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 September 30, 2013

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

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. and FirstEnergy Solutions Corp.

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. and FirstEnergy Solutions Corp.

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.
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. and FirstEnergy Solutions Corp.

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 NOVEMBER 4, 2013
FirstEnergy Corp., $0.10 par value	418,229,541
FirstEnergy Solutions Corp., no par value	7

FirstEnergy Corp. is the sole holder of FirstEnergy Solutions Corp. common stock.

This combined Form 10-Q is separately filed by FirstEnergy Corp. and FirstEnergy Solutions Corp. 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 the other registrant, except that information relating to FirstEnergy Solutions Corp. is also attributed to FirstEnergy Corp.

FirstEnergy Web Site and Other Social Media Sites and Applications

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 the "Investors" page of FirstEnergy’s Internet web site at www.firstenergycorp.com.

These SEC filings are posted on the web site as soon as reasonably practicable after they are electronically filed with the SEC. Additionally, the registrants routinely post additional important information including press releases, investor presentations and notices of upcoming events, under the "Investors" section of 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. Investors may be notified of postings to the web site by signing up for email alerts and RSS feeds on the "Investors" page of FirstEnergy's Internet web site or through push alerts from FirstEnergy Investor Relations apps for Apple Inc.'s iPad and iPhone devices, which can be installed for free at the Apple online store. FirstEnergy also uses Twitter and Facebook as an additional channel of distribution to reach public investors and as a supplemental means of disclosing material non-public information for complying with its disclosure obligations under SEC Regulation FD. Information contained on FirstEnergy’s Internet web site or its Twitter or Facebook site, and any corresponding applications of those sites, shall not be deemed incorporated into, or to be part of, this report.

OMISSION OF CERTAIN INFORMATION

FirstEnergy Solutions Corp. meets the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and is 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,” "will," "intend," “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, in general, and the retail sales market in particular.

• 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 and pending rate cases.

• 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.

• Regulatory outcomes associated with storm restoration, including but not limited to Hurricane Sandy, Hurricane Irene and the October snowstorm of 2011.

• Changing energy, capacity and commodity market prices including, but not limited to, coal, natural gas and oil, and availability and their impact on retail margins.

• The continued ability of our regulated utilities to recover their costs.

• Costs being higher than anticipated and the success of our policies to control costs and to mitigate low energy, capacity and market prices.

• Other legislative and regulatory changes, and revised environmental requirements, including possible GHG emission, water discharge, water intake and coal combustion residual regulations, the potential impacts of CSAPR, CAIR, and/or any laws, rules or regulations that ultimately replace CAIR, and the effects of the EPA's MATS rules including our estimated costs of compliance.

• 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 deactivate or idle certain generating units).

• The uncertainties associated with the deactivation of certain older regulated and competitive fossil units including the impact on vendor commitments, and the timing thereof as they relate to, among other things, RMR arrangements and the reliability of the transmission grid.

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

• Issues arising from the indications of cracking in the shield building at Davis-Besse.

• The impact of future changes to the operational status or availability of our generating units.

• The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings, including, but not limited to, any such proceedings related to vendor commitments.

• Replacement power costs being higher than anticipated or not fully hedged.

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

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

• The ability to accomplish or realize anticipated benefits from strategic and financial goals including, but not limited to, the ability to reduce costs and to successfully complete our announced financial plans designed to improve our credit metrics and strengthen our balance sheet, including but not limited to, proposed capital raising and debt reduction initiatives, and the proposed sale of non-core hydro assets.

• 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 Regulated Distribution and Regulated Transmission segments and to continue to successfully implement our direct retail sales strategy in the Competitive Energy Services segment.

• 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 announced financial plan, the cost of such capital and overall condition of the capital and credit markets affecting us and our subsidiaries.

• Actions that may be taken by credit rating agencies that could negatively affect us and our subsidiaries' access to financing, increase the costs thereof, and increase requirements to post additional collateral to support outstanding commodity positions, LOCs and other financial guarantees.

• Changes in national and regional economic conditions affecting us, our subsidiaries and our major industrial and commercial customers, and other counterparties including fuel suppliers, with which we do business.

• Issues concerning the stability 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 period may in the aggregate vary from prior periods 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 (Loss) and Comprehensive Income (Loss)	5
Consolidated Balance Sheets	6
Consolidated Statements of Cash Flows	7
Combined Notes To Consolidated Financial Statements	8
Item 2. Management’s Discussion and Analysis of Registrant and Subsidiaries	64
FirstEnergy Corp. Management's Discussion and Analysis of Financial Condition and Results of Operations	64
Management’s Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	116
Item 3. Quantitative and Qualitative Disclosures About Market Risk	120
Item 4. Controls and Procedures	120
Part II. Other Information
Item 1. Legal Proceedings	120
Item 1A. Risk Factors	120
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	120
Item 3. Defaults Upon Senior Securities	121
Item 4. Mine Safety Disclosures	121
Item 5. Other Information	121
Item 6. Exhibits	122

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 Supply
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
FG	FirstEnergy Generation, LLC, 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 Pinesdale LLC
Global Rail	A subsidiary of Global Holding 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
NG	FirstEnergy Nuclear Generation, LLC, a subsidiary of FES, which owns nuclear generating facilities
OE	Ohio Edison Company, an Ohio electric utility operating subsidiary
Ohio Companies	CEI, OE and TE
PATH	Potomac-Appalachian Transmission Highline, LLC, a joint venture between Allegheny and a subsidiary of AEP
PATH-Allegheny	PATH Allegheny Transmission Company, LLC
PATH-WV	PATH West Virginia Transmission Company, LLC
PE	The Potomac Edison Company, a Maryland electric utility operating subsidiary of AE
Penn	Pennsylvania Power Company, a Pennsylvania electric utility operating subsidiary of OE
Pennsylvania Companies	ME, PN, Penn and WP
PN	Pennsylvania Electric Company, a Pennsylvania electric utility operating subsidiary
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	An indirect subsidiary of Global Holding 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:
AEP	American Electric Power Company, Inc.
AFS	Available-for-sale
ALJ	Administrative Law Judge
Anker WV	Anker West Virginia Mining Company, Inc.
Anker Coal	Anker Coal Group, Inc.
AOCI	Accumulated Other Comprehensive Income
ARO	Asset Retirement Obligation
ARR	Auction Revenue Right

ii

GLOSSARY OF TERMS, Continued
ASLB	Atomic Safety and Licensing Board
BGS	Basic Generation Service
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CBP	Competitive Bid Process
CCB	Coal Combustion By-products
CCR	Coal Combustion Residuals
CDWR	California Department of Water Resources
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980
CFR	Code of Federal Regulations
CO2	Carbon Dioxide
CSAPR	Cross-State Air Pollution Rule
CWA	Clean Water Act
DCR	Delivery Capital Recovery
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
ELPC	Environmental Law & Policy Center
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
ICE	IntercontinentalExchange, Inc.
ICG	International Coal Group Inc.
ILP	Integrated License Application Process
kV	Kilovolt
KWH	Kilowatt-hour
LAR	License Amendment Request
LBR	Little Blue Run
LCAPP	Long-Term Capacity Agreement Pilot Program
LOC	Letter of Credit
LSE	Load Serving Entity
MAAC	Mid-Atlantic Region of PJM
MATS	Mercury and Air Toxics Standards
MDPSC	Maryland Public Service Commission
MISO	Midcontinent Independent System Operator, Inc.
mmBTU	One Million British Thermal Units
Moody’s	Moody’s Investors Service, Inc.

iii

GLOSSARY OF TERMS, Continued
MOPR	Minimum Offer Price Rule
MTEP	MISO Regional Transmission Expansion Plan
MVP	Multi-value Project
MW	Megawatt
MWH	Megawatt-hour
NDT	Nuclear Decommissioning Trust
NERC	North American Electric Reliability Corporation
NGO	Non-Governmental Organization
NJBPU	New Jersey Board of Public Utilities
NNSR	Non-Attainment New Source Review
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NYPSC	New York State Public Service Commission
NYSEG	New York State Electric and Gas
OCC	Ohio Consumers' Counsel
OPEB	Other Post-Employment Benefits
OTTI	Other Than Temporary Impairments
OVEC	Ohio Valley Electric Corporation
PA DEP	Pennsylvania Department of Environmental Protection
PCB	Polychlorinated Biphenyl
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
RCRA	Resource Conservation and Recovery Act
REC	Renewable Energy Credit
REIT	Real Estate Investment Trust
RFC	ReliabilityFirst Corporation
RFP	Request for Proposal
RGGI	Regional Greenhouse Gas Initiative
RMR	Reliability Must-Run
ROP	Reactor Oversight Process
RPM	Reliability Pricing Model
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SAIDI	System Average Interruption Duration Index
SAIFI	System Average Interruption Frequency Index
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

iv

GLOSSARY OF TERMS, Continued
SMIP	Smart Meter Implementation Plan
SO2	Sulfur Dioxide
SOS	Standard Offer Service
SPE	Special Purpose Entity
SREC	Solar Renewable Energy Credit
SSO	Standard Service Offer
TDS	Total Dissolved Solid
TMDL	Total Maximum Daily Load
TMI-2	Three Mile Island Unit 2
TSC	Transmission Service Charge
UWUA	Utility Workers Union of America
VIE	Variable Interest Entity
VSCC	Virginia State Corporation Commission
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia

v

PART I. FINANCIAL INFORMATION

ITEM I.         Financial Statements

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	Three Months Ended September 30						Nine Months Ended September 30
(In millions, except per share amounts)	2013			2012			2013			2012
REVENUES:
Electric utilities	$	2,530		$	2,670		$	7,139		$	7,533
Unregulated businesses	1,506			1,382			4,131			4,247
Total revenues*	4,036			4,052			11,270			11,780
OPERATING EXPENSES:
Fuel	657			636			1,915			1,833
Purchased power	1,120			1,063			2,932			3,367
Other operating expenses	877			861			2,645			2,597
Provision for depreciation	316			272			909			834
Amortization of regulatory assets, net	312			61			443			198
General taxes	242			257			747			760
Impairment of long-lived assets	—			—			473			—
Total operating expenses	3,524			3,150			10,064			9,589
OPERATING INCOME	512			902			1,206			2,191
OTHER INCOME (EXPENSE):
Gain (loss) on debt redemptions	9			—			(132		)	—
Investment income	5			39			8			63
Interest expense	(257		)	(230		)	(771		)	(750		)
Capitalized interest	17			18			51			54
Total other expense	(226		)	(173		)	(844		)	(633		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	286			729			362			1,558
INCOME TAXES	77			307			129			650
NET INCOME FROM CONTINUING OPERATIONS	209			422			233			908
Discontinued operations (net of income taxes of $3, $2, $9 and $8, respectively) (Note 16)	9			3			17			11
NET INCOME	218			425			250			919
Income attributable to noncontrolling interest	—			—			—			1
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$	218		$	425		$	250		$	918
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations	$	0.50		$	1.01		$	0.56		$	2.17
Basic - Discontinued Operations (Note 16)	0.02			0.01			0.04			0.03
Basic - Earnings Available to FirstEnergy Corp.	$	0.52		$	1.02		$	0.60		$	2.20
Diluted - Continuing Operations	$	0.50		$	1.00		$	0.56		$	2.16
Diluted - Discontinued Operations (Note 16)	0.02			0.01			0.04			0.03
Diluted - Earnings Available to FirstEnergy Corp.	$	0.52		$	1.01		$	0.60		$	2.19
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	418			417			418			418
Diluted	419			419			419			419
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	1.10		$	1.10		$	1.65		$	1.65

* Includes excise tax collections of $117 million and $123 million in the three months ended September 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended September 30, 2013 and 2012, 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 September 30						Nine Months Ended September 30
(In millions)	2013			2012			2013			2012
NET INCOME	$	218		$	425		$	250		$	919
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(47		)	(47		)	(148		)	(148		)
Amortized losses on derivative hedges	2			—			4			1
Change in unrealized gain on available-for-sale securities	6			1			3			13
Other comprehensive loss	(39		)	(46		)	(141		)	(134		)
Income tax benefits on other comprehensive loss	(15		)	(24		)	(55		)	(75		)
Other comprehensive loss, net of tax	(24		)	(22		)	(86		)	(59		)
COMPREHENSIVE INCOME	194			403			164			860
Comprehensive income attributable to noncontrolling interest	—			—			—			1
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$	194		$	403		$	164		$	859

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)	September 30, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	222	$	172
Receivables-
Customers, net of allowance for uncollectible accounts of $41 in 2013 and $40 in 2012	1,579		1,614
Other, net of allowance for uncollectible accounts of $3 in 2013 and $4 in 2012	231		315
Materials and supplies, at average cost	731		861
Prepaid taxes	104		119
Derivatives	140		160
Accumulated deferred income taxes	290		319
Other	262		208
	3,559		3,768
PROPERTY, PLANT AND EQUIPMENT:
In service	44,089		43,210
Less — Accumulated provision for depreciation	13,167		12,600
	30,922		30,610
Construction work in progress	2,301		2,293
	33,223		32,903
INVESTMENTS:
Nuclear plant decommissioning trusts	2,183		2,204
Investments in lease obligation bonds	46		54
Other	876		936
	3,105		3,194
ASSETS HELD FOR SALE (NOTE 16)	234		—
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418		6,447
Regulatory assets	2,146		2,375
Other	1,698		1,719
	10,262		10,541
	$	50,383	$	50,406
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,889	$	1,999
Short-term borrowings	3,404		1,969
Accounts payable	995		1,599
Accrued taxes	401		543
Accrued compensation and benefits	289		331
Derivatives	105		126
Other	872		1,038
	7,955		7,605
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	9,755		9,769
Accumulated other comprehensive income	299		385
Retained earnings	2,448		2,888
Total common stockholders’ equity	12,544		13,084
Noncontrolling interest	3		9
Total equity	12,547		13,093
Long-term debt and other long-term obligations	15,291		15,179
	27,838		28,272
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,603		6,616
Retirement benefits	3,104		3,080
Asset retirement obligations	1,834		1,599
Deferred gain on sale and leaseback transaction	866		892
Adverse power contract liability	467		506
Other	1,716		1,836
	14,590		14,529
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
	$	50,383	$	50,406

