCOME TAXES (BENEFITS)	127	114	349	225
NET INCOME	188	193	494	240
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	188	193	494	240
Pension and OPEB prior service costs	(48)	48	(101)	4
Amortized gain (loss) on derivative hedges	3	17	1	11
Change in unrealized gain on available-for-sale securities	2	10	12	19
Other comprehensive income (loss)	(43)	75	(88)	34
Income taxes (benefits) on other comprehensive income (loss)	(27)	33	(51)	14
Other comprehensive income (loss), net of tax	(16)	42	(37)	20
COMPREHENSIVE INCOME	172	235	457	260
FES Corp
Consolidating Statements of Income
Revenues	1,430	1,275	2,920	2,642
OPERATING EXPENSES:
Fuel	0	6	0	7
Other operating expenses	107	159	183	321
Provision for depreciation	1	1	2	2
General taxes	20	16	40	27
Impairment of long-lived assets		0		0
Total operating expenses	1,718	1,416	3,267	3,073
OPERATING INCOME (LOSS)	(288)	(141)	(347)	(431)
OTHER INCOME (EXPENSE):
Investment income	0	0	1	1
Miscellaneous income, including net income from equity investees	279	132	537	374
Capitalized interest	0	0	0	0
Total other income (expense)	250	108	482	326
INCOME (LOSS) BEFORE INCOME TAXES	(38)	(33)	135	(105)
INCOME TAXES (BENEFITS)	(37)	(62)	14	(179)
NET INCOME	(1)	29	121	74
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	(1)	29	121	74
Pension and OPEB prior service costs	8	(5)	3	(9)
Amortized gain (loss) on derivative hedges	1	14	(4)	5
Change in unrealized gain on available-for-sale securities	3	8	13	15
Other comprehensive income (loss)	12	17	12	11
Income taxes (benefits) on other comprehensive income (loss)	2	8	4	4
Other comprehensive income (loss), net of tax	10	9	8	7
COMPREHENSIVE INCOME	9	38	129	81
FES Corp | Affiliates
OPERATING EXPENSES:
Purchased power	1,156	902	2,121	2,087
OTHER INCOME (EXPENSE):
Interest expense	(5)	0	(9)	(1)
FES Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	434	332	921	629
OTHER INCOME (EXPENSE):
Interest expense	(24)	(24)	(47)	(48)
FGCO
Consolidating Statements of Income
Revenues	636	535	1,178	1,278
OPERATING EXPENSES:
Fuel	336	266	576	560
Other operating expenses	100	108	192	219
Provision for depreciation	30	32	60	63
General taxes	8	8	18	19
Impairment of long-lived assets		7		20
Total operating expenses	474	427	846	889
OPERATING INCOME (LOSS)	162	108	332	389
OTHER INCOME (EXPENSE):
Investment income	5	1	9	1
Miscellaneous income, including net income from equity investees	19	1	19	2
Capitalized interest	1	5	2	10
Total other income (expense)	(3)	(22)	(25)	(44)
INCOME (LOSS) BEFORE INCOME TAXES	159	86	307	345
INCOME TAXES (BENEFITS)	(7)	28	(8)	125
NET INCOME	166	58	315	220
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	166	58	315	220
Pension and OPEB prior service costs	7	(4)	3	(8)
Amortized gain (loss) on derivative hedges	0	0	0	0
Change in unrealized gain on available-for-sale securities	0	0	0	0
Other comprehensive income (loss)	7	(4)	3	(8)
Income taxes (benefits) on other comprehensive income (loss)	3	(2)	1	(4)
Other comprehensive income (loss), net of tax	4	(2)	2	(4)
COMPREHENSIVE INCOME	170	56	317	216
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power	0	9	0	11
OTHER INCOME (EXPENSE):
Interest expense	(2)	(1)	(3)	(1)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	(3)	0	(3)
OTHER INCOME (EXPENSE):
Interest expense	(26)	(28)	(52)	(56)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues	473	393	867	862
OPERATING EXPENSES:
Fuel	44	44	99	92
Other operating expenses	172	134	288	313
Provision for depreciation	39	37	73	76
General taxes	4	6	11	14
Impairment of long-lived assets		0		0
Total operating expenses	319	286	593	629
OPERATING INCOME (LOSS)	154	107	274	233
OTHER INCOME (EXPENSE):
Investment income	7	15	12	20
Miscellaneous income, including net income from equity investees	0	0	0	0
Capitalized interest	8	5	16	10
Total other income (expense)	0	3	5	(4)
INCOME (LOSS) BEFORE INCOME TAXES	154	110	279	229
INCOME TAXES (BENEFITS)	42	41	65	86
NET INCOME	112	69	214	143
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	112	69	214	143
Pension and OPEB prior service costs	0	0	0	0
Amortized gain (loss) on derivative hedges	0	0	0	0
Change in unrealized gain on available-for-sale securities	3	8	13	15
Other comprehensive income (loss)	3	8	13	15
Income taxes (benefits) on other comprehensive income (loss)	1	3	5	6
Other comprehensive income (loss), net of tax	2	5	8	9
COMPREHENSIVE INCOME	114	74	222	152
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power	60	65	122	134
OTHER INCOME (EXPENSE):
Interest expense	(1)	(1)	(2)	(1)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	(14)	(16)	(21)	(33)
Eliminations
Consolidating Statements of Income
Revenues	(1,083)	(911)	(1,993)	(2,098)
OPERATING EXPENSES:
Fuel	0	0	0	0
Other operating expenses	14	12	25	25
Provision for depreciation	(1)	(1)	(3)	(3)
General taxes	0	0	0	0
Impairment of long-lived assets		0		0
Total operating expenses	(1,070)	(900)	(1,971)	(2,076)
OPERATING INCOME (LOSS)	(13)	(11)	(22)	(22)
OTHER INCOME (EXPENSE):
Investment income	(6)	0	(10)	0
Miscellaneous income, including net income from equity investees	(278)	(129)	(532)	(368)
Capitalized interest	0	0	0	0
Total other income (expense)	(262)	(113)	(501)	(336)
INCOME (LOSS) BEFORE INCOME TAXES	(275)	(124)	(523)	(358)
INCOME TAXES (BENEFITS)	3	3	6	5
NET INCOME	(278)	(127)	(529)	(363)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	(278)	(127)	(529)	(363)
Pension and OPEB prior service costs	(7)	4	(3)	8
Amortized gain (loss) on derivative hedges	0	0	0	0
Change in unrealized gain on available-for-sale securities	(3)	(8)	(13)	(15)
Other comprehensive income (loss)	(10)	(4)	(16)	(7)
Income taxes (benefits) on other comprehensive income (loss)	(4)	(1)	(6)	(2)
Other comprehensive income (loss), net of tax	(6)	(3)	(10)	(5)
COMPREHENSIVE INCOME	(284)	(130)	(539)	(368)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power	(1,083)	(911)	(1,993)	(2,098)
OTHER INCOME (EXPENSE):
Interest expense	6	0	10	0
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	16	16	31	32
FES
Consolidating Statements of Income
Revenues	1,456	1,292	2,972	2,684
OPERATING EXPENSES:
Fuel	380	316	675	659
Other operating expenses	393	413	688	878
Provision for depreciation	69	69	132	138
General taxes	32	30	69	60
Impairment of long-lived assets	0	7	0	20
Total operating expenses	1,441	1,229	2,735	2,515
OPERATING INCOME (LOSS)	15	63	237	169
OTHER INCOME (EXPENSE):
Investment income	6	16	12	22
Miscellaneous income, including net income from equity investees	20	4	24	8
Capitalized interest	9	10	18	20
Total other income (expense)	(15)	(24)	(39)	(58)
INCOME (LOSS) BEFORE INCOME TAXES	0	39	198	111
INCOME TAXES (BENEFITS)	1	10	77	37
NET INCOME	(1)	29	121	74
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	(1)	29	121	74
Pension and OPEB prior service costs	8	(5)	3	(9)
Amortized gain (loss) on derivative hedges	1	14	(4)	5
Change in unrealized gain on available-for-sale securities	3	8	13	15
Other comprehensive income (loss)	12	17	12	11
Income taxes (benefits) on other comprehensive income (loss)	2	8	4	4
Other comprehensive income (loss), net of tax	10	9	8	7
COMPREHENSIVE INCOME	9	38	129	81
FES | Affiliates
OPERATING EXPENSES:
Purchased power	133	65	250	134
OTHER INCOME (EXPENSE):
Interest expense	(2)	(2)	(4)	(3)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	434	329	921	626
OTHER INCOME (EXPENSE):
Interest expense	$ (48)	$ (52)	$ (89)	$ (105)

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Pensions and Other Postemployment Benefits

6 Months Ended

Jun. 30, 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 six months ended June 30, 2012, FirstEnergy made a voluntary $600 million pre-tax contribution to its qualified pension plan.

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 June 30,	2012			2011			2012			2011
	(In millions)
Service cost	$	40		$	34		$	3		$	3
Interest cost	97			96			12			12
Expected return on plan assets	(121		)	(115		)	(9		)	(10		)
Amortization of prior service cost	3			4			(51		)	(51		)
Other adjustments (settlements, curtailments, etc)	—			—			—			—
Net periodic costs (credits)	$	19		$	19		$	(45	)	$	(46	)

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Six Months Ended June 30,	2012			2011			2012			2011
	(In millions)
Service cost	$	80		$	63		$	6		$	6
Interest cost	194			180			24			23
Expected return on plan assets	(242		)	(217		)	(18		)	(20		)
Amortization of prior service cost	6			8			(102		)	(99		)
Other adjustments (settlements, curtailments, etc)	—			7			—			—
Net periodic costs (credits)	$	38		$	41		$	(90	)	$	(90	)

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 June 30,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	14		$	14		$	(32	)	$	(34	)
FES	11			7			(8		)	(9		)
OE	(1		)	(2		)	(6		)	(5		)
JCP&L	(2		)	(3		)	(2		)	(2		)

Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Six Months Ended June 30,	2012			2011			2012			2011
	(In millions)
FE Consolidated	$	27		$	34		$	(62	)	$	(66	)
FES	21			14			(16		)	(16		)
OE	(2		)	(4		)	(11		)	(11		)
JCP&L	(3		)	(5		)	(4		)	(5		)

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 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
	June 30, 2012		December 31, 2011			June 30, 2012			December 31, 2011
	(In millions)					(In millions)
Power Contracts					Power Contracts
Current Assets	$	232	$	185	Current Liabilities	$	(213	)	$	(196	)
Noncurrent Assets	106		79		Noncurrent Liabilities	(49		)	(51		)
FTRs					FTRs
Current Assets	12		1		Current Liabilities	(8		)	(22		)
Noncurrent Assets	—		—		Noncurrent Liabilities	(1		)	(1		)
NUGs	9		56		NUGs	(302		)	(349		)
LCAPP	—		—		LCAPP	(145		)	—
Interest Rate Swaps					Interest Rate Swaps
Noncurrent Assets	3		—		Noncurrent Liabilities	(23		)	—
Other					Other
Current Assets	4		—		Current Liabilities	(1		)	—
	$	366	$	321		$	(742	)	$	(619	)

Volume of First Energy's outstanding derivative transactions

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2012:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	29	40	(11	)	MWH
FTRs	82	—	82		MWH
Interest Rate Swaps	1,600	—	1,600		notional dollars
NUGs	22	—	22		MWH
LCAPP	408	—	408		MW
Natural Gas	26	—	26		Million BTUs

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 June 30, 2012 and 2011, are summarized in the following tables:

	Three Months Ended June 30
	Power Contracts			FTRs			Interest Rate Swaps			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	1		$	—		$	—		$	—		$	1
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	14		$	—		$	—		$	—		$	14
Derivatives Not in a Hedging Relationship
2012
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	7		$	12		$	—		$	5		$	24
Interest Expense	—			—			(20		)	—			(20		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(104	)	$	—		$	—		$	—		$	(104	)
Revenues	95			5			—			—			100
Other Operating Expense	—			(18		)	—			—			(18		)
Fuel Expense	—			—			—			(1		)	(1		)
Interest Expense	—			—			—			—			—
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	33		$	—		$	—		$	—		$	33
Revenues	(4		)	—			—			—			(4		)
Other Operating Expense	(34		)	11			—			—			(23		)
Interest Expense	—			—			—			—			—
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	1		$	—		$	—		$	—		$	1
Revenues	(39		)	13			—			—			(26		)
Other Operating Expense	—			(40		)	—			—			(40		)
Interest Expense	—			—			—			—			—

	Six Months Ended June 30
	Power Contracts			FTRs			Interest Rate Swaps			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(4	)	$	—		$	—		$	—		$	(4	)
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	5		$	—		$	—		$	—		$	5
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:
Other Operating Expense	$	62		$	17		$	—		$	3		$	82
Interest Expense	—			—			(20		)	—			(20		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(221	)	$	—		$	—		$	—		$	(221	)
Revenues	206			11			—			—			217
Other Operating Expense	—			(41		)	—			—			(41		)
Fuel Expense	—			—			—			(1		)	(1		)
Interest Expense	—			—			—			—			—
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	61		$	—		$	—		$	—		$	61
Revenues	(3		)	—			—			—			(3		)
Other Operating Expense	(54		)	12			1			—			(41		)
Interest Expense	—			—			—			—			—
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(36	)	$	—		$	—		$	—		$	(36	)
Revenues	(29		)	16			(1		)	—			(14		)
Other Operating Expense	—			(54		)	—			—			(54		)
Interest Expense	—			—			—			—			—

Derivative instruments subject to regulatory accounting

The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and six months ended June 30, 2012 and 2011, are summarized in the following tables:

	Three Months Ended June 30
	NUGs			LCAPP			Regulated FTRs		Other		Total
	(In millions)
Derivatives Not in a Hedging Relationship with Regulatory Offset
2012
Unrealized Gain (Loss) to Derivative Instrument	$	(54	)	$	(145	)	$	—	$	—	$	(199	)
Realized Gain (Loss) to Derivative Instrument	61			—			5		—		66
2011
Unrealized Gain (Loss) to Derivative Instrument	$	(147	)	$	—		$	2	$	—	$	(145	)
Realized Gain (Loss) to Derivative Instrument	62			—			—		—		62

	Six Months Ended June 30
	NUGs			LCAPP			Regulated FTRs			Other		Total
	(In millions)
Derivatives Not in a Hedging Relationship with Regulatory Offset
2012
Unrealized Gain (Loss) to Derivative Instrument	$	(133	)	$	(145	)	$	(1	)	$	—	$	(279	)
Realized Gain (Loss) to Derivative Instrument	133			—			9			—		142
2011
Unrealized Gain (Loss) to Derivative Instrument	$	(236	)	$	—		$	2		$	—	$	(234	)
Realized Gain (Loss) to Derivative Instrument	134			—			(10		)	—		124

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 and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			LCAPP			Regulated FTRs			Other		Total
	(In millions)
Outstanding net asset (liability) as of April 1, 2012	$	(300	)	$	—		$	(5	)	$	—	$	(305	)
Additions/Change in value of existing contracts	(54		)	(145		)	—			—		(199		)
Settled contracts	61			—			5			—		66
Outstanding net asset (liability) as of June 30, 2012	$	(293	)	$	(145	)	$	—		$	—	$	(438	)
Outstanding net asset (liability) as of April 1, 2011	$	(362	)	$	—		$	—		$	—	$	(362	)
Additions/Change in value of existing contracts	(147		)	—			2			—		(145		)
Settled contracts	62			—			—			—		62
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	—		$	2		$	—	$	(445	)

	Six Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			LCAPP			Regulated FTRs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2012	$	(293	)	$	—		$	(8	)	$	—		$	(301	)
Additions/Change in value of existing contracts	(133		)	(145		)	(1		)	—			(279		)
Settled contracts	133			—			9			—			142
Outstanding net asset (liability) as of June 30, 2012	$	(293	)	$	(145	)	$	—		$	—		$	(438	)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	—		$	—		$	10		$	(335	)
Additions/Change in value of existing contracts	(236		)	—			2			—			(234		)
Settled contracts	134			—			—			(10		)	124
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	—		$	2		$	—		$	(445	)

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

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Variable Interest Entities

6 Months Ended

Jun. 30, 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 second 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 $262 million was outstanding as of June 30, 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 $503 million was outstanding as of June 30, 2012.

The caption noncontrolling interest within the consolidated financial statements is used to reflect the portion of a VIE that FirstEnergy consolidates, but does not own. The change in noncontrolling interest within the Consolidated Balance Sheets during the six months ended June 30, 2012, was primarily due to net income attributable to noncontrolling interests of $1 million, offset by a $5 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 $31 million as of June 30, 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 21 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 ended June 30, 2012, were $14 million, $27 million and $17 million for JCP&L, PE and WP, respectively and $26 million, $59 million and $33 million for the six months ended June 30, 2012, 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 ended June 30, 2011, were $55 million, $47 million, and $21 million, respectively and $120 million, $58 million and $26 million for the six months ended June 30, 2011, 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 June 30, 2012, WP’s reserve for this adverse purchase power commitment was $48 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 June 30, 2012:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,318	$	1,111	$	207
OE	574		384		190
Other FE subsidiaries	599		333		266

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.5 billion.

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011		Dec. 31, 2011
Segment Financial Information
External revenues	$ 3,869		$ 4,048		$ 7,945		$ 7,592
Internal revenues	0		12		2		44
Total revenues	3,869	[1]	4,060	[1]	7,947	[1]	7,636	[1]
Depreciation and amortization	354		377		714		734
Investment income	13		31		24		52
Net interest charges	255		245		484		458
Income taxes	127		114		349		225
Net income	188		193		494		240
Total assets	48,048		47,596		48,048		47,596		47,326
Total goodwill	6,444		6,436		6,444		6,436		6,441
Property additions	412		569		1,001		1,018
Regulated Distribution
Segment Financial Information
External revenues	2,095		2,409		4,420		4,632
Internal revenues	0		0		0		0
Total revenues	2,095		2,409		4,420		4,632
Depreciation and amortization	215		232		435		473
Investment income	19		25		42		48
Net interest charges	132		134		264		256
Income taxes	94		100		187		158
Net income	161		171		318		267
Total assets	25,787		25,069		25,787		25,069
Total goodwill	5,025		5,025		5,025		5,025
Property additions	177		266		443		381
Regulated Transmission
Segment Financial Information
External revenues	184		182		370		295
Internal revenues	0		0		0		0
Total revenues	184		182		370		295
Depreciation and amortization	29		28		61		50
Investment income	0		0		1		0
Net interest charges	22		24		45		41
Income taxes	31		33		66		47
Net income	52		57		112		80
Total assets	4,473		4,202		4,473		4,202
Total goodwill	526		526		526		526
Property additions	59		81		122		170
Competitive Energy Services
Segment Financial Information
External revenues	1,616		1,495		3,222		2,736
Internal revenues	209		318		477		661
Total revenues	1,825		1,813		3,699		3,397
Depreciation and amortization	103		109		203		197
Investment income	6		16		12		21
Net interest charges	59		69		113		122
Income taxes	14		12		97		21
Net income	25		21		166		36
Total assets	17,216		17,146		17,216		17,146
Total goodwill	893		885		893		885
Property additions	150		197		393		411
Other/Corporate
Segment Financial Information
External revenues	(24)		(30)		(47)		(53)
Internal revenues	0		0		0		0
Total revenues	(24)		(30)		(47)		(53)
Depreciation and amortization	8		8		16		14
Investment income	1		0		1		1
Net interest charges	42		19		63		39
Income taxes	(25)		(30)		(41)		(30)
Net income	(42)		(51)		(69)		(105)
Total assets	572		1,179		572		1,179
Total goodwill	0		0		0		0
Property additions	26		25		43		56
Reconciling Adjustments
Segment Financial Information
External revenues	(2)		(8)		(20)		(18)
Internal revenues	(209)		(306)		(475)		(617)
Total revenues	(211)		(314)		(495)		(635)
Depreciation and amortization	(1)		0		(1)		0
Investment income	(13)		(10)		(32)		(18)
Net interest charges	0		(1)		(1)		0
Income taxes	13		(1)		40		29
Net income	(8)		(5)		(33)		(38)
Total assets	0		0		0		0
Total goodwill	0		0		0		0
Property additions	$ 0		$ 0		$ 0		$ 0

[1] Includes excise tax collections of $107 million and $116 million in the three months ended June 30, 2012 and 2011, respectively, and $228 million and $235 million in the six months ended June 30, 2012 and 2011, respectively.

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Consolidated Statements of Cash Flows (Unaudited) (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 494	$ 240
Provision for depreciation	577	512
Adjustments to reconcile net income to net cash from operating activities-
Amortization of regulatory assets, net	137	222
Nuclear fuel and lease amortization	106	92
Deferred purchased power and other costs	(149)	(168)
Deferred income taxes and investment tax credits, net	423	598
Deferred rents and lease market valuation liability	(106)	(61)
Stock based compensation	(18)	(4)
Accrued compensation and retirement benefits	(160)	(31)
Commodity derivative transactions, net	(86)	(21)
Pension trust contribution	(600)	(262)
Asset impairments	7	41
Cash collateral, net	22	(31)
Decrease (increase) in operating assets-
Receivables	(105)	199
Materials and supplies	(109)	24
Prepayments and other current assets	(117)	(268)
Increase (decrease) in operating liabilities-
Accounts payable	(122)	(28)
Accrued taxes	(192)	(66)
Accrued interest	(5)	(4)
Other	65	47
Net cash provided from operating activities	62	1,031
New financing-
Long-term debt	182	503
Short-term borrowings, net	1,890	0
Redemptions and Repayments-
Long-term debt	(746)	(1,002)
Short-term borrowings, net	0	(44)
Common stock dividend payments	(460)	(420)
Other	(35)	(76)
Net cash provided from (used for) financing activities	831	(1,039)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,001)	(1,018)
Sales of investment securities held in trusts	382	1,703
Purchases of investment securities held in trusts	(420)	(1,807)
Cash investments	87	50
Cash received in Allegheny merger	0	590
Other	(49)	(53)
Net cash used for investing activities	(1,001)	(535)
Net change in cash and cash equivalents	(108)	(543)
Cash and cash equivalents at beginning of period	202	1,019
Cash and cash equivalents at end of period	94	476
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: merger with Allegheny, common stock issued	$ 0	$ 4,354

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Consolidated Statements of Income (Unaudited) (FirstEnergy Corp.) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Income Statement [Abstract]
Excise tax collections included in Revenue	$ 107	$ 116	$ 228	$ 235

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Consolidated Balance Sheets (Unaudited) (Jersey Central Power & Light Company) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Receivables-
Customers, net of allowance for uncollectible accounts	$ 1,635	$ 1,525
Other	263	269
Prepaid taxes	248	191
Other	171	122
Total current assets	3,608	3,355
UTILITY PLANT:
In service	41,167	40,122
Less - Accumulated provision for depreciation	12,336	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,831	28,283
Construction work in progress	1,937	2,054
Total net property, plant and equipment	30,768	30,337
OTHER PROPERTY AND INVESTMENTS:
Nuclear plant decommissioning trusts	2,153	2,112
Other	1,039	1,008
Total other property and investments	3,518	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444	6,441
Regulatory assets	2,122	2,030
Other	1,588	1,641
Total deferred charges and other assets	10,154	10,112
Total assets	48,048	47,326
CURRENT LIABILITIES:
Currently payable long-term debt	1,577	1,621
Accounts payable-
Accrued compensation and benefits	288	384
Other	617	900
Total current liabilities	6,082	4,855
Common stockholders' equity-
Common stock	42	42
Other paid-in capital	9,756	9,765
Accumulated other comprehensive income	389	426
Retained earnings (Accumulated deficit)	3,310	3,047
Total common stockholders' equity	13,497	13,280
Long-term debt and other long-term obligations	15,159	15,716
Total capitalization	28,671	29,015
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,042	5,670
Retirement benefits	2,257	2,823
Asset retirement obligations	1,548	1,497
Other	1,980	2,072
Total noncurrent liabilities	13,295	13,456
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	48,048	47,326
JCP&L
Receivables-
Customers, net of allowance for uncollectible accounts	227	235
Affiliated companies	12	0
Other	23	17
Prepaid taxes	108	33
Other	22	19
Total current assets	392	304
UTILITY PLANT:
In service	5,067	4,872
Less - Accumulated provision for depreciation	1,779	1,743
Property, plant and equipment in service net of accumulated provision for depreciation	3,288	3,129
Construction work in progress	125	227
Total net property, plant and equipment	3,413	3,356
OTHER PROPERTY AND INVESTMENTS:
Nuclear fuel disposal trust	227	219
Nuclear plant decommissioning trusts	196	193
Other	2	2
Total other property and investments	425	414
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	1,811	1,811
Regulatory assets	523	408
Other	33	32
Total deferred charges and other assets	2,367	2,251
Total assets	6,597	6,325
CURRENT LIABILITIES:
Currently payable long-term debt	35	34
Short-term borrowings-
Other	80	0
Accounts payable-
Affiliated companies	16	19
Other	101	101
Accrued compensation and benefits	33	41
Customer deposits	24	24
Accrued interest	18	18
Other	21	36
Total current liabilities	666	532
Common stockholders' equity-
Common stock	136	136
Other paid-in capital	2,011	2,011
Accumulated other comprehensive income	34	39
Retained earnings (Accumulated deficit)	136	121
Total common stockholders' equity	2,317	2,307
Long-term debt and other long-term obligations	1,720	1,736
Total capitalization	4,037	4,043
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	917	859
Power purchase contract liability	270	147
Nuclear fuel disposal costs	197	197
Retirement benefits	163	170
Asset retirement obligations	119	115
Other	228	262
Total noncurrent liabilities	1,894	1,750
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	6,597	6,325
Affiliates | JCP&L
Short-term borrowings-
Affiliated companies	$ 338	$ 259