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)

	Nine Months Ended September 30
(In millions)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	250		$	919
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	909			834
Amortization of regulatory assets, net	443			198
Nuclear fuel amortization	156			156
Deferred purchased power and other costs	(61		)	(214		)
Deferred income taxes and investment tax credits, net	114			712
Impairments of long-lived assets	473			—
Investment impairments	74			10
Deferred rents and lease market valuation liability	(22		)	(62		)
Retirement benefits	(133		)	(97		)
Gain on asset sales	(21		)	(17		)
Commodity derivative transactions, net (Note 10)	24			(80		)
Pension trust contributions	—			(600		)
Cash collateral, net	(67		)	(3		)
Loss on debt redemptions	132			—
Make-whole premiums paid on debt redemptions	(181		)	—
Income from discontinued operations (Note 16)	(17		)	(11		)
Decrease (increase) in operating assets-
Receivables	(7		)	(41		)
Materials and supplies	117			(63		)
Prepayments and other current assets	(59		)	(151		)
Increase (decrease) in operating liabilities-
Accounts payable	(279		)	(227		)
Accrued taxes	(146		)	(58		)
Accrued interest	29			50
Accrued compensation and benefits	(43		)	(71		)
Other	(14		)	92
Net cash provided from operating activities	1,671			1,276
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	2,745			660
Short-term borrowings, net	1,435			1,604
Redemptions and Repayments-
Long-term debt	(2,662		)	(870		)
Tender premiums paid on debt redemptions	(110		)	—
Common stock dividend payments	(690		)	(690		)
Other	(64		)	(42		)
Net cash provided from financing activities	654			662
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,960		)	(1,686		)
Nuclear fuel	(159		)	(207		)
Sales of investment securities held in trusts	1,545			2,133
Purchases of investment securities held in trusts	(1,567		)	(2,188		)
Cash investments	(12		)	100
Asset removal costs	(125		)	(119		)
Other	3			(23		)
Net cash used for investing activities	(2,275		)	(1,990		)
Net change in cash and cash equivalents	50			(52		)
Cash and cash equivalents at beginning of period	172			202
Cash and cash equivalents at end of period	$	222		$	150

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

4

FIRSTENERGY SOLUTIONS CORP.

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

(Unaudited)

	Three Months Ended September 30						Nine Months Ended September 30
(In millions)	2013			2012			2013			2012
STATEMENTS OF INCOME (LOSS)
REVENUES:
Electric sales to non-affiliates	$	1,455		$	1,358		$	4,066		$	4,035
Electric sales to affiliates	186			155			482			385
Other	38			37			107			91
Total revenues	1,679			1,550			4,655			4,511
OPERATING EXPENSES:
Fuel	304			303			936			978
Purchased power from affiliates	132			131			401			381
Purchased power from non-affiliates	724			502			1,755			1,425
Other operating expenses	339			342			1,105			1,028
Provision for depreciation	80			70			231			200
General taxes	35			35			106			104
Total operating expenses	1,614			1,383			4,534			4,116
OPERATING INCOME	65			167			121			395
OTHER INCOME (EXPENSE):
Loss on debt redemptions	—			—			(103		)	—
Investment income (loss)	(3		)	38			(4		)	50
Miscellaneous income	21			1			29			25
Interest expense — affiliates	(1		)	(3		)	(7		)	(7		)
Interest expense — other	(35		)	(51		)	(126		)	(140		)
Capitalized interest	9			9			28			27
Total other expense	(9		)	(6		)	(183		)	(45		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	56			161			(62		)	350
INCOME TAXES (BENEFITS)	23			65			(19		)	139
INCOME (LOSS) FROM CONTINUING OPERATIONS	$	33		$	96		$	(43	)	$	211
Discontinued operations (net of income taxes of $5, $3, $8 and $6, respectively) (Note 16)	7			5			14			11
NET INCOME (LOSS)	$	40		$	101		$	(29	)	$	222
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	40		$	101		$	(29	)	$	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(5		)	(16		)	(2		)
Amortized loss on derivative hedges	(1		)	(2		)	(3		)	(6		)
Change in unrealized gain on available-for-sale securities	5			(2		)	2			11
Other comprehensive income (loss)	(1		)	(9		)	(17		)	3
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(3		)	(7		)	1
Other comprehensive income (loss), net of tax	—			(6		)	(10		)	2
COMPREHENSIVE INCOME (LOSS)	$	40		$	95		$	(39	)	$	224

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)	September 30, 2013		December 31, 2012
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	3
Receivables-
Customers, net of allowance for uncollectible accounts of $14 in 2013 and $16 in 2012	524		483
Affiliated companies	519		379
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012	123		91
Notes receivable from affiliated companies	254		276
Materials and supplies	439		505
Derivatives	139		158
Prepayments and other	105		87
	2,105		1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	12,508		11,997
Less — Accumulated provision for depreciation	4,649		4,408
	7,859		7,589
Construction work in progress	1,116		1,141
	8,975		8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	1,270		1,283
Other	11		12
	1,281		1,295
ASSETS HELD FOR SALE (NOTE 16)	121		—
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	99		110
Goodwill	23		24
Property taxes	36		36
Unamortized sale and leaseback costs	161		119
Derivatives	65		99
Other	268		253
	652		641
	$	13,134	$	12,648
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	859	$	1,102
Short-term borrowings	4		4
Accounts payable-
Affiliated companies	776		726
Other	213		159
Accrued taxes	42		171
Derivatives	103		124
Other	176		280
	2,173		2,566
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding	3,078		1,573
Accumulated other comprehensive income	62		72
Retained earnings	2,089		2,118
Total common stockholder's equity	5,229		3,763
Long-term debt and other long-term obligations	2,178		3,118
	7,407		6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	866		892
Accumulated deferred income taxes	699		515
Asset retirement obligations	1,159		965
Retirement benefits	255		241
Derivatives	22		37
Other	553		551
	3,554		3,201
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
	$	13,134	$	12,648

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)

	Nine Months Ended September 30
(In millions)	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$	(29	)	$	222
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation	231			200
Nuclear fuel amortization	156			159
Deferred rents and lease market valuation liability	(36		)	(144		)
Deferred income taxes and investment tax credits, net	205			123
Investment impairments	66			8
Pension trust contribution	—			(209		)
Gain on asset sales	(20		)	(17		)
Commodity derivative transactions, net (Note 10)	24			(67		)
Cash collateral, net	(35		)	(4		)
Loss on debt redemptions	103			—
Make-whole premiums paid on debt redemptions	(31		)	—
Income from discontinued operations (Note 16)	(14		)	(11		)
Decrease (increase) in operating assets-
Receivables	(214		)	95
Materials and supplies	66			(40		)
Prepayments and other current assets	(22		)	5
Increase (decrease) in operating liabilities-
Accounts payable	129			312
Accrued taxes	(131		)	(150		)
Accrued compensation and benefits	(5		)	10
Other	(54		)	9
Net cash provided from operating activities	389			501
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	—			560
Short-term borrowings, net	—			3
Equity contribution from parent	1,500			—
Redemptions and repayments-
Long-term debt	(1,179		)	(246		)
Tender premiums paid on debt redemptions	(67		)	—
Other	(7		)	(9		)
Net cash provided from financing activities	247			308
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(477		)	(535		)
Nuclear fuel	(159		)	(207		)
Proceeds from asset sales	21			17
Sales of investment securities held in trusts	650			1,167
Purchases of investment securities held in trusts	(694		)	(1,194		)
Loans to affiliated companies, net	22			(55		)
Other	—			(6		)
Net cash used for investing activities	(637		)	(813		)
Net change in cash and cash equivalents	(1		)	(4		)
Cash and cash equivalents at beginning of period	3			7
Cash and cash equivalents at end of period	$	2		$	3

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

7

FIRSTENERGY CORP. AND SUBSIDIARIES

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note Number		Page Number
1	Organization and Basis of Presentation	9
2	Goodwill	9
3	Impairment of Long-Lived Assets	10
4	Earnings Per Share of Common Stock	11
5	Pensions and Other Postemployment Benefits	12
6	Accumulated Other Comprehensive Income	13
7	Income Taxes	17
8	Variable Interest Entities	18
9	Fair Value Measurements	19
10	Derivative Instruments	27
11	Asset Retirement Obligations	33
12	Regulatory Matters	33
13	Commitments, Guarantees and Contingencies	44
14	Supplemental Guarantor Information	52
15	Segment Information	61
16	Discontinued Operations and Assets Held for Sale	63

8

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 (FG and NG) and FESC. During the second quarter of 2013, FE completed a $1.5 billion equity contribution to FES.

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, 2012.

FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. 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 statement 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. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.

FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES.

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. GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy first assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value, then the two-step goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.

FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, Competitive Energy Services and Other/Corporate. Goodwill is allocated to these reportable segments based on the original purchase price allocation of acquisitions. Total goodwill recognized by segment in FirstEnergy's Consolidated Balance Sheet is as follows:

9

Goodwill	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate		Consolidated
	(In millions)
Balance as of December 31, 2012	$	5,025	$	526	$	896		$	—	$	6,447
Classification to Assets Held for Sale(1)	—		—		(29		)	—		(29		)
Balance as of September 30, 2013	$	5,025	$	526	$	867		$	—	$	6,418

⁽¹⁾ See Note 16, Discontinued Operations and Assets Held for Sale.

FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission segments as of July 31, 2013. FirstEnergy assessed economic, industry and market considerations in addition to overall financial performance of its Regulated Distribution and Regulated Transmission segments. It was determined that the fair values of these segments were, more likely than not, greater than their carrying values. Due to excess generation supply in the region, which has caused a period of protracted low power and capacity prices impacting Competitive operations, FirstEnergy performed a quantitative assessment of the Competitive Energy Services segment as of July 31, 2013. The fair value of the Competitive Energy Services segment was calculated using a discounted cash flow analysis which included the effects of the potential sale of certain hydroelectric power stations and transfer of the Harrison plant to the Regulated Distribution Segment and the Pleasants plant to the Competitive Energy Services Segment as discussed in Note 12, Regulatory Matters. Assumptions used in the analysis include discount rates, market performance, projected operating and capital cash flows and the fair value of debt. The estimated fair value of the Competitive Energy Services segment exceeded its carrying amount (including goodwill) as of July 31, 2013. Continued weak economic conditions, lower than forecasted power and capacity prices, and revised environmental requirements could have a negative impact on future goodwill assessments.

In October of 2013, in connection with the closing of the West Virginia asset transfer, as discussed in Note 12, Regulatory Matters, FirstEnergy transferred approximately $67 million of goodwill from the Competitive Energy Services segment to the Regulated Distribution segment based on the relative fair value of the generating plants to the fair value of the respective segment.

3. IMPAIRMENT OF LONG-LIVED ASSETS

FirstEnergy reviews long-lived assets, including regulatory assets, for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value.

Generating Plant Retirements - 2013

On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013:

Generating Units	MW Capacity	Location
Hatfield's Ferry, Units 1-3	1,710	Masontown, Pennsylvania
Mitchell, Units 2-3	370	Courtney, Pennsylvania

As a result of this decision, in the second quarter of 2013, FirstEnergy recorded a pre-tax impairment of approximately $473 million to continuing operations, which also includes pre-tax impairments of $13 million related to excessive inventory at these facilities. The impairment charge is included within the results of the Competitive Energy Services Segment.

Approximately 240 plant employees and generation related positions were affected by these plant deactivations. FirstEnergy recorded approximately $7 million (pre-tax) severance related expenses that were recognized in Other operating expenses in the Consolidated Statements of Income during the nine months ended 2013.

On October 9, 2013, Hatfield's Ferry Units 1-3 and Mitchell Units 2-3 were deactivated. With the termination of operations at Hatfield's Ferry, AE Supply has the right to redeem $235 million of its outstanding PCRBs at par. A conditional notice of full redemption was issued on October 18, 2013, calling the $235 million of outstanding PCRB's for redemption on November 15, 2013.

AE Supply has obligations, such as fuel supply, that could be affected by the plant closings and management is currently unable to reasonably estimate potential costs, or a range thereof, that could be incurred.

10

Generating Plant Retirements - 2012

As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated.FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated. During the nine months ended September 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately $14 million ($10 million by FES) as a result of the deactivations. These costs are included in Other operating expenses in the Consolidated Statements of Income (Loss).

Cost Savings Initiatives

In addition to deactivating Hatfield's Ferry and Mitchell, FirstEnergy identified and intends to implement additional cost control opportunities across the organization. These actions include reductions to medical and other employee benefits and other organizational changes, including a reduction in staffing of an additional 250 positions. FirstEnergy incurred approximately $2 million (pre-tax) of severance related expenses in the third quarter of 2013.