XML

Document and Entity Information	6 Months Ended
	Jun. 30, 2012	Aug. 06, 2012
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	0001031296
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		418,216,437
FES
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	0001407703
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		7
OE
Entity Registrant Name	OHIO EDISON CO
Entity Central Index Key	0000073960
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		60
JCP&L
Entity Registrant Name	JERSEY CENTRAL POWER & LIGHT CO
Entity Central Index Key	0000053456
Document Type	10-Q
Document Period End Date	Jun. 30, 2012
Amendment Flag	false
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		13,628,447

XML

Consolidated Balance Sheets (Unaudited) (Jersey Central Power & Light Company) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 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	$ 36	$ 37
JCP&L
Common stockholders' equity-
Common stock, par value (in dollars per share)	$ 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	$ 3

XML

Consolidated Statements of Comprehensive Income (Unaudited) (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
Statement of Income and Comprehensive Income [Abstract]
NET INCOME	$ 188	$ 193	$ 494	$ 240
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(48)	48	(101)	4
Amortized gain (loss) on derivative hedges	3	17	1	11
Change in unrealized gain on available-for-sale securities	2	10	12	19
Other comprehensive income (loss)	(43)	75	(88)	34
Income taxes (benefits) on other comprehensive income (loss)	(27)	33	(51)	14
Other comprehensive income (loss), net of tax	(16)	42	(37)	20
COMPREHENSIVE INCOME	172	235	457	260
Comprehensive income (loss) attributable to noncontrolling interest	1	(10)	1	(15)
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$ 171	$ 245	$ 456	$ 275

XML

Consolidated Statements of Income and Comprehensive Income (Unaudited) (Ohio Edison Company) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
REVENUES:
Excise and gross receipts tax collections	$ 107	$ 116	$ 228	$ 235
Total revenues	2,279	2,590	4,790	4,925
OPERATING EXPENSES:
Purchased power	1,156	1,220	2,503	2,406
Other operating expenses	914	1,065	1,726	2,058
Provision for depreciation	292	287	577	512
Amortization of regulatory assets, net	62	90	137	222
General taxes	232	242	504	479
Total operating expenses	3,312	3,539	6,644	6,765
OPERATING INCOME (LOSS)	557	521	1,303	871
OTHER INCOME (EXPENSE):
Investment income	13	31	24	52
Interest expense	(274)	(265)	(520)	(496)
Capitalized interest	19	20	36	38
Total other income (expense)	(242)	(214)	(460)	(406)
INCOME BEFORE INCOME TAXES	315	307	843	465
INCOME TAXES (BENEFITS)	127	114	349	225
NET INCOME	188	193	494	240
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	188	193	494	240
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(48)	48	(101)	4
Change in unrealized gain on available-for-sale securities	2	10	12	19
Other comprehensive income (loss)	(43)	75	(88)	34
Income taxes (benefits) on other comprehensive income (loss)	(27)	33	(51)	14
Other comprehensive income (loss), net of tax	(16)	42	(37)	20
COMPREHENSIVE INCOME	172	235	457	260
OE
REVENUES:
Electric sales	364	360	723	724
Excise and gross receipts tax collections	24	25	51	53
Total revenues	388	385	774	777
OPERATING EXPENSES:
Other operating expenses	119	106	240	202
Provision for depreciation	25	23	49	46
Amortization of regulatory assets, net	15	2	15	3
General taxes	46	46	96	95
Total operating expenses	309	309	626	632
OPERATING INCOME (LOSS)	79	76	148	145
OTHER INCOME (EXPENSE):
Investment income	5	4	9	9
Interest expense	(23)	(22)	(45)	(44)
Capitalized interest	1	1	2	1
Total other income (expense)	(17)	(17)	(34)	(34)
INCOME BEFORE INCOME TAXES	62	59	114	111
INCOME TAXES (BENEFITS)	21	18	42	38
NET INCOME	41	41	72	73
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	41	41	72	73
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(7)	(7)	(17)	(15)
Change in unrealized gain on available-for-sale securities	0	2	0	2
Other comprehensive income (loss)	(7)	(5)	(17)	(13)
Income taxes (benefits) on other comprehensive income (loss)	(4)	(3)	(9)	(7)
Other comprehensive income (loss), net of tax	(3)	(2)	(8)	(6)
COMPREHENSIVE INCOME	38	39	64	67
OE | Affiliates
OPERATING EXPENSES:
Purchased power	38	69	90	163
OE | Non-Affiliates
OPERATING EXPENSES:
Purchased power	$ 66	$ 63	$ 136	$ 123

XML

Consolidated Statements of Cash Flows (Unaudited) (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 494	$ 240
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	577	512
Nuclear fuel and lease amortization	106	92
Deferred rents and lease market valuation liability	(106)	(61)
Deferred income taxes and investment tax credits, net	423	598
Asset impairments	7	41
Accrued compensation and retirement benefits	(160)	(31)
Pension trust contribution	(600)	(262)
Commodity derivative transactions, net	(86)	(21)
Cash collateral, net	22	(31)
Decrease (increase) in operating assets-
Receivables	(105)	199
Materials and supplies	(109)	24
Prepayments and other current assets	(117)	(268)
Increase (decrease) in operating liabilities-
Accounts payable	(122)	(28)
Accrued taxes	(192)	(66)
Other	65	47
Net cash provided from operating activities	62	1,031
New financing-
Long-term debt	182	503
Short-term borrowings, net	1,890	0
Redemptions and Repayments-
Long-term debt	(746)	(1,002)
Other	(35)	(76)
Net cash provided from (used for) financing activities	831	(1,039)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,001)	(1,018)
Sales of investment securities held in trusts	382	1,703
Purchases of investment securities held in trusts	(420)	(1,807)
Other	(49)	(53)
Net cash used for investing activities	(1,001)	(535)
Net change in cash and cash equivalents	(108)	(543)
Cash and cash equivalents at beginning of period	202	1,019
Cash and cash equivalents at end of period	94	476
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	121	74
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	132	138
Nuclear fuel and lease amortization	103	92
Deferred rents and lease market valuation liability	(103)	(58)
Deferred income taxes and investment tax credits, net	162	138
Asset impairments	6	28
Gain on asset sales	(17)	0
Accrued compensation and retirement benefits	14	(24)
Pension trust contribution	(209)	0
Commodity derivative transactions, net	(53)	(60)
Cash collateral, net	17	(40)
Decrease (increase) in operating assets-
Receivables	0	(36)
Materials and supplies	(56)	50
Prepayments and other current assets	19	12
Increase (decrease) in operating liabilities-
Accounts payable	243	(124)
Accrued taxes	(167)	(29)
Other	7	21
Net cash provided from operating activities	219	182
New financing-
Long-term debt	82	247
Short-term borrowings, net	0	530
Redemptions and Repayments-
Long-term debt	(140)	(472)
Other	(6)	(11)
Net cash provided from (used for) financing activities	(64)	294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(303)	(334)
Proceeds from assets sale	17	0
Sales of investment securities held in trusts	109	513
Purchases of investment securities held in trusts	(127)	(545)
Loans to affiliated companies, net	155	(93)
Other	(6)	(20)
Net cash used for investing activities	(155)	(479)
Net change in cash and cash equivalents	0	(3)
Cash and cash equivalents at beginning of period	7	9
Cash and cash equivalents at end of period	$ 7	$ 6

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Income Taxes

6 Months Ended

Jun. 30, 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 second quarter of 2012, FirstEnergy reached a settlement with state authorities related to state apportionment factors in Pennsylvania on an intercompany asset sale, which favorably affected FirstEnergy's effective tax rate by $3 million in the three and six months ended June 30, 2012. Earlier in the year, 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 the 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 for the first six months of 2012. In the second quarter of 2011, FirstEnergy reached a settlement with the IRS on a research and development claim and recognized approximately $30 million of income tax benefits, including $5 million that favorably affected FirstEnergy's effective tax rate in the three and six months ended June 30, 2011.

As of June 30, 2012, it is reasonably possible that approximately $42 million of unrecognized income tax benefits may be resolved within the next twelve months, of which approximately $7 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 six months of 2012 there were no material changes to the amount of accrued interest. The interest associated with the settlement of the claim in 2011 noted above favorably affected FirstEnergy's effective tax rate by $6 million in the first six months of 2011. During the first six months of 2011, there were no other 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 June 30, 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 $28 million in the first six 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 2009 and 2010. 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.

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Consolidated Statements of Cash Flows (Unaudited) (Jersey Central Power & Light Company) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 494	$ 240
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	577	512
Amortization of regulatory assets, net	137	222
Deferred purchased power and other costs	(149)	(168)
Deferred income taxes and investment tax credits, net	423	598
Accrued compensation and retirement benefits	(160)	(31)
Pension trust contribution	(600)	(262)
Decrease (increase) in operating assets-
Receivables	(105)	199
Increase (decrease) in operating liabilities-
Accounts payable	(122)	(28)
Accrued taxes	(192)	(66)
Other	65	47
Net cash provided from operating activities	62	1,031
New financing-
Short-term borrowings, net	1,890	0
Redemptions and Repayments-
Long-term debt	(746)	(1,002)
Common stock dividend payments	(460)	(420)
Other	(35)	(76)
Net cash provided from (used for) financing activities	831	(1,039)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,001)	(1,018)
Sales of investment securities held in trusts	382	1,703
Purchases of investment securities held in trusts	(420)	(1,807)
Other	(49)	(53)
Net cash used for investing activities	(1,001)	(535)
Net change in cash and cash equivalents	(108)	(543)
Cash and cash equivalents at beginning of period	202	1,019
Cash and cash equivalents at end of period	94	476
JCP&L
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	65	68
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	62	54
Amortization of regulatory assets, net	28	122
Deferred purchased power and other costs	(75)	(71)
Deferred income taxes and investment tax credits, net	64	55
Accrued compensation and retirement benefits	(27)	(11)
Pension trust contribution	0	(105)
Decrease (increase) in operating assets-
Receivables	(10)	58
Prepaid taxes	(75)	(125)
Increase (decrease) in operating liabilities-
Accounts payable	(2)	14
Accrued taxes	(14)	(1)
Other	7	0
Net cash provided from operating activities	23	58
New financing-
Short-term borrowings, net	159	411
Redemptions and Repayments-
Long-term debt	(16)	(15)
Common stock dividend payments	(50)	(500)
Other	0	(1)
Net cash provided from (used for) financing activities	93	(105)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(102)	(98)
Loans to affiliated companies, net	0	161
Sales of investment securities held in trusts	165	376
Purchases of investment securities held in trusts	(172)	(386)
Other	(7)	(6)
Net cash used for investing activities	(116)	47
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 Cash Flows (Unaudited) (Ohio Edison Company) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 494	$ 240
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	577	512
Amortization of regulatory assets, net	137	222
Deferred income taxes and investment tax credits, net	423	598
Accrued compensation and retirement benefits	(160)	(31)
Pension trust contribution	(600)	(262)
Decrease (increase) in operating assets-
Receivables	(105)	199
Prepayments and other current assets	(117)	(268)
Increase (decrease) in operating liabilities-
Accounts payable	(122)	(28)
Accrued taxes	(192)	(66)
Accrued interest	(5)	(4)
Other	65	47
Net cash provided from operating activities	62	1,031
Redemptions and Repayments-
Long-term debt	(746)	(1,002)
Short-term borrowings, net	0	(44)
Common stock dividend payments	(460)	(420)
Other	(35)	(76)
Net cash provided from (used for) financing activities	831	(1,039)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,001)	(1,018)
Sales of investment securities held in trusts	382	1,703
Purchases of investment securities held in trusts	(420)	(1,807)
Cash investments	(87)	(50)
Other	(49)	(53)
Net cash used for investing activities	(1,001)	(535)
Net change in cash and cash equivalents	(108)	(543)
Cash and cash equivalents at beginning of period	202	1,019
Cash and cash equivalents at end of period	94	476
OE
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	72	73
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	49	46
Amortization of regulatory assets, net	15	3
Amortization of lease costs	(5)	(5)
Deferred income taxes and investment tax credits, net	22	66
Accrued compensation and retirement benefits	(26)	(18)
Pension trust contribution	0	(27)
Decrease (increase) in operating assets-
Receivables	54	81
Prepayments and other current assets	3	(29)
Increase (decrease) in operating liabilities-
Accounts payable	(27)	(22)
Accrued taxes	(12)	(9)
Accrued interest	3	0
Other	(2)	(9)
Net cash provided from operating activities	146	150
Redemptions and Repayments-
Long-term debt	(1)	(1)
Short-term borrowings, net	0	(142)
Common stock dividend payments	(25)	(268)
Other	(1)	(2)
Net cash provided from (used for) financing activities	(27)	(413)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(86)	(79)
Sales of investment securities held in trusts	57	20
Purchases of investment securities held in trusts	(62)	(25)
Loans to affiliated companies, net	(63)	(79)
Cash investments	(13)	(12)
Other	(4)	(6)
Net cash used for investing activities	(145)	(157)
Net change in cash and cash equivalents	(26)	(420)
Cash and cash equivalents at beginning of period	26	420
Cash and cash equivalents at end of period	$ 0	$ 0

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Derivative Instruments (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (305)	[1]	$ (362)	[1]	$ (301)	[1]	$ (335)	[1]
Additions/Change in value of existing contracts	(199)	[1]	(145)	[1]	(279)	[1]	(234)	[1]
Settled contracts	66	[1]	62	[1]	142	[1]	124	[1]
Outstanding net asset (liability), Ending Balance	(438)	[1]	(445)	[1]	(438)	[1]	(445)	[1]
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(300)	[1]	(362)	[1]	(293)	[1]	(345)	[1]
Additions/Change in value of existing contracts	(54)	[1]	(147)	[1]	(133)	[1]	(236)	[1]
Settled contracts	61	[1]	62	[1]	133	[1]	134	[1]
Outstanding net asset (liability), Ending Balance	(293)	[1]	(447)	[1]	(293)	[1]	(447)	[1]
LCAPP
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	0	[1]	0	[1]	0	[1]	0	[1]
Additions/Change in value of existing contracts	(145)	[1]	0	[1]	(145)	[1]	0	[1]
Settled contracts	0	[1]	0	[1]	0	[1]	0	[1]
Outstanding net asset (liability), Ending Balance	(145)	[1]	0	[1]	(145)	[1]	0	[1]
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(5)	[1]	0	[1]	(8)	[1]	0	[1]
Additions/Change in value of existing contracts	0	[1]	2	[1]	(1)	[1]	2	[1]
Settled contracts	5	[1]	0	[1]	9	[1]	0	[1]
Outstanding net asset (liability), Ending Balance	0	[1]	2	[1]	0	[1]	2	[1]
Other
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	0	[1]	0	[1]	0	[1]	10	[1]
Additions/Change in value of existing contracts	0	[1]	0	[1]	0	[1]	0	[1]
Settled contracts	0	[1]	0	[1]	0	[1]	(10)	[1]
Outstanding net asset (liability), Ending Balance	$ 0	[1]	$ 0	[1]	$ 0	[1]	$ 0	[1]

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

XML

Consolidated Balance Sheets (Unaudited) (Ohio Edison Company) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 202
Receivables-
Customers, net of allowance for uncollectible accounts	1,635	1,525
Other	263	269
Prepayments and other	171	122
Total current assets	3,608	3,355
UTILITY PLANT:
In service	41,167	40,122
Less - Accumulated provision for depreciation	12,336	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,831	28,283
Construction work in progress	1,937	2,054
Total net property, plant and equipment	30,768	30,337
OTHER PROPERTY AND INVESTMENTS:
Investments in lease obligation bonds	326	402
Nuclear plant decommissioning trusts	2,153	2,112
Other	1,039	1,008
Total other property and investments	3,518	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	2,122	2,030
Other	1,588	1,641
Total deferred charges and other assets	10,154	10,112
Total assets	48,048	47,326
CURRENT LIABILITIES:
Currently payable long-term debt	1,577	1,621
Accounts payable-
Accrued taxes	436	558
Other	617	900
Total current liabilities	6,082	4,855
Common stockholders' equity-
Common stock	42	42
Accumulated other comprehensive income	389	426
Retained earnings (Accumulated deficit)	3,310	3,047
Total common stockholders' equity	13,497	13,280
Noncontrolling interest	15	19
Total equity	13,512	13,299
Long-term debt and other long-term obligations	15,159	15,716
Total capitalization	28,671	29,015
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,042	5,670
Retirement benefits	2,257	2,823
Asset retirement obligations	1,548	1,497
Other	1,980	2,072
Total noncurrent liabilities	13,295	13,456
COMMITMENTS AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	48,048	47,326
OE
CURRENT ASSETS:
Cash and cash equivalents	0	26
Receivables-
Customers, net of allowance for uncollectible accounts	173	163
Affiliated companies	51	86
Other	15	41
Notes receivable from affiliated companies	245	181
Prepayments and other	14	17
Total current assets	498	514
UTILITY PLANT:
In service	3,443	3,358
Less - Accumulated provision for depreciation	1,294	1,267
Property, plant and equipment in service net of accumulated provision for depreciation	2,149	2,091
Construction work in progress	87	91
Total net property, plant and equipment	2,236	2,182
OTHER PROPERTY AND INVESTMENTS:
Investments in lease obligation bonds	148	163
Nuclear plant decommissioning trusts	141	137
Other	91	90
Total other property and investments	380	390
DEFERRED CHARGES AND OTHER ASSETS:
Regulatory assets	340	363
Property taxes	80	81
Unamortized sale and leaseback costs	23	25
Other	23	19
Total deferred charges and other assets	466	488
Total assets	3,580	3,574
CURRENT LIABILITIES:
Currently payable long-term debt	3	2
Accounts payable-
Affiliated companies	90	119
Other	37	35
Accrued taxes	76	88
Accrued interest	28	25
Other	69	79
Total current liabilities	303	348
Common stockholders' equity-
Common stock	721	747
Accumulated other comprehensive income	46	54
Retained earnings (Accumulated deficit)	(12)	(84)
Total common stockholders' equity	755	717
Noncontrolling interest	5	5
Total equity	760	722
Long-term debt and other long-term obligations	1,157	1,155
Total capitalization	1,917	1,877
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	799	787
Retirement benefits	211	213
Asset retirement obligations	74	71
Other	276	278
Total noncurrent liabilities	1,360	1,349
COMMITMENTS AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	$ 3,580	$ 3,574

XML

Consolidated Balance Sheets (Unaudited) (Ohio Edison Company) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	418,216,437	418,216,437
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
Customer [Member]
Receivables-
Allowance for uncollectible accounts	36	37
Customer [Member] | OE
Receivables-
Allowance for uncollectible accounts	4	4

XML

Consolidated Statements of Income and Comprehensive Income (Unaudited) (Jersey Central Power & Light Company) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
REVENUES:
Excise and gross receipts tax collections	$ 107	$ 116	$ 228	$ 235
Total revenues	2,279	2,590	4,790	4,925
OPERATING EXPENSES:
Purchased power	1,156	1,220	2,503	2,406
Other operating expenses	914	1,065	1,726	2,058
Provision for depreciation	292	287	577	512
Amortization of regulatory assets, net	62	90	137	222
General taxes	232	242	504	479
Total operating expenses	3,312	3,539	6,644	6,765
OPERATING INCOME (LOSS)	557	521	1,303	871
OTHER INCOME (EXPENSE):
Interest expense	(274)	(265)	(520)	(496)
Total other income (expense)	(242)	(214)	(460)	(406)
INCOME BEFORE INCOME TAXES	315	307	843	465
INCOME TAXES (BENEFITS)	127	114	349	225
NET INCOME	188	193	494	240
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	188	193	494	240
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(48)	48	(101)	4
Other comprehensive income (loss)	(43)	75	(88)	34
Income taxes (benefits) on other comprehensive income (loss)	(27)	33	(51)	14
Other comprehensive income (loss), net of tax	(16)	42	(37)	20
COMPREHENSIVE INCOME	172	235	457	260
JCP&L
REVENUES:
Electric sales	476	577	954	1,211
Excise and gross receipts tax collections	8	11	18	24
Total revenues	484	588	972	1,235
OPERATING EXPENSES:
Purchased power	254	328	518	698
Other operating expenses	81	73	162	153
Provision for depreciation	32	28	62	54
Amortization of regulatory assets, net	8	40	28	122
General taxes	12	15	27	33
Total operating expenses	387	484	797	1,060
OPERATING INCOME (LOSS)	97	104	175	175
OTHER INCOME (EXPENSE):
Miscellaneous income	1	3	2	5
Interest expense	(30)	(31)	(61)	(61)
Capitalized interest	1	1	1	1
Total other income (expense)	(28)	(27)	(58)	(55)
INCOME BEFORE INCOME TAXES	69	77	117	120
INCOME TAXES (BENEFITS)	30	32	52	52
NET INCOME	39	45	65	68
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	39	45	65	68
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(6)	(6)	(12)	(12)
Other comprehensive income (loss)	(6)	(6)	(12)	(12)
Income taxes (benefits) on other comprehensive income (loss)	(3)	(3)	(7)	(5)
Other comprehensive income (loss), net of tax	(3)	(3)	(5)	(7)
COMPREHENSIVE INCOME	$ 36	$ 42	$ 60	$ 61

XML

Commitments, Guarantees and Contingencies (Details Textuals) (USD $)	21 Months Ended								3 Months Ended			6 Months Ended		12 Months Ended		16 Months Ended	6 Months Ended		6 Months Ended		6 Months Ended		6 Months Ended						3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended		6 Months Ended					6 Months Ended
	Dec. 05, 2011 allegation aspect_of_opinion	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2012 FES	Dec. 31, 2011 FES	Jun. 30, 2012 JCP&L	Dec. 31, 2011 JCP&L	Jun. 30, 2012 AE Supply	Jun. 30, 2012 Signal Peak and Global Rail	Jun. 30, 2012 FGCO	Dec. 31, 2011 FGCO	Jun. 30, 2012 CAIR phases	Jun. 30, 2012 Clean Water Act	Dec. 31, 2010 Clean Water Act mi	Apr. 30, 2009 Clean Water Act aspect_of_opinion	Feb. 27, 2007 Clean Water Act FGCO spills	Jun. 30, 2012 Regulation of Waste Disposal options	Jun. 30, 2012 Regulation of Waste Disposal JCP&L	Jun. 30, 2012 Nuclear Plant Matters	Feb. 16, 2012 Nuclear Plant Matters NuclearPowerPlants	Jun. 30, 2012 ICG Litigation AE Supply	May 02, 2011 ICG Litigation AE Supply and MP	Jun. 30, 2012 Caa Compliance ElectricGenerationUnits CoalFiredPlants	Jun. 30, 2012 Caa Compliance FGCO Complaints	Jun. 30, 2012 Caa Compliance Claim One FGCO IndividualsInAComplaint Complaints	Jun. 30, 2012 Caa Compliance Claim Two FGCO plantiffs	Jun. 30, 2012 National Ambient Air Quality Standards T	Jun. 30, 2012 National Ambient Air Quality Standards CSAPR phases	Jun. 30, 2012 Hazardous Air Pollutant Emissions MW CoalFiredPlants	Jun. 30, 2012 Hazardous Air Pollutant Emissions MW CoalFiredPlants	Jun. 30, 2012 Hazardous Air Pollutant Emissions FES	Jun. 30, 2012 Hazardous Air Pollutant Emissions FES	Mar. 08, 2012 Hazardous Air Pollutant Emissions FGCO MW	Jun. 30, 2012 Climate Change celsius	Jan. 02, 2011 Climate Change T	Jun. 30, 2012 Parental Guarantees	Jun. 30, 2012 Subsidiaries' Guarantees	Jun. 30, 2012 Other Guarantees	Jun. 30, 2012 Year 2020 Climate Change Increase in funding	Jun. 30, 2012 Regulated Distribution	Jul. 13, 2012 Plant Deactivation WEST VIRGINIA plant	Jul. 13, 2012 Plant Deactivation WEST VIRGINIA Hazardous Air Pollutant Emissions plant
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated		$ 4,100,000,000																																		$ 900,000,000	$ 2,400,000,000	$ 700,000,000
Maximum exposure under collateral provisions		804,000,000		658,000,000				73,000,000
Company Posted Collateral Related To Net Liability Positions				36,000,000																																				9,000,000
Potential Collateral Posted Related to Net Liability Positions				46,000,000				13,000,000
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	1
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	9
Megwatt Capacity for Retired Coal-Fired Power Plants																													3,349	3,349
Average percentage of power generation of retired coal-fired power plants																													10.00%	10.00%
Potential cost of compliance, MATS																													975,000,000	975,000,000
Measurement period for power generation of retired coal-fired power plants																													3 years	3 years
Commitment Period by Developed Countries to Provide Funds, Years																																		3 years
Aspects of Opinion, Reversed															1
Petroleum Spills																3
Megawatt capacity for proposed combusion turbine																																	832
Number of approved plant deactivations																																									3	3
Pre-tax severance expense related to closures																													10,000,000	17,000,000	6,000,000	10,000,000
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
Claims Resolution, Civil Penalties																	800,000
Options proposed by EPA for additional regulation of coal combustion residuals																	2
Total environmental liabilities																	122,000,000	86,000,000
Environmental Liabilities Former Gas Facilities																	79,000,000
Decommissioning Fund Investments		2,153,000,000	2,112,000,000	1,250,000,000	1,223,000,000	196,000,000	193,000,000			0	0								2,000,000,000
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
Potential MATS Extension Period																													1 year
Number of allegations remanded to trial court	1
Aspects of opinion under appeal	1