4. EARNINGS PER SHARE OF COMMON STOCK

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 September 30				Nine Months Ended September 30
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2013		2012		2013		2012
	(In millions, except per share amounts)
Net income from continuing operations	$	209	$	422	$	233	$	908
Less: Income attributable to noncontrolling interest	—		—		—		1
Income from continuing operations available to common shareholders	209		422		233		907
Discontinued operations (Note 16)	9		3		17		11
Earnings available to FirstEnergy Corp.	$	218	$	425	$	250	$	918
Weighted average number of basic shares outstanding	418		417		418		418
Assumed exercise of dilutive stock options and awards(1)	1		2		1		1
Weighted average number of diluted shares outstanding	419		419		419		419
Earnings per share:
Basic earnings per share:
Net income from continuing operations	$	0.50	$	1.01	$	0.56	$	2.17
Discontinued operations (Note 16)	0.02		0.01		0.04		0.03
Net earnings per basic share	$	0.52	$	1.02	$	0.60	$	2.20
Diluted earnings per share:
Net income from continuing operations	$	0.50	$	1.00	$	0.56	$	2.16
Discontinued operations (Note 16)	0.02		0.01		0.04		0.03
Net earnings per diluted share	$	0.52	$	1.01	$	0.60	$	2.19

⁽¹⁾  For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

11

5. PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended September 30,	2013			2012			2013			2012
	(In millions)
Service costs	$	49		$	40		$	3		$	3
Interest costs	93			97			9			12
Expected return on plan assets	(125		)	(121		)	(8		)	(9		)
Amortization of prior service costs (credits)	3			3			(50		)	(50		)
Net periodic costs (credits)	$	20		$	19		$	(46	)	$	(44	)

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Nine Months Ended September 30,	2013			2012			2013			2012
	(In millions)
Service costs	$	147		$	120		$	9		$	9
Interest costs	279			291			27			36
Expected return on plan assets	(375		)	(363		)	(24		)	(27		)
Amortization of prior service costs (credits)	9			9			(157		)	(152		)
Net periodic costs (credits)	$	60		$	57		$	(145	)	$	(134	)

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 FES were as follows:

Net Periodic Benefit Expense (Credit)	Pensions				OPEB
For the Three Months Ended September 30,	2013		2012		2013			2012
	(In millions)
FirstEnergy	$	16	$	14	$	(31	)	$	(30	)
FES	5		5		(4		)	(4		)

Net Periodic Benefit Expense (Credit)	Pensions				OPEB
For the Nine Months Ended September 30,	2013		2012		2013			2012
	(In millions)
FirstEnergy	$	41	$	41	$	(95	)	$	(92	)
FES	13		13		(12		)	(12		)

12

6. ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, in the three and nine months ended September 30, 2013 and 2012, for FirstEnergy and FES are shown in the following tables:

FirstEnergy
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2013	$	(37	)	$	13		$	347		$	323
Other comprehensive income before reclassifications	—			5			—			5
Amounts reclassified from AOCI	1			(1		)	(29		)	(29		)
Net other comprehensive income (loss)	1			4			(29		)	(24		)
AOCI Balance as of September 30, 2013	$	(36	)	$	17		$	318		$	299
AOCI Balance as of July 1, 2012	$	(39	)	$	27		$	401		$	389
Other comprehensive income before reclassifications	—			25			—			25
Amounts reclassified from AOCI	—			(25		)	(22		)	(47		)
Net other comprehensive loss	—			—			(22		)	(22		)
AOCI Balance as of September 30, 2012	$	(39	)	$	27		$	379		$	367

FES
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2013	$	1		$	12		$	49		$	62
Other comprehensive income before reclassifications	—			4			—			4
Amounts reclassified from AOCI	—			(1		)	(3		)	(4		)
Net other comprehensive income (loss)	—			3			(3		)	—
AOCI Balance as of September 30, 2013	$	1		$	15		$	46		$	62
AOCI Balance as of July 1, 2012	$	6		$	25		$	53		$	84
Other comprehensive income (loss) before reclassifications	(1		)	24			—			23
Amounts reclassified from AOCI	(1		)	(25		)	(3		)	(29		)
Net other comprehensive loss	(2		)	(1		)	(3		)	(6		)
AOCI Balance as of September 30, 2012	$	4		$	24		$	50		$	78

13

FirstEnergy
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
Other comprehensive income before reclassifications	—			19			—			19
Amounts reclassified from AOCI	2			(17		)	(90		)	(105		)
Net other comprehensive income (loss)	2			2			(90		)	(86		)
AOCI Balance as of September 30, 2013	$	(36	)	$	17		$	318		$	299
AOCI Balance as of January 1, 2012	$	(39	)	$	19		$	446		$	426
Other comprehensive income before reclassifications	1			38			5			44
Amounts reclassified from AOCI	(1		)	(30		)	(72		)	(103		)
Net other comprehensive income (loss)	—			8			(67		)	(59		)
AOCI Balance as of September 30, 2012	$	(39	)	$	27		$	379		$	367

FES
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
Other comprehensive income before reclassifications	—			17			—			17
Amounts reclassified from AOCI	(2		)	(15		)	(10		)	(27		)
Net other comprehensive income (loss)	(2		)	2			(10		)	(10		)
AOCI Balance as of September 30, 2013	$	1		$	15		$	46		$	62
AOCI Balance as of January 1, 2012	$	8		$	16		$	52		$	76
Other comprehensive income before reclassifications	—			37			8			45
Amounts reclassified from AOCI	(4		)	(29		)	(10		)	(43		)
Net other comprehensive income (loss)	(4		)	8			(2		)	2
AOCI Balance as of September 30, 2012	$	4		$	24		$	50		$	78

14

The following amounts were reclassified from AOCI in the three months ended September 30, 2013 and 2012:

FE	Three Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
Long-term debt	3			2			Interest expense
	2			—			Total before taxes
	(1		)	—			Income taxes
	$	1		$	—		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(2	)	$	(40	)	Investment income
	1			15			Income taxes
	$	(1	)	$	(25	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(47	)	$	(47	)	(a)
	18			25			Income taxes
	$	(29	)	$	(22	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES	Three Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
	1			1			Income taxes (benefits)
	$	—		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(2	)	$	(40	)	Investment income (loss)
	1			15			Income taxes (benefits)
	$	(1	)	$	(25	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			2			Income taxes (benefits)
	$	(3	)	$	(3	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

15

The following amounts were reclassified from AOCI in the nine months ended September 30, 2013 and 2012:

FE	Nine Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(7	)	Other operating expenses
Long-term debt	9			6			Interest expense
	4			(1		)	Total before taxes
	(2		)	—			Income taxes
	$	2		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(27	)	$	(48	)	Investment income
	10			18			Income taxes
	$	(17	)	$	(30	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(148	)	$	(143	)	(a)
	58			71			Income taxes
	$	(90	)	$	(72	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES	Nine Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(6	)	Other operating expenses
Long-term debt	2			—			Interest expense
	(3		)	(6		)	Total before taxes
	1			2			Income taxes (benefits)
	$	(2	)	$	(4	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(24	)	$	(46	)	Investment income (loss)
	9			17			Income taxes (benefits)
	$	(15	)	$	(29	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(16	)	$	(15	)	(a)
	6			5			Income taxes (benefits)
	$	(10	)	$	(10	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

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7. INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Judgment is required in determining FirstEnergy's income taxes and in evaluating tax positions taken or expected to be taken on its tax returns. In the third quarter of 2013, FirstEnergy increased its liability for unrecognized income tax benefits by approximately $5 million. There were no material changes to FirstEnergy's unrecognized income tax benefits during the first nine months of 2012.

As of September 30, 2013, it is reasonably possible that approximately $4 million of unrecognized income tax benefits may be resolved within the next twelve months, all of which, if recognized, would affect FirstEnergy's effective tax rate.

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 nine months of 2013 and 2012, there were no material changes to the amount of accrued interest. The net amount of interest accrued as of September 30, 2013 and December 31, 2012 was approximately $10 million and $9 million, respectively.

As of December 31, 2012, the deferred income taxes consisted of $319 million of current federal, $466 million of long-term federal and $389 million of state and local net operating loss carryforwards. The American Taxpayer Relief Act of 2012 (Act) was enacted in January 2013 and provides 50% accelerated (bonus) depreciation for qualifying expenditures made in 2013. As a result of the availability of 50% bonus depreciation for 2013, none of the $319 million of the current federal deferred tax asset as of December 31, 2012, will be realized in 2013, but will be available for future periods. As of September 30, 2013,FirstEnergy expects to utilize federal and state net operating loss carryforwards in the next twelve months and therefore has classified $290 million to current deferred income taxes.

As discussed in Note 3, Impairment of Long-Lived Assets, on July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating two coal-fired generating plants. As a result of the decision, FirstEnergy determined that it is more likely than not that certain state and local net operating loss carryforwards will not be realized through future operations or through the reversal of existing temporary differences. As a result, FirstEnergy recorded a valuation reserve of approximately $20 million against net operating loss carryforwards in the second quarter of 2013.

On July 9, 2013, Pennsylvania House Bill 465 (HB 465) was enacted, adopting new market-based sourcing rules for certain items of income as well as increasing the Pennsylvania net operating loss deduction credit for tax years beginning after December 31, 2013 and 2014 to the greater of 25% or $4 million of taxable income and 30% or $5 million of taxable income, respectively. Based on income projections, Pennsylvania net operating loss carryforward valuation reserves were reduced by approximately $8 million in the third quarter of 2013.

During the third quarter of 2013, FirstEnergy made changes to state apportionment factors in certain jurisdictions based on sales sourcing rules for electricity, which reduced deferred tax liabilities by approximately $9 million. Furthermore, in the third quarter of 2013, based on the assessment of business operations, FirstEnergy determined that income from certain subsidiaries should not be apportioned to certain tax jurisdictions due to the absence of business nexus. This assessment resulted in a reduction to deferred tax liabilities of approximately $22 million.

FirstEnergy's three and nine months ended September 30, 2013 effective tax rate was 26.9% and 35.6%, respectively. The effective tax rate for the three months ended September 30, 2013 benefited by reductions in valuation reserves against net operating loss carryforwards, and changes in state apportionment factors as described above. The effective tax rate for the nine months ended September 30, 2013 benefited by changes in state apportionment factors as discussed above, however, was partially offset by a net increase in valuation reserves against net operating loss carryforwards.

FirstEnergy's three and nine months ended September 30, 2012 effective tax rate was 42.1% and 41.7%, respectively. The effective tax rate for the three and nine months ended September 30, 2012 was negatively impacted by recognition of valuation reserves against net operating loss carryforwards and the elimination of certain tax deductions associated with Medicare Part D subsidies.

FES’ three and nine months ended September 30, 2013 effective tax rate was 41.1% and 30.6%, respectively. The effective tax rate for the nine months ended September 30, 2013 was impacted by the loss on debt redemptions of approximately $103 million and a $4 million valuation reserve against net operating loss carryforwards.

FES’three and nine months ended September 30, 2012 effective tax rate was 40.5% and 39.7%, respectively. FES’ effective tax rate for the three and nine months ended September 30, 2012 was negatively impacted by higher state apportionment allocation factors.

The 2013 effective tax rate for FirstEnergy and FES is estimated to be approximately 37%.

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8. 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. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.

VIEs included in FirstEnergy’s consolidated financial statements are: the PNBV capital trust that was created to refinance debt originally issued in connection with sale and leaseback transactions; wholly-owned limited liability companies of the Ohio Companies (as described below); wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs and special purpose limited liability companies created to issue environmental control bonds that were used to construct environmental control facilities.

In September 2012, the Ohio Companies formed CEI Funding LLC, OE Funding LLC and TE Funding LLC, respectively, as separate, wholly-owned limited liability SPEs. Each SPE is a bankruptcy-remote, special purpose limited liability company that is restricted to activities necessary to issue phase-in recovery bonds and perform other functions in connection with the bond issuance. Creditors of FirstEnergy and the Ohio Companies have no recourse to any assets or revenues of the SPEs. The phase-in recovery bonds issued by these SPEs are payable only from, and secured by, phase-in recovery property held by the SPEs (i.e. the right to impose, charge and collect irrevocable non-bypassable usage-based charges payable by retail electric customers in the service territories of the Ohio Companies) and the bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. The SPEs are considered VIEs and each one is consolidated into its applicable utility.InJune 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

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 nine months ended September 30, 2013, was primarily due to $6 million of distributions to owners.

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

Mining Operations

FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting.

Trusts

FirstEnergy's consolidated financial statements include PNBV. FirstEnergy used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE.

PATH-WV

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 that was to be constructed by PATH-WV.

On August 24, 2012, PJM removed the PATH project from its long-range expansion plans. See Note 12, Regulatory Matters, for additional information on the abandonment of PATH.

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 and the contract price for power is correlated with

18

the plant’s variable costs of production. FirstEnergy 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, any of these entities.

FirstEnergy has determined that for all but two of these NUG entities, it does not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold variable interests in the remaining two entities; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $48 million and $65 million during the three months ended September 30, 2013 and 2012, respectively and $139 million and $184 million during the nine months ended September 30, 2013 and 2012, respectively.

Sale and Leaseback

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 arrangements.

During 2012, NG repurchasedlessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for$129 million. In 2012, FG acquired certain equity and other lessor interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $262 millionand in March of 2013, FG acquired the remaining interests for approximately $221 million.

FES, 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 as of September 30, 2013:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,288	$	1,079	$	209
Other FE subsidiaries	762		329		433

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion.

9. FAIR VALUE MEASUREMENTS

RECURRING AND NONRECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques 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

19

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 FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs, NUGs and LCAPPs 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 periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than 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 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.

NUG contracts represent purchase 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 and adjusted periodically using a mark-to-model methodology, 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 ICE 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 and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2016/2017 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. See Note 10, Derivative Instruments for additional information regarding LCAAP contracts.

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 September 30, 2013, from those used as of December 31, 2012. 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.