XML

Supplemental Guarantor Information (Details 1) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011	Jun. 30, 2011	Dec. 31, 2010
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 202	$ 476	$ 1,019
Receivables-
Customers	1,635	1,525
Other	263	269
Materials and supplies, at average cost	921	811
Derivatives	276	235
Prepayments and other	171	122
Total current assets	3,608	3,355
PROPERTY, PLANT AND EQUIPMENT:
In service	41,167	40,122
Less - Accumulated provision for depreciation	12,336	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,831	28,283
Construction work in progress	1,937	2,054
Total net property, plant and equipment	30,768	30,337
INVESTMENTS:
Nuclear plant decommissioning trusts	2,153	2,112
Other	1,039	1,008
Total other property and investments	3,518	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444	6,441	6,436
Other	1,588	1,641
Total deferred charges and other assets	10,154	10,112
Total assets	48,048	47,326	47,596
CURRENT LIABILITIES:
Currently payable long-term debt	1,577	1,621
Short-term borrowings-
Affiliated companies	1,890	0
Accounts payable-
Accrued Taxes	436	558
Derivatives	222	218
Other	617	900
Total current liabilities	6,082	4,855
CAPITALIZATION:
Total equity	13,497	13,280
Long-term debt and other long-term obligations	15,159	15,716
Total capitalization	28,671	29,015
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	909	925
Accumulated deferred income taxes	6,042	5,670
Asset retirement obligations	1,548	1,497
Retirement benefits	2,257	2,823
Other	1,980	2,072
Total noncurrent liabilities	13,295	13,456
Total liabilities and capitalization	48,048	47,326
FES Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	457	424
Affiliated companies	464	476
Other	67	28
Notes receivable from affiliated companies	155	155
Materials and supplies, at average cost	68	60
Derivatives	265	219
Prepayments and other	3	11
Total current assets	1,479	1,373
PROPERTY, PLANT AND EQUIPMENT:
In service	89	84
Less - Accumulated provision for depreciation	30	28
Property, plant and equipment in service net of accumulated provision for depreciation	59	56
Construction work in progress	28	29
Total net property, plant and equipment	87	85
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	6,241	5,700
Other	0	0
Total other property and investments	6,241	5,700
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	10
Customer intangibles	118	123
Goodwill	24	24
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	110	79
Other	86	89
Total deferred charges and other assets	338	325
Total assets	8,145	7,483
CURRENT LIABILITIES:
Currently payable long-term debt	1	1
Accounts payable-
Affiliated companies	739	777
Other	173	99
Accrued Taxes	23	84
Derivatives	219	189
Other	68	62
Total current liabilities	2,820	2,277
CAPITALIZATION:
Total equity	3,704	3,577
Long-term debt and other long-term obligations	1,482	1,483
Total capitalization	5,186	5,060
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	28	12
Asset retirement obligations	0	0
Retirement benefits	34	56
Lease market valuation liability	0	0
Other	77	78
Total noncurrent liabilities	139	146
Total liabilities and capitalization	8,145	7,483
FGCO
CURRENT ASSETS:
Cash and cash equivalents	7	7	6	9
Receivables-
Customers	0	0
Affiliated companies	482	643
Other	25	20
Notes receivable from affiliated companies	1,653	1,346
Materials and supplies, at average cost	272	232
Derivatives	0	0
Prepayments and other	15	26
Total current assets	2,454	2,274
PROPERTY, PLANT AND EQUIPMENT:
In service	5,620	5,573
Less - Accumulated provision for depreciation	1,872	1,813
Property, plant and equipment in service net of accumulated provision for depreciation	3,748	3,760
Construction work in progress	187	195
Total net property, plant and equipment	3,935	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	261	307
Customer intangibles		0
Goodwill		0
Property taxes	20	20
Unamortized sale and leaseback costs	4	5
Derivatives		0
Other	160	99
Total deferred charges and other assets	445	431
Total assets	6,841	6,667
CURRENT LIABILITIES:
Currently payable long-term debt	646	411
Accounts payable-
Affiliated companies	279	228
Other	133	121
Accrued Taxes	20	42
Derivatives	0	0
Other	124	141
Total current liabilities	1,337	1,032
CAPITALIZATION:
Total equity	3,413	3,097
Long-term debt and other long-term obligations	1,657	1,905
Total capitalization	5,070	5,002
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	29	28
Retirement benefits	145	300
Lease market valuation liability	148	171
Other	112	134
Total noncurrent liabilities	434	633
Total liabilities and capitalization	6,841	6,667
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	297	262
Other	4	13
Notes receivable from affiliated companies	152	69
Materials and supplies, at average cost	208	200
Derivatives	0	0
Prepayments and other	1	1
Total current assets	662	545
PROPERTY, PLANT AND EQUIPMENT:
In service	6,051	5,711
Less - Accumulated provision for depreciation	2,594	2,449
Property, plant and equipment in service net of accumulated provision for depreciation	3,457	3,262
Construction work in progress	704	790
Total net property, plant and equipment	4,161	4,052
INVESTMENTS:
Nuclear plant decommissioning trusts	1,250	1,223
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,250	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	1	3
Total deferred charges and other assets	24	26
Total assets	6,097	5,846
CURRENT LIABILITIES:
Currently payable long-term debt	518	513
Accounts payable-
Affiliated companies	305	211
Other	0	0
Accrued Taxes	27	110
Derivatives	0	0
Other	13	16
Total current liabilities	863	882
CAPITALIZATION:
Total equity	2,810	2,587
Long-term debt and other long-term obligations	580	641
Total capitalization	3,390	3,228
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	572	510
Asset retirement obligations	905	876
Retirement benefits	0	0
Lease market valuation liability	0	0
Other	367	350
Total noncurrent liabilities	1,844	1,736
Total liabilities and capitalization	6,097	5,846
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(706)	(781)
Other	0	0
Notes receivable from affiliated companies	(1,732)	(1,187)
Materials and supplies, at average cost	0	0
Derivatives	0	0
Prepayments and other	0	0
Total current assets	(2,438)	(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	(6,241)	(5,700)
Other	0	0
Total other property and investments	(6,241)	(5,700)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(261)	(317)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	114	75
Derivatives	0	0
Other	(110)	(62)
Total deferred charges and other assets	(257)	(304)
Total assets	(9,139)	(8,177)
CURRENT LIABILITIES:
Currently payable long-term debt	(21)	(20)
Accounts payable-
Affiliated companies	(715)	(780)
Other	0	0
Accrued Taxes	(8)	(9)
Derivatives	0	0
Other	37	42
Total current liabilities	(2,439)	(1,953)
CAPITALIZATION:
Total equity	(6,223)	(5,684)
Long-term debt and other long-term obligations	(1,219)	(1,230)
Total capitalization	(7,442)	(6,914)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	909	925
Accumulated deferred income taxes	(164)	(236)
Asset retirement obligations	0	0
Retirement benefits	0	0
Lease market valuation liability	0	0
Other	(3)	1
Total noncurrent liabilities	742	690
Total liabilities and capitalization	(9,139)	(8,177)
FES
CURRENT ASSETS:
Cash and cash equivalents	7	7	6	9
Receivables-
Customers	457	424
Affiliated companies	537	600
Other	96	61
Notes receivable from affiliated companies	228	383
Materials and supplies, at average cost	548	492
Derivatives	265	219
Prepayments and other	19	38
Total current assets	2,157	2,224
PROPERTY, PLANT AND EQUIPMENT:
In service	11,375	10,983
Less - Accumulated provision for depreciation	4,314	4,110
Property, plant and equipment in service net of accumulated provision for depreciation	7,061	6,873
Construction work in progress	919	1,014
Total net property, plant and equipment	7,980	7,887
INVESTMENTS:
Nuclear plant decommissioning trusts	1,250	1,223
Investment in affiliated companies	0	0
Other	7	7
Total other property and investments	1,257	1,230
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	118	123
Goodwill	24	24
Property taxes	43	43
Unamortized sale and leaseback costs	118	80
Derivatives	110	79
Other	137	129
Total deferred charges and other assets	550	478
Total assets	11,944	11,819
CURRENT LIABILITIES:
Currently payable long-term debt	1,144	905
Accounts payable-
Affiliated companies	608	436
Other	306	220
Accrued Taxes	62	227
Derivatives	219	189
Other	242	261
Total current liabilities	2,581	2,238
CAPITALIZATION:
Total equity	3,704	3,577
Long-term debt and other long-term obligations	2,500	2,799
Total capitalization	6,204	6,376
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	909	925
Accumulated deferred income taxes	436	286
Asset retirement obligations	934	904
Retirement benefits	179	356
Lease market valuation liability	148	171
Other	553	563
Total noncurrent liabilities	3,159	3,205
Total liabilities and capitalization	11,944	11,819
Affiliates | FES Corp
Short-term borrowings-
Affiliated companies	1,597	1,065
Affiliates | FGCO
Short-term borrowings-
Affiliated companies	135	89
Affiliates | Nuclear Generation Corp
Short-term borrowings-
Affiliated companies	0	32
Affiliates | Eliminations
Short-term borrowings-
Affiliated companies	(1,732)	(1,186)
Affiliates | FES
Short-term borrowings-
Affiliated companies	$ 0	$ 0

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Commitments, Guarantees and Contingencies (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 804
Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	419
BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	494
FES
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	658
FES | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	373
FES | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	429
AE Supply
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	73
AE Supply | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	6
AE Supply | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	6
Utilities
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	73
Utilities | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	40
Utilities | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 59

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Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 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 June 30, 2012:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,318	$	1,111	$	207
OE	574		384		190
Other FE subsidiaries	599		333		266

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.5 billion.

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Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	Jun. 30, 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	$ 2,032	[1]	$ 1,980	[2]
Unrealized Gains	52	[1]	25	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	2,084	[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	243	[1]	222	[2]
Unrealized Gains	36	[1]	36	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	279	[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	1,034	[1]	1,012	[2]
Unrealized Gains	29	[1]	13	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	1,063	[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	125	[1]	104	[2]
Unrealized Gains	19	[1]	20	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	144	[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	138	[1]	134	[2]
Unrealized Gains	0	[1]	0	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	138	[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	358	[1]	356	[2]
Unrealized Gains	12	[1]	7	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	370	[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	3	[1]	3	[2]
Unrealized Losses	0	[1]	0	[2]
Fair Value	$ 30	[1]	$ 30	[2]

[1] Excludes short-term cash investments: FE Consolidated - $113 million; FES - $42 million; OE - $3 million; JCP&L - $23 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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Earnings Per Share

6 Months Ended

Jun. 30, 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 June 30				Six Months Ended June 30
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2012		2011		2012		2011
	(In millions, except per share amounts)
Weighted average number of basic shares outstanding	417		418		418		380
Assumed exercise of dilutive stock options and awards(1)	2		2		1		2
Weighted average number of diluted shares outstanding	419		420		419		382
Earnings Available to FirstEnergy Corp.	$	187	$	203	$	493	$	255
Basic earnings per share of common stock	$	0.45	$	0.48	$	1.18	$	0.67
Diluted earnings per share of common stock	$	0.45	$	0.48	$	1.18	$	0.67

⁽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 and six months ended June 30, 2012 and 2011.

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Derivative Instruments

6 Months Ended

Jun. 30, 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.

Total net unamortized gains included in AOCI associated with de-designated cash flow hedges totaled $15 million and $19 million as of June 30, 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 $1 million and $14 million during the three months ended June 30, 2012 and 2011, respectively, and $4 million and $19 million during the six months ended June 30, 2012 and 2011, respectively. Approximately $9 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 June 30, 2012, no forward starting swap agreements accounted for as a cash flow hedge were outstanding. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $74 million as of June 30, 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 June 30, 2012 and 2011, respectively, and $5 million and $6 million during the six months ended June 30, 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 June 30, 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 $91 million as of June 30, 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 during the three months ended June 30, 2012 and 2011, and $11 million during the six months ended June 30, 2012 and 2011.

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 June 30, 2012, FirstEnergy’s net asset position under commodity derivative contracts was $78 million, which related to FES and AE Supply positions. Under these commodity derivative contracts, FES posted $34 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $12 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 June 30, 2012, an adverse 10% change in commodity prices would decrease net income by approximately $2 million during the next twelve months.