20

Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the nine months ended September 30, 2013. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

FirstEnergy
Recurring Fair Value Measurements	September 30, 2013												December 31, 2012
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,299		$	—		$	1,299		$	—		$	1,259		$	—		$	1,259
Derivative assets - commodity contracts	4			197			—			201			—			252			—			252
Derivative assets - FTRs	—			—			3			3			—			—			8			8
Derivative assets - NUG contracts(1)	—			—			23			23			—			—			36			36
Equity securities(2)	461			—			—			461			310			—			—			310
Foreign government debt securities	—			101			—			101			—			126			—			126
U.S. government debt securities	—			171			—			171			—			179			—			179
U.S. state debt securities	—			226			—			226			—			299			—			299
Other(3)	160			157			—			317			126			227			—			353
Total assets	$	625		$	2,151		$	26		$	2,802		$	436		$	2,342		$	44		$	2,822
Liabilities
Derivative liabilities - commodity contracts	$	(5	)	$	(107	)	$	—		$	(112	)	$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—			—			(14		)	(14		)	—			—			(9		)	(9		)
Derivative liabilities - NUG contracts(1)	—			—			(233		)	(233		)	—			—			(290		)	(290		)
Derivative liabilities - LCAPP contracts(1)	—			—			(166		)	(166		)	—			—			(144		)	(144		)
Total liabilities	$	(5	)	$	(107	)	$	(413	)	$	(525	)	$	(3	)	$	(151	)	$	(443	)	$	(597	)
Net assets (liabilities)(4)	$	620		$	2,044		$	(387	)	$	2,277		$	433		$	2,191		$	(399	)	$	2,225

⁽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 or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽⁴⁾  Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, 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 and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2013 and December 31, 2012:

	NUG Contracts(1)									LCAPP Contracts(1)								FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2012 Balance	$	57		$	(349	)	$	(292	)	$	—	$	—		$	—		$	1		$	(23	)	$	(22	)
Unrealized gain (loss)	(20		)	(180		)	(200		)	—		1			1			6			(6		)	—
Purchases	—			—			—			—		(145		)	(145		)	13			(10		)	3
Settlements	(1		)	239			238			—		—			—			(12		)	30			18
December 31, 2012 Balance	$	36		$	(290	)	$	(254	)	$	—	$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
Unrealized gain (loss)	(6		)	(6		)	(12		)	—		(22		)	(22		)	1			2			3
Purchases	—			—			—			—		—			—			5			(15		)	(10		)
Settlements	(7		)	63			56			—		—			—			(11		)	8			(3		)
September 30, 2013 Balance	$	23		$	(233	)	$	(210	)	$	—	$	(166	)	$	(166	)	$	3		$	(14	)	$	(11	)

⁽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 September 30, 2013:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(11	)	Model	RTO auction clearing prices	($5.60) to $5.40	$0.62	Dollars/MWH
NUG Contracts	$	(210	)	Model	Generation Electricity regional prices	600 to 5,864,000 $41.40 to $57.30	1,421,000 $49.40	MWH Dollars/MWH
LCAPP Contracts	$	(166	)	Model	Regional capacity prices	$158.60 to $187.60	$171.20	Dollars/MW-Day

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FES
Recurring Fair Value Measurements	September 30, 2013												December 31, 2012
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	742		$	—		$	742		$	—		$	703		$	—		$	703
Derivative assets - commodity contracts	4			197			—			201			—			252			—			252
Derivative assets - FTRs	—			—			2			2			—			—			6			6
Equity securities(1)	338			—			—			338			294			—			—			294
Foreign government debt securities	—			58			—			58			—			61			—			61
U.S. government debt securities	—			26			—			26			—			27			—			27
Other(2)	—			94			—			94			—			104			—			104
Total assets	$	342		$	1,117		$	2		$	1,461		$	294		$	1,147		$	6		$	1,447
Liabilities
Derivative liabilities - commodity contracts	$	(5	)	$	(107	)	$	—		$	(112	)	$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—			—			(13		)	(13		)	—			—			(6		)	(6		)
Total liabilities	$	(5	)	$	(107	)	$	(13	)	$	(125	)	$	(3	)	$	(151	)	$	(6	)	$	(160	)
Net assets (liabilities)(3)	$	337		$	1,010		$	(11	)	$	1,336		$	291		$	996		$	—		$	1,287

⁽¹⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽³⁾  Excludes $12 million and $94 million as of September 30, 2013 and December 31, 2012, 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 September 30, 2013 and December 31, 2012:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2012 Balance	$	1		$	(7	)	$	(6	)
Unrealized gain (loss)	4			(4		)	—
Purchases	9			(7		)	2
Settlements	(8		)	12			4
December 31, 2012 Balance	$	6		$	(6	)	$	—
Unrealized loss	(1		)	(1		)	(2		)
Purchases	4			(12		)	(8		)
Settlements	(7		)	6			(1		)
September 30, 2013 Balance	$	2		$	(13	)	$	(11	)

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 September 30, 2013:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(11	)	Model	RTO auction clearing prices	($5.60) to $5.40	$0.40	Dollars/MWH

23

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, AFS securities and notes receivable.

At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value.

Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI.

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, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.

AFS Securities

FirstEnergy holds debt and equity securities within its NDT, nuclear fuel disposal and NUG trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes.

The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of September 30, 2013 and December 31, 2012:

	September 30, 2013(1)						December 31, 2012(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,825	$	21	$	1,846	$	1,827	$	34	$	1,861
FES	868		9		877		778		14		792
Equity securities
FirstEnergy	$	433	$	28	$	461	$	293	$	16	$	309
FES	317		21		338		281		13		294

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million.

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Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three months and nine months ended September 30, 2013 and 2012 were as follows:

Three Months Ended
September 30, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	368	$	9	$	(15	)	$	(21	)	$	26
FES	164		5		(3		)	(21		)	16
September 30, 2012	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	1,751	$	81	$	(30	)	$	(2	)	$	18
FES	1,059		60		(21		)	(2		)	10

Nine Months Ended
September 30, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	1,545	$	49	$	(31	)	$	(74	)	$	74
FES	650		38		(14		)	(66		)	44
September 30, 2012	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	2,133	$	118	$	(58	)	$	(9	)	$	51
FES	1,167		85		(40		)	(8		)	27

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of September 30, 2013 and December 31, 2012:

	September 30, 2013						December 31, 2012
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	46	$	1	$	47	$	54	$	30	$	84

Investments in emission allowances, employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $646 million as of September 30, 2013, and $644 million as of December 31, 2012, 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 as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate 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:

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	September 30, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	17,007	$	17,721	$	16,957	$	19,460
FES	3,015		3,082		4,194		4,524

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. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of September 30, 2013 and December 31, 2012.

During the first quarter of 2013, FE issued in aggregate $1.5 billion of senior unsecured notes in two series: $650 million of 2.75% senior notes due March 15, 2018 and $850 million of 4.25% senior notes due March 15, 2023. The stated interest rates are subject to adjustments based upon changes in the credit ratings of FirstEnergy but will not decrease below the issued rates. The proceeds were used to repay short-term borrowings and to invest in the money pool for FES and AE Supply's use in funding a portion of their concurrent tender offers.

Also during the first quarter of 2013, pursuant to tender offers launched in February 2013, FES and AE Supply repurchased $369 million and $294 million, respectively, of outstanding senior notes with interest rates ranging from 5.75% to 6.8%. The $369 million of FES repurchases consisted of original maturities of $252 million due 2021 and $117 million due 2039. The $294 million of AE Supply repurchases consisted of original maturities of $194 million due 2019 and $100 million due 2039. FES and AE Supply paid $67 million and $43 million, respectively, in tender premiums to repurchase the tendered senior notes. FirstEnergy recorded a loss on debt redemption of $119 million (FES - $71 million), including such premiums and other related expenses. The tender premiums paid are included in cash flows from financing activities in the Consolidated Statement of Cash Flows.

In March 2013, ME issued $300 million of 3.50% senior unsecured notes due March 15, 2023. Proceeds from this offering were used to repay $150 million of ME 4.95% senior unsecured notes that matured in March 2013 and short-term borrowings.

On April 15, 2013, FES redeemed $400 million of its 4.80% senior notes due 2015 and recorded a loss on debt redemption of $32 million including $31 million of make-whole premiums paid. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

On June 3, 2013, FG exercised a mandatory put option and repurchased approximately $235 million of PCRBs due 2023, which FG is currently holding for remarketing subject to future market and other conditions.

As discussed in Note 8, Variable Interest Entities, in June 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

During August, the Ohio Companies redeemed an additional $660 million of long-term debt with interest rates ranging from 5.65% to 7.25% and paid approximately $120 million of make-whole premiums which were deferred as a regulatory asset and will be amortized over the original life of the redeemed debt. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. Additionally, during August, JCP&L issued $500 million of 4.7% unsecured notes due April 2024 and used the proceeds to pay down a portion of its short-term debt obligations.

On May 8, 2013, FE, FES, and FE's other borrowing subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each facility was extended until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. The FE Facility was amended to increase the lending banks' commitments under the facility by $500 million to a total of $2.5 billion and to increase the individual borrower sub-limits for FE by $500 million to a total of $2.5 billion and for JCP&L by $175 million to a total of $600 million.

On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the facility. Similarly, the FES/AE Supply $2.5 billion revolving credit facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges

26

of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. The effect of these amendments will apply to the compliance reports for the period ended September 30, 2013, which are due November 29, 2013.

10. 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 contractual derivative agreements through 2031.

Cash Flow Hedges

FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. The effective portion of gains and losses on a derivative contract is 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 instruments previously designated to be in a cash flow hedging relationship totaled $5 million and $10 million as of September 30, 2013 and December 31, 2012, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $10 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. No forward starting swap agreements accounted for as a cash flow hedge were outstanding as of September 30, 2013 or December 31, 2012. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $61 million and $70 million as of September 30, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months.

Refer to Note 6, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three and nine months ended September 30, 2013 and 2012.

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 September 30, 2013 and December 31, 2012, no fixed-for-floating interest rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $48 million and $79 million as of September 30, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $13 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $4 million and $6 million during the three months ended September 30, 2013 and 2012, respectively and $15 million and $17 million during the nine months ended September 30, 2013 and 2012, respectively. In connection with the redemptions of senior notes by FES and taxable bonds by CEI and OE, unamortized gains associated with fixed for floating interest rate swap agreements of $9 million and $17 million were included in the Gain (loss) on debt redemptions in the Consolidated Statements of Income for the three and nine months ended September 30, 2013, respectively. Refer to Note 9, Fair Value Measurements - Long-Term Debt and Other Long-Term Obligations, for additional information regarding FirstEnergy's debt redemptions during the three and nine months ended September 30, 2013.

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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 combustion turbine units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs.

As of September 30, 2013, FirstEnergy’s net asset position under commodity derivative contracts was $89 million, which related to FES positions. Under these commodity derivative contracts, FES posted $43 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $9 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 September 30, 2013, an adverse change of 10% in commodity prices would decrease net income by approximately $27 million during the next twelve months.

Interest Rate Swaps

In 2013, in connection with certain debt redemptions, FirstEnergy recorded gains of approximately $17 million, including $9 million in the third quarter related to terminated interest rate swaps. In August 2012, FirstEnergy terminated all of the forward starting swap agreements that were executed in the second quarter of 2012, resulting in a net gain, recorded in the third quarter of 2012 as a reduction to interest expense, and cash proceeds of approximately $6 million.

NUGs

As of September 30, 2013, FirstEnergy's net liability position under NUG contracts was $210 million representing contracts held at JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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. 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 with a corresponding regulatory asset. Since the LCAPP contracts are subject to regulatory accounting, changes in their fair value do not impact earnings. On October 11, 2013, the U.S. District Court for the District of New Jersey declared that the LCAPP is preempted by the FPA and unconstitutional. On October 22, 2013, the Superior Court of New Jersey Appellate Division dismissed two consolidated appeals which had been taken from the final order of the NJBPU which accepted and adopted the recommendation of the NJBPU's Agent regarding implementation of the LCAPP law. Dismissal of the consolidated appeals, along with pending matters currently on remand to the NJBPU, was without prejudice subject to the parties exercising their appellate rights in the federal courts. JCP&L continues to maintain a derivative liability with a corresponding regulatory asset on its Consolidated Balance Sheet until the the matter is finally resolved.

FTRs

As of September 30, 2013, FirstEnergy's and FES's net liability position under FTRs was $11 million and FES posted $6 million of collateral. 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 FES and AE Supply are included in other operating expenses

28

as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s utilities 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.

FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:

Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	September 30, 2013		December 31, 2012			September 30, 2013			December 31, 2012
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	137	$	153	Commodity Contracts	$	(94	)	$	(119	)
FTRs	3		7		FTRs	(11		)	(7		)
	140		160			(105		)	(126		)
					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs	(233		)	(290		)
Deferred Charges and Other Assets - Other					LCAAP	(166		)	(144		)
Commodity Contracts	64		99		Noncurrent Liabilities - Other
FTRs	—		1		Commodity Contracts	(18		)	(36		)
NUGs	23		36		FTRs	(3		)	(2		)
	87		136			(420		)	(472		)
Derivative Assets	$	227	$	296	Derivative Liabilities	$	(525	)	$	(598	)

FirstEnergy enters into contracts with counterparties that allow for net settlement of derivative assets and derivative liabilities. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative instruments on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position:

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				Amounts Not Offset in Consolidated Balance Sheet
September 30, 2013	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	201		$	(104	)	$	(11	)	$	86
FTRs	3			(3		)	—			—
NUG contracts	23			—			—			23
	$	227		$	(107	)	$	(11	)	$	109
Derivative Liabilities
Commodity contracts	$	(112	)	$	104		$	5		$	(3	)
FTRs	(14		)	3			6			(5		)
NUG contracts	(233		)	—			—			(233		)
LCAPP contracts	(166		)	—			—			(166		)
	$	(525	)	$	107		$	11		$	(407	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2012	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	252		$	(142	)	$	(5	)	$	105
FTRs	8			(8		)	—			—
NUG contracts	36			—			—			36
	$	296		$	(150	)	$	(5	)	$	141
Derivative Liabilities
Commodity contracts	$	(155	)	$	142		$	12		$	(1	)
FTRs	(9		)	8			1			—
NUG contracts	(290		)	—			—			(290		)
LCAPP contracts	(144		)	—			—			(144		)
	$	(598	)	$	150		$	13		$	(435	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2013:

	Purchases	Sales	Net		Units
	(In millions, except for LCAPP)
Power Contracts	32	37	(5	)	MWH
FTRs	59	—	59		MWH
NUGs	11	—	11		MWH
LCAPP	408	—	408		MW
Natural Gas	64	—	64		mmBTU

30

The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months and nine months ended September 30, 2013 and 2012, are summarized in the following tables:

	Three Months Ended September 30
	Commodity Contracts			FTRs			Interest Rate Swaps		Total
	(In millions)
2013
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	11		$	(8	)	$	—	$	3
Realized Gain (Loss) Reclassified to:
Revenues	$	14		$	6		$	—	$	20
Purchased Power Expense	(17		)	—			—		(17		)
Other Operating Expense	—			(10		)	—		(10		)
Fuel Expense	(2		)	—			—		(2		)
2012
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	7		$	(5	)	$	—	$	2
Interest Expense	—			—			20		20
Realized Gain (Loss) Reclassified to:
Revenues	$	46		$	6		$	—	$	52
Purchased Power Expense	(27		)	—			—		(27		)
Other Operating Expense	—			(10		)	—		(10		)
Fuel Expense	3			—			—		3
Interest Expense	—			—			6		6

	Nine Months Ended September 30
	Commodity Contracts			FTRs			Interest Rate Swaps		Total
	(In millions)
2013
Unrealized Loss Recognized in:
Other Operating Expense	$	(5	)	$	(10	)	$	—	$	(15	)
Realized Gain (Loss) Reclassified to:
Revenues	$	29		$	19		$	—	$	48
Purchased Power Expense	(30		)	—			—		(30		)
Other Operating Expense	—			(28		)	—		(28		)
2012
Unrealized Gain Recognized in:
Other Operating Expense	$	72		$	12		$	—	$	84
Realized Gain (Loss) Reclassified to:
Revenues	$	260		$	18		$	—	$	278
Purchased Power Expense	(248		)	—			—		(248		)
Other Operating Expense	—			(51		)	—		(51		)
Fuel Expense	2			—			—		2
Interest Expense	—			—			6		6

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The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2013 and 2012, are summarized in the following tables:

	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	7		$	(8	)	$	1		$	—
Realized Gain (Loss) on Derivative Instrument	14			—			(1		)	13
2012
Unrealized Gain (Loss) on Derivative Instrument	$	(50	)	$	3		$	—		$	(47	)
Realized Gain (Loss) on Derivative Instrument	61			—			(1		)	60

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	(13	)	$	(22	)	$	1		$	(34	)
Realized Gain (Loss) on Derivative Instrument	57			—			(1		)	56
2012
Unrealized Loss on Derivative Instrument	$	(183	)	$	(142	)	$	—		$	(325	)
Realized Gain on Derivative Instrument	194			—			7			201

The following tables provide 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 nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of July 1, 2013	$	(231	)	$	(158	)	$	—		$	(389	)
Additions/Change in value of existing contracts	7			(8		)	1			—
Settled contracts	14			—			(1		)	13
Outstanding net liability as of September 30, 2013	$	(210	)	$	(166	)	$	—		$	(376	)
Outstanding net liability as of July 1, 2012	$	(293	)	$	(145	)	$	—		$	(438	)
Additions/Change in value of existing contracts	(50		)	3			—			(47		)
Settled contracts	61			—			(1		)	60
Outstanding net liability as of September 30, 2012	$	(282	)	$	(142	)	$	(1	)	$	(425	)

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of January 1, 2013	$	(254	)	$	(144	)	$	—		$	(398	)
Additions/Change in value of existing contracts	(13		)	(22		)	1			(34		)
Settled contracts	57			—			(1		)	56
Outstanding net liability as of September 30, 2013	$	(210	)	$	(166	)	$	—		$	(376	)
Outstanding net liability as of January 1, 2012	$	(293	)	$	—		$	(8	)	$	(301	)
Additions/Change in value of existing contracts	(183		)	(142		)	—			(325		)
Settled contracts	194			—			7			201
Outstanding net liability as of September 30, 2012	$	(282	)	$	(142	)	$	(1	)	$	(425	)

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11. ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.

The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not in the recognition of the liability.

The following table summarizes the changes to the ARO balances during 2013:

ARO Reconciliation	FirstEnergy			FES
	(In millions)
Balance, December 31, 2012	$	1,599		$	965
Liabilities settled	(13		)	(14		)
Accretion	85			52
Revisions in estimated cash flows	163			156
Balance, September 30, 2013	$	1,834		$	1,159

During the first quarter of 2013, revisions to estimated cash flows associated with the ARO liability of FES increased the liability. The revision in estimated cash flows related primarily to increased cost estimates for the closure of LBR. The revised cost estimates were the result of a Closure Plan submitted to the PA DEP by FG on March 28, 2013, which provides for placing a final cap over LBR. See Note 13, Commitments, Guarantees, and Contingencies for additional information related to the closure of LBR.

During the third quarter of 2013, studies were completed to update the estimated cost of asbestos remediation for TE and FES. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and TE and increased the liability for FES and TE by approximately $5 million and $7 million, respectively.

12. 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.

As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates.In addition, if FES, AE Supply or any of their subsidiaries were to engage in the construction of significant new generation facilities in any of those states, they would also be subject to state siting authority.

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 that are overseen by the MDPSC and a third party monitor.Although settlements with respect to residential SOS for PE customers expired on December 31, 2012, by statute, service continues in the same manner unless changed by order of the MDPSC.The settlement provisions relating to non-residential SOS have also expired, however, 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.PE's initial plan submitted in compliance with the statute was approved in 2009 and covered 2009-2011, the first three years of the statutory period.Expenditures were originally estimated to

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be approximately$101 millionfor the PE programs for the entire period of 2009-2015.Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, on August 31, 2011, PE filed a new comprehensive plan for the second three year period, 2012-2014, that includes additional and improved programs.The 2012-2014 plan is expected to cost approximately$66 millionout of the original$101 millionestimate for the entire EmPOWER program.On December 22, 2011, the MDPSC issued an order approving PE's second plan with various modifications and follow-up assignments.PE continues to recover program costs subject to afive-year amortization.Maryland law only allows for the utility to recover lost distribution revenue attributable to 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.

Pursuant to a bill passed by the Maryland legislature in 2011, the MDPSC adopted rules, effective May 28, 2012, 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 MDPSC will be required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day, per violation.The new rules set utility-specific SAIDI and SAIFI targets for 2012-2015; prescribe detailed tree-trimming requirements, outage restoration and downed wire response deadlines; and impose other reliability and customer satisfaction requirements.PE has advised the MDPSC that compliance with the new rules is expected to increase costs by approximately$106 millionover the period 2012-2015.On April 1, 2013, the Maryland electric utilities, including PE, filed their first annual reports on compliance with the new rules.The MDPSC conducted a hearing on August 20, 2013 to discuss the reports, after which an order was issued on September 3, 2013, which accepted PE's filing and the operational changes proposed therein.

Following a "derecho" storm through the region on June 29, 2012, the MDPSC convened a new proceeding to consider matters relating to the electric utilities' performance in responding to the storm.Hearings on the matter were conducted in September 2012.Concurrently, Maryland's governor convened a special panel to examine possible ways to improve the resilience of the electric distribution system.On October 3, 2012, that panel issued a report calling for various measures including: acceleration and expansion of some of the requirements contained in the reliability standards which had become final on May 28, 2012; for selective increased investment in system hardening; for creation of separate recovery mechanisms for the costs of those changes and investments; and penalties or bonuses on returns earned by the utilities based on their reliability performance.On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the utilities to submit several reports over a series of months, relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations.The order further requires the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information.PE has responded to the requirements in the order consistent with the schedule set forth therein.PE's final filing on September 3, 2013, discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 27 Order, and projected that it would expect to make approximately$2.7 billionin infrastructure investments over15years to attempt to achieve the quickest level of response for the largest storm projected in the February 27 Order.The MDPSC has ordered that certain reports of its Staff relating to these matters be provided by May 1, 2014, and otherwise, has not issued a schedule for further proceedings in this matter.

NEW JERSEY

JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service.The supply for BGS, which is comprised oftwocomponents, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU.OneBGS 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.

On September 7, 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, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that JCP&L 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.The rate case petition was filed on November 30, 2012.In the filing, JCP&L requested approval to increase its revenues by approximately$31.5 millionand reserved the right to update the filing to include costs associated with the impact of Hurricane Sandy.The NJBPU has transmitted the case to the New Jersey Office of Administrative Law for further proceedings and an ALJ has been assigned.On February 22, 2013, JCP&L updated its filing to request recovery of$603 millionof distribution-related Hurricane Sandy restoration costs, resulting in increasing the total revenues requested to approximately$112 million.On June 14, 2013, JCP&L further updated its filing to: 1) include the impact of a depreciation study which had been directed by the NJBPU; 2) remove costs associated with 2012 major storms, consistent with the NJBPU orders establishing a generic proceeding to review 2011 and 2012 major storm costs (discussed below); and 3) reflect other revisions to JCP&L's filing.That filing represented an increase of approximately$20.6 millionover the revenues produced by existing base rates.Testimony has also been filed in the matter by the Division of Rate Counsel and several other intervening parties in opposition to the base rate increase JCP&L requested. Specifically, the testimony of the Division of Rate Counsel's witnesses recommended that revenues produced by JCP&L's base

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rates for electric service be reduced by approximately$202.8 million(such amount did not address the revenue requirements associated with major storm events of 2011 and 2012, which are subject to review in the generic proceeding).JCP&L filed rebuttal testimony in response to the testimony of other parties on August 7, 2013. Hearings in the rate case have commenced and are scheduled to continue through mid-November.

On March 20, 2013, the NJBPU ordered that a generic proceeding be established to investigate the prudence of costs incurred by all New Jersey utilities for service restoration efforts associated with the major storm events of 2011 and 2012.The Order provided that if any utility had already filed a proceeding for recovery of such storm costs, to the extent the amount of approved recovery had not yet been determined, the prudence of such costs would be reviewed in the generic proceeding.On May 31, 2013, the NJBPU clarified its earlier order to indicate that the 2011 major storm costs would be reviewed expeditiously in the generic proceeding with the goal of maintaining the base rate case schedule established by the ALJ where recovery of such costs would be addressed.The NJBPU further indicated in the May 31 clarification that it would review the 2012 major storm costs in the generic proceeding and the recovery of such costs would be considered through a Phase II in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding.On June 21, 2013, consistent with NJBPU's orders, JCP&L filed the detailed report in support of recovery of major storm costs with the NJBPU.On October 23, 2013, a prehearing order was issued and established that evidentiary hearings in this proceeding will be held in January 2014. JCP&L intends to vigorously pursue its position in the base rate case and full recovery of the costs associated with the major storm events of 2011 and 2012 but we cannot predict the outcome of these proceedings.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held in September 2011 to solicit comments regarding the state of preparedness and responsiveness of New Jersey's EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011.Additionally, the NJBPU accepted written comments through October 28, 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 consultant's report was submitted to and subsequently accepted by the NJBPU on September 12, 2012.JCP&L submitted written comments on the report.On January 24, 2013, based upon recommendations in its consultant's report, the NJBPU ordered the New Jersey EDCs to take a number of specific actions to improve their preparedness and responses to major storms.The order includes specific deadlines for implementation of measures with respect to preparedness efforts, communications, restoration and response, post event and underlying infrastructure issues.On May 31, 2013, the NJBPU ordered that the New Jersey EDCs implement a series of new communications enhancements intended to develop more effective communications among EDCs, municipal officials, customers and the NJBPU during extreme weather events and other expected periods of extended service interruptions.The new requirements include making information regarding estimated times of restoration available on the EDC's web sites and through other technological expedients.JCP&L is implementing the required measures consistent with the schedule set out in the above NJBPU's orders.

OHIO

The Ohio Companies primarily operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include:

• Generation supplied through a CBP;

• 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 thefive-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 million, subject to the outcome of certain PJM proceedings.The Ohio Companies have also agreed to establish a$12 millionfund 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 fortwoyears.The ESP 3 Application was approved by the PUCO on July 18, 2012.Several parties timely filed applications for rehearing.The PUCO issued an Entry on Rehearing on January 30, 2013 denying all applications for rehearing.Notices of appeal to the Supreme Court of Ohio were filed bytwoparties in the case, Northeast Ohio Public Energy Council and the ELPC.The matter has not yet been scheduled for oral argument.

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As approved, the ESP 3 plan continues certain provisions from the current ESP including:

• Continuing the current base distribution rate freeze through May 31, 2016;

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

• A6%generation rate 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);

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

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

As approved, the ESP 3 plan will provide additional provisions, including:

• Securing generation supply for a longer period of time by conducting an auction for athree-year period rather than aone-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

• Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

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.The Ohio Companies were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.On May 15, 2013, the Ohio Companies filed their 2012 Status Update Report in which they indicated compliance with 2012 statutory energy efficiency and peak demand reduction benchmarks.

In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.Estimated costs for thethreeOhio Companies' plans total approximately$250 millionover the three-year period, which is expected to be recovered in rates to the extent approved by the PUCO.Hearings were held with the PUCO in October 2012.On March 20, 2013, the PUCO approved the three-year portfolio plan for 2013-2015.Applications for rehearing were filed by the Ohio Companies and several other parties on April 19, 2013.The Ohio Companies filed their request for rehearing primarily to challenge the PUCO's decision to mandate that they offer planned energy efficiency resources into PJM's base residual auction.On May 15, 2013, the PUCO granted the applications for rehearing for the sole purpose of further consideration of the matter.On July 17, 2013, the PUCO issued an entry on rehearing denying the Ohio Companies' application for rehearing, in part, but authorizing the Ohio Companies' to receive20%of any revenues obtained from bidding energy efficiency and demand response reserves into the PJM auction.The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to the extent that such costs or penalties are prudently incurred.On August 16, 2013, ELPC and OCC filed applications for rehearing under the basis that the PUCO's authorization for the Ohio Companies to share in the PJM revenues was unlawful.The PUCO granted rehearing on September 11, 2013 for the sole purpose of further consideration of the issue.

On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with and are not supported by statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal. The Ohio Companies' response was filed on November 4, 2013.

Additionally, under SB221, electric utilities and electric service companies in Ohio are required to serve part of their load from renewable energy resources measured by an annually increasing percentage amount.In August and October 2009 and in August 2010, the Ohio Companies conducted RFPs to secure RECs.The RECs acquired through thesethreeRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conductedtwoRFP processes to obtain RECs to meet the statutory benchmarks for 2011 and contribute toward meeting the benchmark for future years.On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies will recover the costs of acquiring these RECs.The PUCO selected auditors to perform a financial and management audit, and final audit reports were filed with the PUCO on August 15, 2012.While generally supportive of the Ohio Companies' approach to procurement of RECs, the management/performance auditor recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state all renewable obligations that the auditor characterized as excessive.A hearing for this matter commenced on February 19, 2013, and concluded on February 25, 2013.The PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of renewable energy credits to meet statutory mandates in all instances except for part of the purchases arising from one auction and directing the Ohio Companies to credit non-shopping customers in the amount of$43.3 million, plus interest, with such crediting to commence within60days following the issuance of a final appealable order on the basis that the Ohio Companies did not prove such purchases were prudent.The Ohio Companies, along with other parties, timely filed applications for rehearing on September 6, 2013. On September 18, 2013, the PUCO issued an entry on rehearing granting rehearing solely for the purpose of further consideration of the matters specified therein.