Interest Rate Swaps

FirstEnergy uses forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives are considered economic hedges, protecting against the risk of increases in future interest payments resulting from increases in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. During the three months ended June 30, 2012, FirstEnergy executed forward starting swap agreements expiring December 31, 2013, with sixteen separate counterparties for a combined notional value of $1.6 billion in order to lock in interest rates on planned debt issuances, which includes refinancings. The total portfolio of swaps carries a weighted average 10-year fixed rate of 2.315%. Changes in the fair value of the forward starting swap agreements are recorded in net income on a mark-to-market basis.

LCAPP

The LCAPP law was enacted in New Jersey during 2011 to promote the construction of qualified electric generation facilities. JCP&L maintains two LCAPP contracts, which are financially settled agreements that allow eligible generators to receive payments from, or make payments to, JCP&L pursuant to an annually calculated load-ratio share of the capacity produced by the generator based upon the annual forecasted peak demand as determined by PJM. During the second quarter of 2012, JCP&L began to account for these contracts as derivatives as a result of the generators clearing the 2015/2016 PJM RPM capacity auction. JCP&L expects to recover from its customers payments made to the generators and give credit to customers for payments from the generators under these contracts. As a result, the projected future obligations for the LCAPP contracts are reflected on the Consolidated Balance Sheets as derivative liabilities (assets) with a corresponding regulatory asset (liability). Since the LCAPP contracts are subject to regulatory accounting, changes in their fair value do not impact earnings.

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
	June 30, 2012		December 31, 2011			June 30, 2012			December 31, 2011
	(In millions)					(In millions)
Power Contracts					Power Contracts
Current Assets	$	232	$	185	Current Liabilities	$	(213	)	$	(196	)
Noncurrent Assets	106		79		Noncurrent Liabilities	(49		)	(51		)
FTRs					FTRs
Current Assets	12		1		Current Liabilities	(8		)	(22		)
Noncurrent Assets	—		—		Noncurrent Liabilities	(1		)	(1		)
NUGs	9		56		NUGs	(302		)	(349		)
LCAPP	—		—		LCAPP	(145		)	—
Interest Rate Swaps					Interest Rate Swaps
Noncurrent Assets	3		—		Noncurrent Liabilities	(23		)	—
Other					Other
Current Assets	4		—		Current Liabilities	(1		)	—
	$	366	$	321		$	(742	)	$	(619	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of June 30, 2012:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	29	40	(11	)	MWH
FTRs	82	—	82		MWH
Interest Rate Swaps	1,600	—	1,600		notional dollars
NUGs	22	—	22		MWH
LCAPP	408	—	408		MW
Natural Gas	26	—	26		Million BTUs

The effect of derivative instruments on the Consolidated Statements of Income during the three months ended June 30, 2012 and 2011, are summarized in the following tables:

	Three Months Ended June 30
	Power Contracts			FTRs			Interest Rate Swaps			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	1		$	—		$	—		$	—		$	1
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	14		$	—		$	—		$	—		$	14
Derivatives Not in a Hedging Relationship
2012
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	7		$	12		$	—		$	5		$	24
Interest Expense	—			—			(20		)	—			(20		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(104	)	$	—		$	—		$	—		$	(104	)
Revenues	95			5			—			—			100
Other Operating Expense	—			(18		)	—			—			(18		)
Fuel Expense	—			—			—			(1		)	(1		)
Interest Expense	—			—			—			—			—
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	33		$	—		$	—		$	—		$	33
Revenues	(4		)	—			—			—			(4		)
Other Operating Expense	(34		)	11			—			—			(23		)
Interest Expense	—			—			—			—			—
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	1		$	—		$	—		$	—		$	1
Revenues	(39		)	13			—			—			(26		)
Other Operating Expense	—			(40		)	—			—			(40		)
Interest Expense	—			—			—			—			—

	Six Months Ended June 30
	Power Contracts			FTRs			Interest Rate Swaps			Other			Total
	(In millions)
Derivatives in a Hedging Relationship
2012
Gain (Loss) Recognized in AOCI (Effective Portion)	$	(4	)	$	—		$	—		$	—		$	(4	)
2011
Gain (Loss) Recognized in AOCI (Effective Portion)	$	5		$	—		$	—		$	—		$	5
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:
Other Operating Expense	$	62		$	17		$	—		$	3		$	82
Interest Expense	—			—			(20		)	—			(20		)
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(221	)	$	—		$	—		$	—		$	(221	)
Revenues	206			11			—			—			217
Other Operating Expense	—			(41		)	—			—			(41		)
Fuel Expense	—			—			—			(1		)	(1		)
Interest Expense	—			—			—			—			—
2011
Unrealized Gain (Loss) Recognized in:
Purchased Power Expense	$	61		$	—		$	—		$	—		$	61
Revenues	(3		)	—			—			—			(3		)
Other Operating Expense	(54		)	12			1			—			(41		)
Interest Expense	—			—			—			—			—
Realized Gain (Loss) Reclassified to:
Purchased Power Expense	$	(36	)	$	—		$	—		$	—		$	(36	)
Revenues	(29		)	16			(1		)	—			(14		)
Other Operating Expense	—			(54		)	—			—			(54		)
Interest Expense	—			—			—			—			—

The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and six months ended June 30, 2012 and 2011, are summarized in the following tables:

	Three Months Ended June 30
	NUGs			LCAPP			Regulated FTRs		Other		Total
	(In millions)
Derivatives Not in a Hedging Relationship with Regulatory Offset
2012
Unrealized Gain (Loss) to Derivative Instrument	$	(54	)	$	(145	)	$	—	$	—	$	(199	)
Realized Gain (Loss) to Derivative Instrument	61			—			5		—		66
2011
Unrealized Gain (Loss) to Derivative Instrument	$	(147	)	$	—		$	2	$	—	$	(145	)
Realized Gain (Loss) to Derivative Instrument	62			—			—		—		62

	Six Months Ended June 30
	NUGs			LCAPP			Regulated FTRs			Other		Total
	(In millions)
Derivatives Not in a Hedging Relationship with Regulatory Offset
2012
Unrealized Gain (Loss) to Derivative Instrument	$	(133	)	$	(145	)	$	(1	)	$	—	$	(279	)
Realized Gain (Loss) to Derivative Instrument	133			—			9			—		142
2011
Unrealized Gain (Loss) to Derivative Instrument	$	(236	)	$	—		$	2		$	—	$	(234	)
Realized Gain (Loss) to Derivative Instrument	134			—			(10		)	—		124

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 and six months ended June 30, 2012 and 2011:

	Three Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			LCAPP			Regulated FTRs			Other		Total
	(In millions)
Outstanding net asset (liability) as of April 1, 2012	$	(300	)	$	—		$	(5	)	$	—	$	(305	)
Additions/Change in value of existing contracts	(54		)	(145		)	—			—		(199		)
Settled contracts	61			—			5			—		66
Outstanding net asset (liability) as of June 30, 2012	$	(293	)	$	(145	)	$	—		$	—	$	(438	)
Outstanding net asset (liability) as of April 1, 2011	$	(362	)	$	—		$	—		$	—	$	(362	)
Additions/Change in value of existing contracts	(147		)	—			2			—		(145		)
Settled contracts	62			—			—			—		62
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	—		$	2		$	—	$	(445	)

	Six Months Ended June 30
Derivatives Not in a Hedging Relationship with Regulatory Offset(1)	NUGs			LCAPP			Regulated FTRs			Other			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2012	$	(293	)	$	—		$	(8	)	$	—		$	(301	)
Additions/Change in value of existing contracts	(133		)	(145		)	(1		)	—			(279		)
Settled contracts	133			—			9			—			142
Outstanding net asset (liability) as of June 30, 2012	$	(293	)	$	(145	)	$	—		$	—		$	(438	)
Outstanding net asset (liability) as of January 1, 2011	$	(345	)	$	—		$	—		$	10		$	(335	)
Additions/Change in value of existing contracts	(236		)	—			2			—			(234		)
Settled contracts	134			—			—			(10		)	124
Outstanding net asset (liability) as of June 30, 2011	$	(447	)	$	—		$	2		$	—		$	(445	)

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

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Fair Value Measurements (Details 1) (USD $) In Millions, unless otherwise specified	6 Months Ended		12 Months Ended
	Jun. 30, 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	(48)	[1]	(58)	[1]
Unrealized gain (loss), Derivative Liability	(86)	[1]	(144)	[1]
Unrealized gain (loss), Derivative total	(134)	[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	0	[1]	(7)	[1]
Settlements, Derivative Liability	133	[1]	261	[1]
Settlements, Derivative Asset and Liability, total	133	[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	9	[1]	57	[1]
Ending Balance, Derivative Liability	(302)	[1]	(349)	[1]
Ending Balance, Derivative, Total	(293)	[1]	(292)	[1]
Non Utility Generation contract | JCP&L
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	4	[1]	6	[1]
Beginning Balance, Derivative Liability	(147)	[1]	(233)	[1]
Beginning Balance, Derivative, Total	(143)	[1]	(227)	[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	(7)	[1]	(11)	[1]
Unrealized gain (loss), Derivative total	(7)	[1]	(13)	[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	0	[1]	0	[1]
Settlements, Derivative Liability	29	[1]	97	[1]
Settlements, Derivative Asset and Liability, total	29	[1]	97	[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	4	[1]	4	[1]
Ending Balance, Derivative Liability	(125)	[1]	(147)	[1]
Ending Balance, Derivative, Total	(121)	[1]	(143)	[1]
LCAPP Contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	0	[1]
Beginning Balance, Derivative Liability	0	[1]
Beginning Balance, Derivative, Total	0	[1]	0	[1]
Realized gain (loss), Derivative Total	0	[1]	0	[1]
Unrealized gain (loss), Derivative total	0	[1]	0	[1]
Purchases, Derivative Asset and Liability, total	(145)	[1]	0	[1]
Issuances, Derivative Asset and Liability, total	0	[1]	0	[1]
Sales, Derivative Asset and Liability, total	0	[1]	0	[1]
Settlements, Derivative Asset and Liability, total	0	[1]	0	[1]
Transfers into Level 3, Derivative Asset and Liability, total	0	[1]	0	[1]
Ending Balance, Derivative Asset	0	[1]	0	[1]
Ending Balance, Derivative Liability	(145)	[1]	0	[1]
Ending Balance, Derivative, Total			0	[1]
LCAPP Contracts | JCP&L
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	0	[1]	0	[1]
Beginning Balance, Derivative Liability	0	[1]	0	[1]
Beginning Balance, Derivative, Total	0	[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]	0	[1]
Unrealized gain (loss), Derivative Liability	0	[1]	0	[1]
Unrealized gain (loss), Derivative total	0	[1]	0	[1]
Purchases, Derivative Asset	0	[1]	0	[1]
Purchases, Derivative Liability	(145)	[1]	0	[1]
Purchases, Derivative Asset and Liability, total	(145)	[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	0	[1]	0	[1]
Settlements, Derivative Liability	0	[1]	0	[1]
Settlements, Derivative Asset and Liability, total	0	[1]	0	[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	0	[1]	0	[1]
Ending Balance, Derivative Liability	(145)	[1]	0	[1]
Ending Balance, Derivative, Total	(145)	[1]	0	[1]
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Asset	1		0
Beginning Balance, Derivative Liability	(23)		0
Beginning Balance, Derivative, Total	(22)		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		2
Unrealized gain (loss), Derivative Liability	(2)		(27)
Unrealized gain (loss), Derivative total	(2)		(25)
Purchases, Derivative Asset	12		13
Purchases, Derivative Liability	(9)		(4)
Purchases, Derivative Asset and Liability, total	3		9
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	(1)		(14)
Settlements, Derivative Liability	25		20
Settlements, Derivative Asset and Liability, total	24		6
Transfers into Level 3, Derivative Asset	0		0
Transfers into Level 3, Derivative Liability	0		(12)
Transfers into Level 3, Derivative Asset and Liability, total	0		(12)
Ending Balance, Derivative Asset	12		1
Ending Balance, Derivative Liability	(9)		(23)
Ending Balance, Derivative, Total	3		(22)
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	8		2
Purchases, Derivative Liability	(7)		(1)
Purchases, Derivative Asset and Liability, total	1		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	(1)		(5)
Settlements, Derivative Liability	9		2
Settlements, Derivative Asset and Liability, total	8		(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	8		1
Ending Balance, Derivative Liability	(6)		(7)
Ending Balance, Derivative, Total	$ 2		$ (6)

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

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Earnings Per Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				6 Months Ended
	Jun. 30, 2012		Jun. 30, 2011		Jun. 30, 2012		Jun. 30, 2011
Reconciliation of basic and diluted earnings per share of common stock
Weighted average number of basic shares outstanding	417		418		418		380
Assumed exercise of dilutive stock options and awards	2	[1]	2	[1]	1	[1]	2	[1]
Weighted average number of diluted shares outstanding	419		420		419		382
Earnings available to FirstEnergy Corp.	$ 187		$ 203		$ 493		$ 255
Basic Earnings Per Share of Common Stock, in dollars per share	$ 0.45		$ 0.48		$ 1.18		$ 0.67
Diluted Earnings Per Share of Common Stock, in dollars per share	$ 0.45		$ 0.48		$ 1.18		$ 0.67

[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 and six months ended June 30, 2012 and 2011.