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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 achieved their in-state solar compliance requirements for 2012.The Ohio Companies also held a short-term RFP process to obtain all state SRECs and both in-state and all state non-solar RECs to help meet the statutory benchmarks for 2012.The Companies recently reported that all of the Ohio Companies met their annual renewable energy resource requirements for reporting year 2012.The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.

The PUCO instituted a statewide investigation on December 12, 2012 to evaluate the vitality of the competitive retail electric service market in Ohio.The PUCO provided interested stakeholders the opportunity to provide comments ontwenty-twoquestions.The questions posed are categorized as market design and corporate separation.The Ohio Companies timely filed their comments on March 1, 2013, and filed reply comments on April 5, 2013.The PUCO has scheduled a series of workshops for the remainder of 2013, the first of which commenced on July 9, 2013.The Ohio Companies cannot predict the outcome of this investigation.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expired on May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs 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 DSPs 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.The PPUC entered an opinion and order on August 16, 2012, which primarily resolved those issues related to procurement and rate design, but required the submission of revised proposals regarding the retail market enhancement programs.The Pennsylvania Companies filed revised proposals on the retail market enhancements on November 14, 2012.A final order was entered on February 15, 2013, which addressed minor changes to the Pennsylvania Companies' revised enhancement proposals and ordered two choices for cost recovery of those programs.On February 28, 2013, the Pennsylvania Companies filed a petition to amend the August 16, 2012, order related to the description of how the hourly industrial product is to be priced.On April 4, 2013, the PPUC entered a Final Order postponing the implementation ofoneof the retail market enhancements.On March 20, 2013, answers supporting and opposing the Pennsylvania Companies' February 28 petition were filed by several parties.On July 16, 2013, the PPUC entered an order granting the Pennsylvania Companies' February 28, 2013 petition, thereby amending its August 16, 2012 order and clarifying the description of the hourly industrial product pricing. The Pennsylvania Companies are actively implementing their DSPs as of June 1, 2013. On November 4, 2013, the Pennsylvania Companies filed a default service plan that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2015 through May 31, 2017. The Pennsylvania Companies proposed programs call for quarterly descending clock auctions to procure 3, 12, 24, and 48-month energy contracts, as well as, one RFP seeking 2-year contracts to secure solar renewable energy credits for ME, PN, and Penn. The Pennsylvania Companies expect a decision from the PPUC within nine months.

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 refunded those amounts to customers over a29-month period that began in January of 2011.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's and PN's TSC riders.The Pennsylvania Supreme Court denied ME's and PN's Petition for Allowance of Appeal on February 28, 2012, and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari on October 9, 2012.On July 13, 2011, ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania for the purpose of obtaining an order that would enjoin enforcement of the PPUC and Pennsylvania court orders under a theory of federal preemption on the question of retail rate recovery of the marginal transmission loss charges.Proceedings in the U.S. District Court effectively were suspended until conclusion of the proceedings before the United States Supreme Court.Pursuant to procedural orders issued by U.S. District Court Judge Gardner, on December 21, 2012, the PPUC submitted its motion to dismiss the U.S. District Court proceedings.ME and PN submitted their answers on January 9, 2013, and subsequent pleadings were submitted by the PPUC, ME and PN.Oral arguments on the PPUC motion to dismiss took place on May 20, 2013.On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss. On October 29, 2013, ME and PN filed a notice of appeal in the U.S. Court of Appeals for the Third Circuit with respect to the U.S. District Court's decision.As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately$254 million(pre-tax) in the quarter ended September 30, 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. FirstEnergy continues to believe in the merits of its case.

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.

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 on utilities that fail to achieve the required reductions in consumption and peak demand.The Pennsylvania Companies submitted an interim 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 did not.WP could be subject to a statutory penalty of up to$20 millionand is unable to predict the outcome of this matter.On July 15, 2013, the Pennsylvania Companies filed their preliminary energy efficiency and demand reduction results for the period ending May 31, 2013, indicating that all Pennsylvania Companies are expected to meet their statutory obligations.The Pennsylvania Companies are expected to report their final energy efficiency and demand reduction results for the period ending May 31, 2013, by November 15, 2013.

Pursuant to Act 129, the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs.The PPUC found the energy efficiency programs to be cost effective and in an Order entered on August 3, 2012, the PPUC directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016.The PPUC has deferred ruling on the need to create peak demand reduction targets until it receives more information from the EE&C statewide evaluator.The Pennsylvania Companies filed their Phase II plans and supporting testimony in November 2012.On January 16, 2013, the Pennsylvania Companies reached a settlement with all but one party on all but one issue.The settlement provides for the Pennsylvania Companies to meet with interested parties to discuss ways to expand upon the EE&C programs and incorporate any such enhancements after the plans are approved, provided that these enhancements will not jeopardize the Pennsylvania Companies' compliance with their required targets or exceed the statutory spending caps.On February 6, 2013, the Pennsylvania Companies filed revised Phase II EE&C Plans to conform the plans to the terms of the settlement.Total costs of these plans are expected to be approximately$234 million.All such costs are expected to be recoverable through the Pennsylvania Companies reconcilable Phase II EE&C Plan C riders.The remaining issue, raised by a natural gas company, involved the recommendation that the Pennsylvania Companies include in their plans incentives for natural gas space and water heating appliances.On March 14, 2013 the PPUC approved the 2013-2016 EE&C plans of the Pennsylvania Companies, adopting the settlement, and rejecting the natural gas companies recommendations.

In addition, Act 129 required utilities to file a SMIP with the PPUC.On December 31, 2012, the Pennsylvania Companies filed their Smart Meter Deployment Plan.The Deployment Plan requests deployment of approximately98.5%of the smart meters to be installed over the period 2013 to 2019, and the remaining meters in difficult to reach locations to be installed by 2022, with an estimated life cycle cost of about$1.25 billion.Such costs are expected to be recovered through the Pennsylvania Companies' PPUC-approved Riders SMT-C.Evidentiary hearings have been held and briefs were submitted by the Pennsylvania Companies and the Office of Consumer Advocate.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market would 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 onelevendirected 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.A final order was issued on February 15, 2013 providing recommendations on the entities to provide default service, the products to be offered, billing options, customer education, and licensing fees and assessments, among other items.Subsequently, the PPUC establishedfiveworkgroups andonecomment proceeding in order to seek resolution of certain matters and to clarify certain obligations that arose from that order.

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 electricity 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 the Pennsylvania Companies and FES on March 27, 2012.If implemented these rules could require a significant change in the ways FES and the Pennsylvania Companies 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 the proposed rulemaking on April 26, 2012, 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.The House Consumer Affairs Committee of the Pennsylvania

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General Assembly also sent a letter to the Independent Regulatory Review Commission on July 12, 2012, noting its opposition to the proposed regulations as modified.

WEST VIRGINIA

MP and PE currently operate under a Joint Stipulation and Agreement of Settlement reached with the other parties and approved by the WVPSC in June 2010 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.

In February 2011, MP and PE filed a petition with the WVPSC seeking an order declaring that MP owns all RECs associated with the 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, opposed the petition.On November 22, 2011, the WVPSC granted ownership of all RECs produced by the facilities to MP, and held that an electric utility that purchases electric energy and capacity under an electric power purchase agreement with a Qualifying Facility under PURPA owns the RECs associated with that purchase.The West Virginia Supreme Court upheld the WVPSC's decision.The City of New Martinsville and Morgantown Energy Associates filed petitions at FERC alleging the WVPSC order violated PURPA and requested that FERC initiate an enforcement action.On April 24, 2012, FERC issued an order declining to act on the petitions and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court.MP and PE filed for rehearing of FERC's order, which was denied on September 20, 2012.The City of New Martinsville filed a complaint in the U.S. District Court for the Southern District of West Virginia on June 1, 2012, alleging that the WVPSC order violates PURPA.Morgantown Energy Associates has joined in filing a similar complaint and requesting damages in the same U.S. District Court.MP and PE filed for judgment on the pleadings in both cases on January 25, 2013.The WVPSC filed a motion to dismiss on June 28, 2013.On September 30, 2013, the District Court ruled in favor of MP and PE and the WVPSC and dismissed the proceedings with prejudice.

The WVPSC opened a general investigation into the June 29, 2012, derecho windstorm with data requests for all utilities.A public meeting for presentations on utility responses and restoration efforts was held on October 22, 2012 and two public input hearings have been held.The WVPSC issued an Order in this matter on January 23, 2013 closing the proceeding and directing electric utilities to file a vegetation management plan withinsix monthsand to propose a cost recovery mechanism.This Order also requires MP and PE to file a status report regarding improvements to their storm response procedures by the same date.On July 23, 2013, MP and PE filed their vegetation management plans, which provided for recovery of costs through a surcharge mechanism.On October 3, 2013, the WVPSC issued a procedural schedule for the vegetation management plan proceeding and scheduled a hearing for December 3, 2013.

MP and PE filed their Resource Plan with the WVPSC in August 2012 detailing both supply and demand forecasts and noting a substantial capacity deficiency.MP and PE have filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposes a net ownership transfer of1,476MW of coal-fired generation capacity to MP.The proposed transfer would involve MP's acquisition of the remaining ownership of the Harrison Power Station from AE Supply and the sale of MP's minority interest in the Pleasants Power Station to AE Supply.The proposed transfer would implement a cost-effective plan to assist MP in meeting its energy and capacity obligations with its own generation resources, eliminating the need to make unhedged electricity and capacity purchases from the spot market, which is expected to result in greater rate stability for MP's customers.The plan is expected to remedy MP's capacity and energy shortfalls, which are projected to worsen due to a projected increase in annual load growth of approximately1.4%.MP and PE will file a base rate case no later thansix monthsfrom the completion of the transaction.On February 11, 2013, the WVPSC issued an order adopting a procedural schedule for this matter and testimony and briefing has followed.MP and PE also filed with FERC for authorization to effect these transfers and on April 23, 2013, FERC issued an order authorizing the transfers.MP's application for FERC authorization to effect the financing was approved on May 13, 2013.Hearings were held at the WVPSC in late May and briefs and reply briefs have been submitted.A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013.On October 7, 2013, WVPSC issued an order authorizing the transaction, with certain conditions and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately$330 millionin the fourth quarter of 2013 to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base.Additionally, MP recognized a regulatory liability of approximately$23 millionin the fourth quarter of 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station. The transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. Currently, the $1.1 billion net consideration was financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million.

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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, FG, FENOC, ATSI and TrAIL.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 toeightregional 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.Any 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.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities.While FirstEnergy and other parties advocated for a traditional "beneficiary pays" (or usage based) 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.On August 6, 2009, 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 LSEs in PJM bearing the majority of the costs.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 (or socialized) 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 and on March 22, 2013, FERC denied rehearing.On March 29, 2013, FirstEnergy filed its Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated for briefing and disposition before that court. Briefing commenced on September 11, 2013, and is expected to continue into early 2014.Thereafter, the case will be scheduled for oral argument, with a decision currently expected in 2014.

Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order.To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of50%beneficiary pays and50%postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing.On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing.On March 22, 2013, FERC granted final acceptance of the hybrid method.Certain parties have sought rehearing of parts of FERC's March 22, 2013 order.These requests for rehearing are pending before FERC.On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the New York Independent System Operator region and; (2) the PJM region and the FERC-jurisdictional members of the Southeastern Regional Transmission Planning region.These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region.On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000.The July 10, 2013 filings are pending before FERC.

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”

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transmission project continues to be disputed; the details of the dispute are discussed below under "MISO Multi-Value Project Rule Proposal."In addition, FERC denied recovery of certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation issues by means of ATSI's transmission rate totaling approximately$78.8 millionuntil 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.On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve certain of the exit fee and transmission cost allocation issues that are outstanding with regard to ATSI's transmission rate revisions related to ATSI's move into PJM.On September 19, 2013, FERC rejected that settlement stating ATSI had not shown why its tariff changes are just and reasonable. FERC further stated, consistent with its initial May 31, 2011 ruling on this issue that its September 19, 2013 order is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the costs that are sought to be recovered in ATSI's transmission rates.On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

In the May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM could be charged to transmission customers in the ATSI zone.ATSI sought rehearing of the question of whether the ATSI zone should pay these legacy RTEP charges and, on September 20, 2012, FERC denied ATSI's request for rehearing.On November 19, 2012, ATSI filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit of FERC's ruling on the "legacy RTEP" issue, and ATSI's initial brief was filed with that court on April 11, 2013.FERC filed its brief on June 25, 2013, and FirstEnergy filed its reply brief on August 9, 2013, and final reply brief on August 28, 2013.FERC filed its final brief on August 30, 2013. The court has scheduled oral argument for December 11, 2013, and a decision is expected in the second quarter of 2014.

The 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 project that was approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would be allocated to and charged to ATSI.MISO estimated that approximately$16 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction.In addition, the MISO's MVP tariffs could assess costs on PJM loads that purchase energy that has flowed over the transmission systems into the MISO.

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.FirstEnergy asserts legal, factual and policy arguments.To date, FERC has responded in a series of orders that may require ATSI to absorb the charges for the Michigan Thumb Project pending the outcome of further regulatory proceedings and appeals.These further proceedings can be divided into two tracks: litigation related to MISO's generic MVP cost allocation proposal; and litigation related to MISO's "Schedule 39" tariff that purports to charge the MVP costs to ATSI.