XML

Consolidated Balance Sheets (Unaudited) (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 94	$ 202
Receivables-
Customers, net of allowance for uncollectible accounts	1,635	1,525
Other, net of allowance for uncollectible accounts	263	269
Materials and supplies	921	811
Prepaid taxes	248	191
Derivatives	276	235
Other	171	122
Total current assets	3,608	3,355
In service	41,167	40,122
PROPERTY, PLANT AND EQUIPMENT:
Less - Accumulated provision for depreciation	12,336	11,839
Property, plant and equipment in service net of accumulated provision for depreciation	28,831	28,283
Construction work in progress	1,937	2,054
Total net property, plant and equipment	30,768	30,337
INVESTMENTS:
Nuclear plant decommissioning trusts	2,153	2,112
Investments in lease obligation bonds	326	402
Other	1,039	1,008
Total other property and investments	3,518	3,522
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,444	6,441
Regulatory assets	2,122	2,030
Other	1,588	1,641
Total deferred charges and other assets	10,154	10,112
Total assets	48,048	47,326
CURRENT LIABILITIES:
Currently payable long-term debt	1,577	1,621
Short-term borrowings	1,890	0
Accounts payable	1,052	1,174
Accrued taxes	436	558
Accrued compensation and benefits	288	384
Derivatives	222	218
Other	617	900
Total current liabilities	6,082	4,855
Common stockholders' equity-
Common stock	42	42
Other paid-in capital	9,756	9,765
Accumulated other comprehensive income	389	426
Retained earnings (Accumulated deficit)	3,310	3,047
Total common stockholders' equity	13,497	13,280
Noncontrolling interest	15	19
Total equity	13,512	13,299
Long-term debt and other long-term obligations	15,159	15,716
Total capitalization	28,671	29,015
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,042	5,670
Retirement benefits	2,257	2,823
Asset retirement obligations	1,548	1,497
Deferred gain on sale and leaseback transaction	909	925
Adverse power contract liability	559	469
Other	1,980	2,072
Total noncurrent liabilities	13,295	13,456
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 9)
Total liabilities and capitalization	$ 48,048	$ 47,326

XML

Consolidated Balance Sheets (Unaudited) (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Jun. 30, 2012	Dec. 31, 2011
Common stockholders' equity-
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	36	37
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts	2	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 Receivables [Member]
Receivables-
Allowance for uncollectible accounts	2	3

XML

Derivative Instruments (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2012	Jun. 30, 2011	Jun. 30, 2012	Jun. 30, 2011
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)	$ 1	$ 14
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
Interest rate swaps
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
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
Designated as Hedging Instrument [Member]
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)	1	14	(4)	5
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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)
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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)			(4)	5
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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)
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | Interest rate swaps
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
Designated as Hedging Instrument [Member] | Interest rate swaps | 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
Designated as Hedging Instrument [Member] | Interest rate swaps | 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
Designated as Hedging Instrument [Member] | Interest rate swaps | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Designated as Hedging Instrument [Member] | 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
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		33		61
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(104)	1	(221)	(36)
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		(4)		(3)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	100	(26)	217	(14)
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(1)		(1)
Not Designated as Hedging Instrument [Member] | 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:	24	(23)	82	(41)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(18)	(40)	(41)	(54)
Not Designated as Hedging Instrument [Member] | Interest 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:	(20)	0	(20)	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		33		61
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(104)	1	(221)	(36)
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		(4)		(3)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	95	(39)	206	(29)
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0		0
Not Designated as Hedging Instrument [Member] | 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:	7	(34)	62	(54)
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | Power Contracts | Interest 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:	0	0	0	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		0		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		0		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	5	13	11	16
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0		0
Not Designated as Hedging Instrument [Member] | 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:	12	11	17	12
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(18)	(40)	(41)	(54)
Not Designated as Hedging Instrument [Member] | FTRs | Interest 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:	0	0	0	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | Interest rate swaps | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		0		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | Interest rate swaps | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		0		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	(1)
Not Designated as Hedging Instrument [Member] | Interest rate swaps | 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
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0		0
Not Designated as Hedging Instrument [Member] | Interest rate swaps | 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:	0	0	0	1
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | Interest rate swaps | Interest 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:	(20)	0	(20)	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		0		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Unrealized Gain (Loss) Recognized in:		0		0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | 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
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	(1)		(1)
Not Designated as Hedging Instrument [Member] | 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:	5	0	3	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	0	0	0	0
Not Designated as Hedging Instrument [Member] | Other | Interest 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:	0	0	0	0
Not in a Hedging Relationship; Realized Gain (Loss) Reclassified to:	$ 0	$ 0	$ 0	$ 0

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Segment Information (Details Textuals)	6 Months Ended
	Jun. 30, 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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Regulatory Matters

6 Months Ended

Jun. 30, 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.

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, on August 31, 2011, PE filed a new comprehensive plan that includes additional and improved programs for the period 2012-2014.The plan is expected to cost approximately$66 millionover the three-year period.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.In its written Order issued July 31, 2012, affirming the determination made at its July 18, 2012 agenda meeting, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that the Company is investing sufficiently to assure the provision of safe, adequate and proper utility service to its customers" and ordered JCP&L to file a base rate case using a historical 2011 test year on or before November 1, 2012. JCP&L is unable to predict the outcome of this matter.

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 August 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.

On April 13, 2012, the Ohio Companies filed an application with the PUCO to essentially extend the terms of their current ESP for two years. The ESP 3 Application was approved by the PUCO on July 18, 2012.

As approved, the ESP 3 plan will 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 power to shopping and to non-shopping customers as part of the 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 approved, the ESP 3 plan will provide additional new benefits, including:

• Securing generation supply for a longer period of time by conducting an auction for a three-year period rather than a one-year period, in October 2012 and January 2013, 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 3 period. This is expected to initially reduce the monthly renewable energy charge for all FirstEnergy Ohio non-shopping utility customers by spreading out the costs over the entire ESP period.

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).Sevenadditional parties agreed not to oppose the filing.

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 approximately1,211GWHs in 2012 (an increase of416,000MWHs over 2011 levels),1,726GWHs in 2013,2,306GWHs in 2014 and2,903GWHs for each year thereafter 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 intended to implement to meet the energy efficiency and peak demand reduction requirements for the 2010-2012 period. In March 2011, the PUCO issued an Opinion and Order generally approving the Ohio Companies' 2010-2012 portfolio plan which provides for recovery of all costs associated with the programs, including lost revenues. The Ohio Companies have implemented those programs included in the plan. However, due to the timing of the approval of the plan, the Ohio Companies requested that the PUCO amend the energy efficiency and peak demand reduction benchmarks for 2010. 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 because they achieved their targets in that year. 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.

The Ohio Companies had filed applications for rehearing regarding portions of the PUCO's decision related to the Ohio Companies'three-year portfolio plan, which was later denied. On December 30, 2011, the Ohio Companies filed a notice of appeal with the Supreme Court of Ohio, which was dismissed on June 20, 2012. In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their next three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.

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 management audit, and final audit reports are currently scheduled to be filed with the PUCO on August 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, the Pennsylvania Companies filed a Joint Petition for Approval of their DSP that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2013 through May 31, 2015.The ALJ issued a Recommended Decision on June 15, 2012, that supported adoption of the Pennsylvania Companies' proposed wholesale procurement plans, denial of their proposed Market Adjustment Charge, and various modifications to the proposed competitive enhancements. Exceptions to the Recommended Decision are currently pending.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.On June 27, 2012, ME and PN filed a Petition for Writ of Certiorari with the Supreme Court of the United States. The PPUC's brief in opposition is due on August 31, 2012, and the ME/PE reply is due on September 10, 2012. If the Supreme Court declines to take the case then ME and PE will pursue their claims in the proceedings that are pending in the U.S. District Court (E.D. PA).

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.The PPUC entered an order on May 10, 2012 approving the Joint Settlement.

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 by the end of 2012, or in a future base distribution rate case.The deadline for the Pennsylvania Companies to file their smart meter deployment plan is December 31, 2012.

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.Pennsylvania's Independent Regulatory Review Commission subsequently issued comments on April 26, 2012, on the proposed rulemaking, which called for the PPUC to further justify the need for the proposed revisions by citing a lack of evidence demonstrating a need for them.

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 West Virginia Supreme Court issued an Order on June 11, 2012, upholding the WVPSC's decision.

The City of New Martinsville and Morgantown Energy Associates have also filed complaints at FERC alleging the WVPSC order violated PURPA and requested FERC initiate an enforcement action. 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.FERC also noted there may be language in the WVPSC decision that is inconsistent with PURPA. MP filed for rehearing of the FERC's order taking the position that the WVPSC order is consistent with PURPA. New Martinsville filed a complaint in the U.S. District Court on June 4, 2012, alleging that the WVPSC order violates PURPA.

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 deactivation announcements. On April 30, 2012, MP provided the WVPSC with additional information regarding the plant deactivations.The WVPSC issued an order on July 13, 2012 finding the information provided to be sufficient and FirstEnergy's decision to deactivate the three plants reasonable. The WVPSC concluded FirstEnergy may proceed with its plan to deactivate the plants. MP anticipates deactivating these units by September 1, 2012.

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 toelevenhours. 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 expects the matter to be resolved for an immaterial amount.

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 advocated 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.

Order No. 1000 issued by FERC on July 21, 2011, requires the submission of a compliance filing in October 2012 by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfies the principles set forth in the order. The PJM transmission owners have announced their intention to submit a compliance filing based on a hybrid methodology of 50% beneficiary pays and 50% postage stamp (or socialization) to be effective for projects approved by the PJM Board on and after the effective date of the compliance filing. FirstEnergy is working with other PJM transmission owners to develop the required filing based on this proposed methodology.

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 FirstEnergy) 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 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 with briefs due from the parties through 2012 and oral argument to be scheduled in 2013.

In February 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.FERC also set for hearing the question of whether it is just and reasonable for ATSI to pay the Michigan Thumb project costs and, if so, the amount of and methodology for calculating ATSI's Michigan Thumb project cost responsibility.On March 28, 2012, FirstEnergy filed for clarification and rehearing of the February 2012 Order, and such request is pending before the FERC.On July 10, 2012, a prehearing conference was convened before a FERC ALJ who will determine the scope of the hearing and thereafter set the hearing schedule.

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 million ($0.5 million - FES; $34.5 million - AE Supply) in the 2010-2011 Delivery Year. Losses for the 2011-2012 Delivery Year are estimated to be approximately$11.5 million($11.4 million- FES;$0.1 million- AE Supply).

On January 13, 2012, PJM filed comments describing changes to the PJM tariff that, if adopted, should remedy the underfunding issue.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.On July 19, 2012, FERC issued its Order on Rehearing and again dismissed FirstEnergy's complaint without prejudice. FERC noted PJM's ongoing stakeholder process and directed that if the issues were not addressed in that process FirstEnergy could file its complaint again.

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. Exelon Corporation filed a protest, and several other parties filed comments.On July 11, 2012, FERC issued its Order Granting Complaint and Requiring a Compliance Filing. In the order, FERC agreed with FirstEnergy's description of the issues and with FirstEnergy's proposed changes to PJM's rules, and FERC directed PJM to submit a compliance filing within 60 days to implement the changes in the rules.

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.By Order issued June 13, 2012, FERC denied the request for rehearing. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals.

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 additional 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.By Order issued June 13, 2012, that request for rehearing also was denied. On June 21, 2012, the California Parties appealed the FERC's decision to the Ninth Circuit Court of Appeals. 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.The PJM Board has directed the PJM staff to perform additional analysis using the 2012 RTEP assumptions and incorporating the results of the May 2012 RPM base residual auction. The PJM staff is expected to report its conclusions from this analysis to the Transmission Expansion Advisory Committee on August 9, 2012. All applications for authorization to construct the project filed with state commissions have been withdrawn.

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.

MISO Capacity Portability

On June 11, 2012, the FERC issued a Notice of Request for Comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM. FERC is responding to suggestions from MISO Stakeholders that PJM's rules regarding the criteria and qualifications for external generation capacity resources be changed to ease participation by resources that are located in MISO in PJM's RPM capacity auctions. Comments are due on August 10, 2012, and reply comments are due on August 27, 2012. Changes to the criteria and qualifications for participation in the PJM RPM capacity auctions could have a significant impact on the outcome of those auctions, including the prices at which those auctions would clear. FirstEnergy anticipates submitting initial comments by August 10, 2012 and, depending on the comments submitted by other parties, submitting reply comments by August 27, 2012.