Regarding the first litigation track, in 2010 and 2011 FERC issued orders that approved the MISO proposal.On October 31, 2011, FirstEnergy filed a Petition of Review of those 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 appeals were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit.Briefs were filed in late 2012 and early 2013, and the court heard oral arguments on April 10, 2013.On June 7, 2013, the Seventh Circuit issued an order that ratified FERC's acceptance of the MISO's proposed MVP tariff.On October 7, 2013, several parties, including FirstEnergy, filed appeals of the Seventh Circuit's decision with the U.S. Supreme Court.FirstEnergy continues to evaluate the Seventh Circuit's order and its substantive and procedural options on other holdings in the opinion.

Regarding the second litigation track, in February 2012, FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI.FERC 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.The hearings took place in April 2013, and on July 16, 2013 the ALJ issued an Initial Decision ruling that ATSI must pay the "Schedule 39" MVP costs.FirstEnergy and other parties submitted Briefs on Exceptions on August 15, 2013.The MISO and other parties filed Briefs Opposing Exceptions on September 4, 2013.The matter is pending before FERC for final decision.

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

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 U.S. Court of Appeals for the Ninth Circuit in several pending

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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 had previously remandedoneof those proceedings to FERC, which dismissed the claims of the California Parties in May 2011, and affirmed the dismissal in June 2012.On June 20, 2012, the California Parties appealed FERC's decision back to the Ninth Circuit.Briefing was completed before the Ninth Circuit on October 23, 2013.The timing of further action by the Ninth Circuit is unknown.

In another proceeding, in June 2009, the California Attorney General, on behalf of certain California parties, filed another complaint with FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during 2000 and 2001.The above-noted transactions with CDWR are the basis for including AE Supply in this complaint.AE Supply filed a motion to dismiss, which was granted by FERC in May 2011, and affirmed by FERC in June 2012.The California Attorney General has appealed FERC's dismissal of its complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and stayed the proceedings pending further order.

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 was proposed to be comprised of a765kV transmission line 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.On August 24, 2012, the PJM Board of Managers canceled the PATH project, which it had suspended in February 2011.As a result, approximately$62 millionand approximately$59 millionin costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery.On September 28, 2012, those companies requested authorization from FERC to recover the costs with a proposed return on equity of10.9%(10.4%base plus0.5%RTO membership) from PJM customers over the nextfiveyears.Several parties protested the request.On November 30, 2012, FERC issued an order denying the0.5%return on equity adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012 subject to settlement judge procedures and hearing if the parties do not agree to a settlement.The issues subject to settlement include the prudence of the costs, the base return on equity and the period of recovery.PATH-Allegheny and PATH-WV are currently engaged in settlement discussions with the other parties.Depending on the outcome of a possible settlement or hearing, if settlement is not achieved, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

PATH-Allegheny and PATH-WV have requested rehearing of FERC's denial of the0.5%return on equity adder for RTO membership; that request for rehearing remains pending before FERC.In addition, FERC has consolidated for settlement judge procedures and hearing purposes three formal challenges to the PATH formula rate annual updates submitted to FERC in June 2010, June 2011 and June 2012, with the September 28, 2012 filing for recovery of costs associated with the cancellation of the PATH project.FirstEnergy cannot predict the outcome of these matters or estimate the possible loss or range of loss.

Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FG.FG 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, FG initiated the ILP relicensing process by filing its notice of intent to relicense and related documents in the license docket.

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.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.FG believes it is entitled to a statutory “incumbent preference” under Section 15 and that it ultimately should prevail in these proceedings.Nevertheless, the Seneca Nation's pleadings reflect the Nation's apparent intent to obtain the license for the facility, and to assume ownership and operation of the facility as contemplated by the statute.

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 January 7, 2013, FirstEnergy and the Seneca Nation submitted their respective reports for the 2012 study season.On January 31 and February 1, 2013, respectively, the Seneca Nation and FirstEnergy each submitted their respective proposed study plans for the 2013 study season.On March 4, 2013, the Seneca Nation and other parties submitted comments regarding FirstEnergy's proposed study plans.In its comments, the Seneca Nation alleges that FirstEnergy does not hold the real estate rights necessary

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to operate a hydroelectric project in circumstances where there is flowage over the Seneca Nation's lands.On April 3, 2013, FirstEnergy filed its response to these and other assertions by the Seneca Nation and its allied parties.On May 3, 2013, FERC's Director of the Office of Energy Projects issued FERC Staff's study plan determinations for the 2013 study year.The Director determined that water level fluctuations in the lower reservoir due to hydroelectric project operations have no discernible effect on reservoir lands or environmental resources.This finding is expected to strengthen FirstEnergy's position that the project boundary should be defined to exclude the U.S. Army Corps of Engineers dam and reservoir facilities.FERC Staff's determinations also largely adopted FirstEnergy's position and arguments as to the proper scope of environmental studies for the 2013 study season.The study processes will extend through approximately November 2013.

On July 3, 2013, FirstEnergy and the Seneca Nation each submitted "Preliminary License Proposals" in the relicensing dockets.These submissions are intended to be non-binding indications of types of project upgrades that may be proposed in the parties' respective final licensing applications, as well as an indication of the scope and direction of the parties' plans for the upcoming final licensing applications.On October 1, 2013, FERC staff provided comments on FirstEnergy's and the Seneca Nation's Preliminary Licensing Proposals, including identifying deficiencies for the applicants to address in their applications. FirstEnergy and the Seneca Nation each are required to submit their application for the project license by December 2, 2013.

Hydroelectric Asset Sale

On September 4, 2013, certain of FirstEnergy’s subsidiaries submitted filings with FERC for authorization to sellelevenhydroelectric power plant projects to subsidiaries of Harbor Hydro Holdings, LLC (Harbor Hydro), a subsidiary of LS Power Equity Partners II, LP (LS Power) for approximately$400 million.Theelevenhydroelectric projects are: the Seneca Pumped Storage Project, Allegheny Lock & Dam No. 5, Allegheny Lock & Dam No. 6, the Lake Lynn Project, the Millville Hydro Project, the Dam No. 4 Project, the Dam No. 5 Project, and four additional projects located in Shenandoah, Front Royal and Luray, Virginia.Theelevenprojects have a combined generating capacity of approximately527MW.Resolution of the potential competing hydro license application of the Seneca Nation for the Seneca Pumped Storage Project and other claims and matters is a condition to closing of the proposed asset sale.FirstEnergy’s submittals for regulatory authorization include a request for authorization to transfer the hydroelectric licenses under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the hydroelectric projects under Part II of the FPA.On September 25, 2013, the Seneca Nation submitted a pleading in the Part II regulatory proceeding wherein the Seneca Nation reiterated the real estate and other claims that the Seneca Nation has advanced in the Seneca Pumped Storage Project relicensing proceeding. On October 18, 2013, the Seneca Nation reiterated its real estate claims in comments on the Part I application to transfer the license for the Seneca Pumped Storage Project.However, the Seneca Nation noted in both sets of comments that it does not oppose the proposed sale or license transfer “at this time.” On November 1, 2013, FERC issued an order granting the FPA Part II authorization to transfer the hydro assets (the license transfer application remains pending before FERC).Additional filings have been submitted to FERC for the purpose of implementing the transaction once regulatory approval is obtained. The VSCC also must approve the sale for the assets that are located in Virginia, and the application for such approval was submitted on September 19, 2013.Once the regulatory authorizations are granted and the other closing conditions are satisfied, FirstEnergy expects to close this asset sale transaction in the fourth quarter of 2013. See Note 16, Discontinued Operations and Assets Held for Sale for additional information regarding the potential asset sales.

MISO Capacity Portability

On June 11, 2012, 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 and the 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.FirstEnergy submitted comments and reply comments in August 2012.In the fall of 2012, FirstEnergy participated in certain stakeholder meetings to review various proposals advanced by MISO.Although none of MISO's proposals attracted significant stakeholder support, on January 3, 2013, MISO filed a pleading with FERC that renewed many of the arguments advanced in prior MISO filings and asked FERC to take expedited action to address MISO's allegations.FirstEnergy and other parties subsequently submitted filings arguing that MISO's concerns largely are without foundation and suggesting that FERC order that the remaining concerns be addressed in the existing stakeholder process that is described in the PJM/MISO Joint Operating Agreement.On April 2, 2013, FERC issued an order directing MISO and PJM to make presentations to FERC regarding ongoing regional efforts to address whether barriers to transfer capability exist between the MISO and PJM regions and the actions the FERC should take to address any such barriers.The RTOs presented their respective positions to FERC on June 20, 2013 and provided additional information regarding their stakeholder prioritization survey, in response to a FERC request on June 27, 2013.On September 26, 2013, the RTOs jointly submitted an informational filing providing a description of and schedule for their Joint and Common Market initiatives. FERC has not acted on the presentations, and the RTOs and affected parties are working to address the MISO's proposal in stakeholder proceedings.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 a negative impact on the prices at which those auctions would clear.

MOPR Reform

On December 7, 2012, PJM filed amendments to its tariff to revise the MOPR used in the RPM. PJM revised the MOPR to add two broad, categorical exemptions, eliminate an existing exemption, and to limit the applicability of the MOPR to certain capacity resources.The filing also included related and conforming changes to the RPM posting requirements and to those provisions

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describing the role of the Independent Market Monitor for the PJM Region.On May 2, 2013, FERC issued an order in large part accepting PJM's proposed reform of the MOPR, including the proposed exemptions and applicability but also requiring PJM to commit to future review and, if necessary, additional revisions to the MOPR to accommodate changing market conditions.On June 3, 2013, FirstEnergy submitted a request for rehearing of FERC's May 2, 2013 order.In its rehearing request, FirstEnergy referenced the results of the May 2013 PJM RPM capacity auction, and the data that is available in the public domain about the reasons for the unexpectedly low "rest-of-RTO" clearing price of $59 per MW-day, as supporting its contention that the MOPR reform depressed prices as predicted in FirstEnergy's December 28, 2012 and January 25, 2013 comments.FirstEnergy's request for rehearing is pending before FERC.

Synchronous Condensers

On December 20, 2012, FERC approved the transfer by FG to ATSI of certain deactivated generation assets associated with Eastlake Units 1 through 5 and Lakeshore Unit 18 to facilitate their conversion to synchronous condensers to provide voltage support on the ATSI transmission system.The transfer price of the assets was approximately$21.5 millionand the estimated conversion cost was approximately$60 million.The transfer of Eastlake Units 4 and 5 was completed on January 31, 2013 andATSI completed the conversion of Eastlake Unit 5 in July 2013 and is expected to complete Eastlake Unit 4 by June 1, 2014.The transfer of each of the remaining units and conversion to synchronous condensers will occur when the use of the unit for RMR purposes is no longer required.On January 22, 2013, ATSI requested clarification or, in the alternative, rehearing with respect to a statement in the FERC order authorizing the transfer that ATSI's current formula rate does not include the accounts and components necessary to allow for recovery of the costs associated with acquisition of the transferred assets and that ATSI must make a filing under Section 205 of the FPA in order to recover those costs.ATSI requested clarification from FERC noting its formula rate currently includes the necessary accounts and components to allow for such recovery and that a Section 205 filing is not required.On August 5, 2013, FERC clarified that the issue of whether the cost of the transferred facilities and any conversion costs could be included in ATSI’s formula rates is more appropriately addressed during ATSI’s yearly formula rate update process.Based on this clarification by FERC, FE and FES recognized a pre-tax gain of approximately$17 millionin the third quarter of 2013 representing the sales price to ATSI over the net book value.

FTR Underfunding Complaint

In PJM, FTRs are a mechanism to hedge congestion and they operate as a financial replacement for physical firm transmission service.FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price differences across a specific transmission path in the PJM Day-ahead Energy Market.FE also performs bilateral transactions for the purpose of hedging the price differences between the location of supply resources and retail load obligations. Due to certain language in the PJM tariff, the funds that are set aside to pay FTRs can be diverted to other uses, resulting in “underfunding” of FTR payments.Since June of 2010, FES and AE Supply have lost more than$63.5 millionin revenues that they otherwise would have received as FTR holders to hedge congestion costs.FES and AE Supply expect to continue to experience significant underfunding.

On December 28, 2011, FES and AE Supply filed a complaint with FERC for the purpose of modifying certain provisions in the PJM tariff to eliminate FTR underfunding.On March 2, 2012, FERC issued an order dismissing the complaint.In its order, FERC ruled that it was not appropriate to initiate action at that time because of the unknown root causes of FTR underfunding.FERC directed PJM to convene stakeholder proceedings for the purpose of determining the root causes of the FTR underfunding.FERC went on to note that its dismissal of the complaint was without prejudice to FES and AE Supply or any other affected entity filing a complaint if the stakeholder proceedings proved unavailing.FES and AE Supply sought rehearing of FERC's order and, on July 19, 2012, FERC denied rehearing.In April, 2012, PJM issued a report on FTR underfunding.However, the PJM stakeholder process proved unavailing as the stakeholders were not willing to change the tariff to eliminate FTR underfunding.Accordingly, on February 15, 2013, FES and AE Supply refiled their complaint with FERC for the purpose of changing the PJM tariff to eliminate FTR underfunding.Various parties filed responsive pleadings, including PJM.On June 5, 2013, FERC issued its order denying the new complaint.On July 5, 2013, FirstEnergy filed a request for rehearing of FERC's order.FirstEnergy's request for rehearing is pending before FERC.

13. 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 September 30, 2013, outstanding guarantees and other assurances aggregated approximately $4.4 billion, consisting of parental guarantees ($1,403 million), subsidiaries' guarantees ($2,232 million) and other guarantees ($747 million).

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

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COLLATERAL AND CONTINGENT-RELATED FEATURES

In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE'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 FE and its subsidiaries have margining provisions that require posting of collateral.Based on FES' power portfolio exposure as ofSeptember 30, 2013, FES has posted collateral of$150 million and AE supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of$16 million.

These credit-risk-related contingent features stipulate that if the subsidiary 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, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries.The following table discloses the additional credit contingent contractual obligations as ofSeptember 30, 2013:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	440	$	6	$	55	$	501
BB+/Ba1 Credit Ratings	$	484	$	6	$	55	$	545
Full impact of credit contingent contractual obligations	$	755	$	58	$	90	$	903

Excluded from the preceding chart is the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Services Segment.As ofSeptember 30, 2013, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$77 millionand$2 million, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FirstEnergy is a guarantor under a syndicated three-year senior secured term loan facility due October 18, 2015, under which Global Holding borrowed $350 million. Proceeds from the loan were used to repay Signal Peak's and Global Rail's maturing$350 millionsyndicated two-year senior secured term loan facility. In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, have also provided their joint and several guaranties of the obligations of Global Holding under the new facility.