XML

Supplemental Guarantor Information (Tables)

6 Months Ended

Jun. 30, 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 June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,430		$	636		$	473		$	(1,083	)	$	1,456
OPERATING EXPENSES:
Fuel	—			336			44			—			380
Purchased power from affiliates	1,156			—			60			(1,083		)	133
Purchased power from non-affiliates	434			—			—			—			434
Other operating expenses	107			100			172			14			393
Provision for depreciation	1			30			39			(1		)	69
General taxes	20			8			4			—			32
Total operating expenses	1,718			474			319			(1,070		)	1,441
OPERATING INCOME (LOSS)	(288		)	162			154			(13		)	15
OTHER INCOME (EXPENSE):
Investment income	—			5			7			(6		)	6
Miscellaneous income, including net income from equity investees	279			19			—			(278		)	20
Interest expense — affiliates	(5		)	(2		)	(1		)	6			(2		)
Interest expense — other	(24		)	(26		)	(14		)	16			(48		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	250			(3		)	—			(262		)	(15		)
INCOME (LOSS) BEFORE INCOME TAXES	(38		)	159			154			(275		)	—
INCOME TAXES (BENEFITS)	(37		)	(7		)	42			3			1
NET INCOME (LOSS)	$	(1	)	$	166		$	112		$	(278	)	$	(1	)
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME (LOSS)	$	(1	)	$	166		$	112		$	(278	)	$	(1	)
OTHER COMPREHENSIVE INCOME:
Pensions and OPEB prior service costs	8			7			—			(7		)	8
Amortized gain on derivative hedges	1			—			—			—			1
Change in unrealized gain on available for sale securities	3			—			3			(3		)	3
Other comprehensive income	12			7			3			(10		)	12
Income taxes on other comprehensive income	2			3			1			(4		)	2
Other comprehensive income, net of tax	10			4			2			(6		)	10
COMPREHENSIVE INCOME	$	9		$	170		$	114		$	(284	)	$	9

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Six Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	2,920		$	1,178		$	867		$	(1,993	)	$	2,972
OPERATING EXPENSES:
Fuel	—			576			99			—			675
Purchased power from affiliates	2,121			—			122			(1,993		)	250
Purchased power from non-affiliates	921			—			—			—			921
Other operating expenses	183			192			288			25			688
Provision for depreciation	2			60			73			(3		)	132
General taxes	40			18			11			—			69
Total operating expenses	3,267			846			593			(1,971		)	2,735
OPERATING INCOME (LOSS)	(347		)	332			274			(22		)	237
OTHER INCOME (EXPENSE):
Investment income	1			9			12			(10		)	12
Miscellaneous income, including net income from equity investees	537			19			—			(532		)	24
Interest expense — affiliates	(9		)	(3		)	(2		)	10			(4		)
Interest expense — other	(47		)	(52		)	(21		)	31			(89		)
Capitalized interest	—			2			16			—			18
Total other income (expense)	482			(25		)	5			(501		)	(39		)
INCOME BEFORE INCOME TAXES	135			307			279			(523		)	198
INCOME TAXES (BENEFITS)	14			(8		)	65			6			77
NET INCOME	$	121		$	315		$	214		$	(529	)	$	121
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	121		$	315		$	214		$	(529	)	$	121
OTHER COMPREHENSIVE INCOME
Pensions and OPEB prior service costs	3			3			—			(3		)	3
Amortized loss on derivative hedges	(4		)	—			—			—			(4		)
Change in unrealized gain on available for sale securities	13			—			13			(13		)	13
Other comprehensive income	12			3			13			(16		)	12
Income taxes on other comprehensive income	4			1			5			(6		)	4
Other comprehensive income, net of tax	8			2			8			(10		)	8
COMPREHENSIVE INCOME	$	129		$	317		$	222		$	(539	)	$	129

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,275		$	535		$	393		$	(911	)	$	1,292
OPERATING EXPENSES:
Fuel	6			266			44			—			316
Purchased power from affiliates	902			9			65			(911		)	65
Purchased power from non-affiliates	332			(3		)	—			—			329
Other operating expenses	159			108			134			12			413
Provision for depreciation	1			32			37			(1		)	69
General taxes	16			8			6			—			30
Impairment of long-lived assets	—			7			—			—			7
Total operating expenses	1,416			427			286			(900		)	1,229
OPERATING INCOME (LOSS)	(141		)	108			107			(11		)	63
OTHER INCOME (EXPENSE):
Investment income	—			1			15			—			16
Miscellaneous income, including net income from equity investees	132			1			—			(129		)	4
Interest expense — affiliates	—			(1		)	(1		)	—			(2		)
Interest expense — other	(24		)	(28		)	(16		)	16			(52		)
Capitalized interest	—			5			5			—			10
Total other income (expense)	108			(22		)	3			(113		)	(24		)
INCOME (LOSS) BEFORE INCOME TAXES	(33		)	86			110			(124		)	39
INCOME TAXES (BENEFITS)	(62		)	28			41			3			10
NET INCOME	$	29		$	58		$	69		$	(127	)	$	29
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	29		$	58		$	69		$	(127	)	$	29
OTHER COMPREHENSIVE INCOME (LOSS)
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	14			—			—			—			14
Change in unrealized gain on available for sale securities	8			—			8			(8		)	8
Other comprehensive income (loss)	17			(4		)	8			(4		)	17
Income taxes (benefits) on other comprehensive income (loss)	8			(2		)	3			(1		)	8
Other comprehensive income (loss), net of tax	9			(2		)	5			(3		)	9
COMPREHENSIVE INCOME	$	38		$	56		$	74		$	(130	)	$	38

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	2,642		$	1,278		$	862		$	(2,098	)	$	2,684
OPERATING EXPENSES:
Fuel	7			560			92			—			659
Purchased power from affiliates	2,087			11			134			(2,098		)	134
Purchased power from non-affiliates	629			(3		)	—			—			626
Other operating expenses	321			219			313			25			878
Provision for depreciation	2			63			76			(3		)	138
General taxes	27			19			14			—			60
Impairment of long-lived assets	—			20			—			—			20
Total operating expenses	3,073			889			629			(2,076		)	2,515
OPERATING INCOME (LOSS)	(431		)	389			233			(22		)	169
OTHER INCOME (EXPENSE):
Investment income	1			1			20			—			22
Miscellaneous income, including net income from equity investees	374			2			—			(368		)	8
Interest expense — affiliates	(1		)	(1		)	(1		)	—			(3		)
Interest expense — other	(48		)	(56		)	(33		)	32			(105		)
Capitalized interest	—			10			10			—			20
Total other income (expense)	326			(44		)	(4		)	(336		)	(58		)
INCOME (LOSS) BEFORE INCOME TAXES	(105		)	345			229			(358		)	111
INCOME TAXES (BENEFITS)	(179		)	125			86			5			37
NET INCOME	$	74		$	220		$	143		$	(363	)	$	74
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	74		$	220		$	143		$	(363	)	$	74
OTHER COMPREHENSIVE INCOME (LOSS)
Pensions and OPEB prior service costs	(9		)	(8		)	—			8			(9		)
Amortized gain on derivative hedges	5			—			—			—			5
Change in unrealized gain on available for sale securities	15			—			15			(15		)	15
Other comprehensive income (loss)	11			(8		)	15			(7		)	11
Income taxes (benefits) on other comprehensive income (loss)	4			(4		)	6			(2		)	4
Other comprehensive income (loss), net of tax	7			(4		)	9			(5		)	7
COMPREHENSIVE INCOME	$	81		$	216		$	152		$	(368	)	$	81

Condensed Consolidating Balance Sheets

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of June 30, 2012	FES		FGCO		NGC		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	7	$	—	$	—		$	7
Receivables-
Customers	457		—		—		—			457
Affiliated companies	464		482		297		(706		)	537
Other	67		25		4		—			96
Notes receivable from affiliated companies	155		1,653		152		(1,732		)	228
Materials and supplies, at average cost	68		272		208		—			548
Derivatives	265		—		—		—			265
Prepayments and other	3		15		1		—			19
	1,479		2,454		662		(2,438		)	2,157
PROPERTY, PLANT AND EQUIPMENT:
In service	89		5,620		6,051		(385		)	11,375
Less — Accumulated provision for depreciation	30		1,872		2,594		(182		)	4,314
	59		3,748		3,457		(203		)	7,061
Construction work in progress	28		187		704		—			919
	87		3,935		4,161		(203		)	7,980
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,250		—			1,250
Investment in affiliated companies	6,241		—		—		(6,241		)	—
Other	—		7		—		—			7
	6,241		7		1,250		(6,241		)	1,257
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		261		—		(261		)	—
Customer intangibles	118				—		—			118
Goodwill	24				—		—			24
Property taxes	—		20		23		—			43
Unamortized sale and leaseback costs	—		4		—		114			118
Derivatives	110				—		—			110
Other	86		160		1		(110		)	137
	338		445		24		(257		)	550
	$	8,145	$	6,841	$	6,097	$	(9,139	)	$	11,944
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	646	$	518	$	(21	)	$	1,144
Short-term borrowings-
Affiliated companies	1,597		135		—		(1,732		)	—
Accounts payable-
Affiliated companies	739		279		305		(715		)	608
Other	173		133		—		—			306
Accrued taxes	23		20		27		(8		)	62
Derivatives	219		—		—		—			219
Other	68		124		13		37			242
	2,820		1,337		863		(2,439		)	2,581
CAPITALIZATION:
Total equity	3,704		3,413		2,810		(6,223		)	3,704
Long-term debt and other long-term obligations	1,482		1,657		580		(1,219		)	2,500
	5,186		5,070		3,390		(7,442		)	6,204
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		909			909
Accumulated deferred income taxes	28		—		572		(164		)	436
Asset retirement obligations	—		29		905		—			934
Retirement benefits	34		145		—		—			179
Lease market valuation liability	—		148		—		—			148
Other	77		112		367		(3		)	553
	139		434		1,844		742			3,159
	$	8,145	$	6,841	$	6,097	$	(9,139	)	$	11,944

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	5,700		—		—		(5,700		)	—
Other	—		7		—		—			7
	5,700		7		1,223		(5,700		)	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
	$	7,483	$	6,667	$	5,846	$	(8,177	)	$	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:
Total equity	3,577		3,097		2,587		(5,684		)	3,577
Long-term debt and other long-term obligations	1,483		1,905		641		(1,230		)	2,799
	5,060		5,002		3,228		(6,914		)	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
	$	7,483	$	6,667	$	5,846	$	(8,177	)	$	11,819

Condensed Consolidating Statements of Cash Flows

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Six Months Ended June 30, 2012	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(525	)	$	308		$	446		$	(10	)	$	219
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			52			30			—			82
Short-term borrowings, net	532			46			—			(578		)	—
Redemptions and Repayments-
Long-term debt	—			(63		)	(87		)	10			(140		)
Short-term borrowings, net	—			—			(32		)	32			—
Other	(1		)	(4		)	(1		)	—			(6		)
Net cash provided from (used for) financing activities	531			31			(90		)	(536		)	(64		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(44		)	(254		)	—			(303		)
Proceeds from assets sale	—			17			—			—			17
Sales of investment securities held in trusts	—			—			109			—			109
Purchases of investment securities held in trusts	—			—			(127		)	—			(127		)
Loans to affiliated companies, net	1			(308		)	(84		)	546			155
Other	(2		)	(4		)	—			—			(6		)
Net cash provided from (used for) investing activities	(6		)	(339		)	(356		)	546			(155		)
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 Six Months Ended June 30, 2011	FES			FGCO			NGC			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(329	)	$	321		$	200		$	(10	)	$	182
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			140			107			—			247
Short-term borrowings, net	453			77			—			—			530
Redemptions and Repayments-
Long-term debt	(135		)	(192		)	(155		)	10			(472		)
Other	(9		)	(1		)	(1		)	—			(11		)
Net cash used for financing activities	309			24			(49		)	10			294
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(6		)	(109		)	(219		)	—			(334		)
Sales of investment securities held in trusts	—			—			513			—			513
Purchases of investment securities held in trusts	—			—			(545		)	—			(545		)
Loans to affiliated companies, net	28			(221		)	100			—			(93		)
Other	(2		)	(18		)	—			—			(20		)
Net cash provided from (used for) investing activities	20			(348		)	(151		)	—			(479		)
Net change in cash and cash equivalents	—			(3		)	—			—			(3		)
Cash and cash equivalents at beginning of period	—			9			—			—			9
Cash and cash equivalents at end of period	$	—		$	6		$	—		$	—		$	6

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Organization and Basis of Presentation

6 Months Ended

Jun. 30, 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 FET), 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 six months ended June 30, 2011, include just four months 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 six months ended June 30, 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.