In connection with the new facility,69.99%of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective33-1/3%membership interests in Global Holding, are pledged to the lenders under the new facility as collateral.

FirstEnergy, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed to use their best efforts to refinance the new facility no later than July 20, 2015, which reflects the terms of an amendment dated August 14, 2013, on a non-recourse basis so that FirstEnergy's guaranty can be terminated and/or released.If that refinancing does not occur, FirstEnergy may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the new facility in full.In lieu of providing such funding, the co-owners, at FirstEnergy's option, may provide their several guaranties of Global Holding's obligations under the facility.FirstEnergy receives a fee for providing its guaranty, payable semiannually, which accrued at a rate of4%through December 31, 2012, and accrues at a rate of5%from January 1, 2013 through October 18, 2015, which amends the rate in the prior agreement, in each case based upon the average daily outstanding aggregate commitments under the facility for such semiannual period.

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.

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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, utilizing 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 FG 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.FG believes the claims are without merit and intends to vigorously 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 possible loss or range of loss.

In January 2009, the EPA issued an 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, as a former owner of the facilities, is 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 during 1991 to 1994 without pre-construction 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 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. DOJ 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 which affirmed the dismissal on August 21, 2013.PN believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints.The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.PN is unable to predict the outcome of this matter or estimate the loss or possible range of loss.

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.FG intends to comply with the CAA and Ohio regulations, 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 an 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, January 31, 2013, and March 27, 2013, EPA issued additional CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007.AE 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 June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Allegheny Utilities 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.

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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 December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit and was ultimately vacated by the Court on August 21, 2012.The Court has ordered EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR.On January 24, 2013, EPA and intervenors' petitions seeking rehearing or rehearing en banc were denied by the U.S. Court of Appeals for the District of Columbia Circuit.On June 24, 2013, the Supreme Court of the United States agreed to review the decision vacating CSAPR.Oral argument is scheduled for December 10, 2013.Depending on the outcome of these proceedings and how any final rules are ultimately implemented, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' 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.On December 28, 2012, the WVDEP granted a conditional extension through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants stations.On March 20, 2013, the PA DEP granted an extension through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Mansfield stations.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.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. Oral argument is scheduled for December 10, 2013.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 currently estimated to be approximately$465 million.

As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated.FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated.As of October 9, 2013, the Hatfield's Ferry and Mitchell stations were also deactivated.

FirstEnergy and FES have various long-term coal transportation agreements, some of which run through 2025 and certain of which are related to the plants described above.We have asserted force majeure defenses for delivery shortfalls under certain agreements, and we are in discussion with the applicable counterparties.Under one agreement, we have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately$45 million, and agreed to pay liquidated damages for delivery shortfalls, if any, for 2013 and 2014.As to another agreement, based on the state of current negotiations, penalties of approximately$25 millionfor delivery shortfalls for 2012 were recorded in the third quarter of 2013, and we could incur additional penalties for any delivery shortfalls in 2013 and 2014.If we fail to reach a resolution with applicable counterparties for the unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to our belief, the force majeure provisions or other defenses do not excuse delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the state, federal and international level.Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs to control emissions of certain GHGs.In his 2013 State of the Union address, President Obama called for Congressional action on GHG emissions indicating his administration will take action in the event Congress fails to act.In June 2013, the President's Climate Action Plan outlined Executive action to: (1) cut carbon pollution in America, including EPA carbon pollution standards for both new and existing power plants by17%by 2020 (from 2005 levels), (2) prepare the United States for the impacts of climate change, and (3) lead international efforts to combat global climate change and prepare for its impacts.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required the measurement and reporting of 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

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until January 2, 2011, at the earliest.In May 2010, the EPA finalized new thresholds for GHG emissions that define when NSR pre-construction permits would be required including an emissions applicability threshold of75,000tons per year of CO₂equivalents for existing facilities under the CAA's PSD program. On April 13, 2012, the EPA proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units that are larger than25MW, which were ultimately withdrawn.On June 25, 2013, a Presidential memorandum directed EPA to complete, in a timely fashion, proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units, starting with re-proposal by September 20, 2013, and propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units.On September 20, 2013, EPA proposed a new source performance standard of 1,000 lbs. CO₂/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for fossil fuel fired units which would require partial carbon capture and storage.On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 D.C. Circuit Court of Appeals decision upholding EPA's May 2010 regulations to decide a single narrow question: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases?" Depending on the outcome of these proceedings and how any final rules are ultimately implemented, future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.

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 by 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.In December 2010, the U.N. Climate Change Conference in Cancun, Mexico resulted in an acknowledgment to reduce emissions from industrialized countries by 25 to 40 percent from 1990 emissions by 2020 and support enhanced action on climate change in the developing world.In December 2011 the 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.In December 2012, the U.N. Climate Change Conference in Doha, Qatar, resulted in countries agreeing to a new commitment period under the Kyoto Protocol beginning in 2020.The new Doha Amendment to establish a second commitment period requires the ratification of three-quarters of the parties to the Kyoto Protocol before it becomes effective.

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 operate 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.The period for finalizing the Section 316(b) regulation has been extended to November 20, 2013 under a Settlement Agreement between EPA and certain NGOs.FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant's water intake channel to divert fish away from the plant's water intake system.Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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On April 19, 2013, the EPA proposed regulatory changes to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423).The EPA proposedeighttreatment options for waste water discharges from electric power plants, of which four are "preferred" by the Agency.The preferred options range from more stringent chemical and biological treatment requirements to zero discharge requirements.The EPA is required to finalize this rulemaking by May 22, 2014, under a consent decree entered by a U.S. District Court and the treatment obligations are proposed to phase-in as waste water discharge permits are renewed on a5-year cycle from 2017 to 2022.Depending on the content of the EPA's final rule, the future costs of compliance with these standards may require material capital expenditures.

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 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$150 millionin 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 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 which requires the development of a TMDL limit for the river, a process that will take PA DEP approximately five years.However, the Hatfield's Ferry and Mitchell Plants in Pennsylvania that discharge into the Monongahela River were deactivated on October 9, 2013.

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 RCRA 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 April 19, 2013, the EPA stated it would "align" its proposed coal combustion residuals regulations with revised waste water discharge effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) that were proposed on that date.On July 25, 2013, the House of Representatives passed H.R. 221 that would require CCRs to be regulated under Subtitle D of RCRA, as non-hazardous.Depending on the content of the EPA's final effluent limitations rule and the specifics of any "alignment", the future costs of compliance with such standards may require material capital expenditures.

On July 27, 2012, the PA DEP filed a complaint against FG in the U.S. District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FG to resolve those claims.On December 14, 2012, a modified Consent Decree that addresses public comments received by PA DEP was entered by the court, requiring FG 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 modified Consent Decree also requires payment of civil penalties of$800,000to resolve claims under the Solid Waste Management Act.On February 1, 2013, FG submitted a Feasibility Study analyzing various technical issues relevant to the closure of LBR.On March 28, 2013, FG submitted to the PA DEP a Closure Plan Major Permit Modification Application which provides for placing a final cap over LBR that would require15years to fully implement following the closure of LBR.The estimated cost for the proposed closure plan is$234 million, including environmental and other post closure costs.On October 3, 2013, the PA DEP issued a technical deficiency letter citing four main deficiencies with the Closure Plan: (1) seeking to accelerate the 15 year period proposed by FG for closure activities to complete closure in 9 years by commencing closure activities prior to 2017 as proposed by FG; (2) seeking to extend bond closure and post closure activities beyond the 45 years proposed by FG; (3) seeking active dewatering of the CCBs in areas where there are seeps impacted by the Impoundment; and (4) seeking an abatement plan for groundwater impacted by arsenic.The Bruce Mansfield Plant is pursuing several options for its CCBs following December 31, 2016, and on January 23, 2013, announced a plan for beneficial use of its CCBs for mine reclamation in LaBelle, Pennsylvania.In June 2013, a complaint filed in the U.S. District Court for the Western District of Pennsylvania, alleges the LaBelle site is in violation of RCRA and state laws.On December 20, 2012, the Environmental Integrity Project and others served FG with a citizen suit notice alleging CWA and PA Clean Streams Law Violations at LBR.

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On October 10, 2013, a complaint was filed on behalf of approximately50individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment.The complaint states claims for private nuisance, negligence, negligence per se, reckless conduct and trespass related to alleged groundwater contamination and odors emanating from the Impoundment.FE, FG and FES believe the claims are without merit and intend to vigorously defend themselves against the allegations made in this complaint, but, at this time, are unable to predict the outcome of the above matter or estimate the possible loss or range of loss.

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 FirstEnergy's 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 ofSeptember 30, 2013based 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$124 millionhave been accrued throughSeptember 30, 2013. Included in the total are accrued liabilities of approximately$82 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 ofSeptember 30, 2013, FirstEnergy had approximately$2.2 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 guaranty, 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.FE maintains a$125 millionparental guaranty relating to a potential shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry.FE also maintains an$11 millionparental guaranty in support of the decommissioning of the spent fuel storage facilities located at its Davis-Besse and Perry nuclear facilities.

On October 4, 2013, during a refueling outage for Beaver Valley Unit 1, FENOC conducted a planned visual examination of the interior containment liner and coatings. The containment design for Beaver Valley includes an interior steel liner that is surrounded by reinforced concrete. A penetration through the containment steel liner plate of approximately 0.4 inches by 0.28 inches was discovered. A detailed investigation was initiated, including laboratory analysis that has indicated that the degraded area was initiated by foreign material inadvertently left in the concrete during construction. An assessment has been performed which concluded that any postulated leakage through the affected area was within overall allowable limits for the containment building. The structural integrity of the containment building is not affected. Repair of the containment liner has been completed and is not expected to impact the restart of the Unit.

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.An NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners.On July 9, 2012, the petitioners' proposed a contention on the environmental impacts of spent fuel storage in the Davis-Besse license renewal proceeding.In an order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the challenges to the NRC Waste Confidence Decision and Temporary Storage Rule and all pending contentions on this topic should be held in abeyance.The ASLB has suspended further consideration of the petitioners' proposed contention on the environmental impacts of spent fuel storage at Davis-Besse.The NRC Staff issued Waste Confidence Draft Generic Environmental Impact Statement and published a proposed rule on this subject in September of 2013.

In May 2013, four petitioners requested a hearing on an NRC LAR submitted by FENOC to amend the Technical Specifications for the Davis-Besse plant to support plant operations following replacement of the steam generators, which is scheduled to be completed in April 2014.The petitioners also challenged FENOC's ability to replace the steam generators at the Davis-Besse plant under the NRC regulations, 10 CFR §50.59 without submitting a formal LAR.By an order dated August 12, 2013, the NRC denied the request for a hearing.

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station FENOC identified changes to the laminar cracking condition discovered in 2011. FENOC expanded its sample size to include all of the existing core bores in the shield building. These inspections are now complete. FENOC identified additional subsurface cracking that determined to be pre-existing, but not previously identified, due to improved inspection technology. In addition, these inspections revealed that the cracking

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condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirm that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

By a 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 conducted several supplemental inspections, including inspections using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues were understood, the extent of condition was identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.On August 12, 2013, the NRC issued an inspection report for the final 95002 Supplemental Inspection for Perry and returned Perry to the Licensee Response Column (Column 1) of the NRC's ROP Action Matrix.

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.

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 millionfor 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, the defendants posted bond and filed a Notice of Appeal with the Superior Court.On August 13, 2012, the Superior Court affirmed the$14 millionpast damages award but vacated the$90 millionfuture damages award.While the Superior Court found that the defendants still owed future damages, it remanded the calculation of those damages back to the trial court.The specific amount of those future damages is not known at this time, but they are expected to be calculated at a market price of coal that is significantly lower than the price used by the trial court.On August 27, 2012, AE Supply and MP filed an Application for Reargument En Banc with the Superior Court, which was denied on October 19, 2012.AE Supply and MP filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on November 19, 2012.On July 2, 2013, the Petition for Allowance of Appeal was denied and in the second quarter of 2013 the now final past damage award of$15.5 million(including interest) was recognized.The case was sent back to the trial court to recalculate the future damages only and is currently in the discovery phase.

Other Legal Matters

In 2010, a lawsuit was filed in Allegheny County Court of Common Pleas by Michael Goretzka, for wrongful death and negligence after his wife was fatally electrocuted when she contacted a downed power line.The trial resulted in a verdict against WP and the parties settled this matter.WP's portion of the settlement was covered by insurance subject to the remainder of its deductible.On May 30, 2012, the PPUC's Bureau of Investigation and Enforcement (I&E) filed a Formal Complaint at the PPUC regarding this matter.On February 13, 2013, WP and I&E filed a Joint Petition for Full Settlement that includes, among other things, WP's agreement to conduct an infrared inspection of its primary distribution system, modify certain training programs, and pay an$86,000civil penalty, which settlement is subject to PPUC approval.On August 29, 2013, the PPUC entered an Order granting the Goretzka family limited party status for the sole purpose of submitting comments to the settlement and issuing the settlement for comment by the parties.On September 16, 2013, the Goretzka family filed Limited Objections to the settlement. Reply comments were filed by WP on September 30, 2013.

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 12, Regulatory Matters of the Combined Notes to 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 if such estimate can be made.

51

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.

14. SUPPLEMENTAL GUARANTOR INFORMATION

In 2007, FG completed a sale and leaseback transaction for its undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FG, 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 lease for FG.

The Consolidating Statements of Income and Comprehensive Income for the three months and nine months ended September 30, 2013 and 2012, Consolidating Balance Sheets as of September 30, 2013 and December 31, 2012, and Consolidating Statements of Cash Flows for the nine months ended September 30, 2013 and 2012, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FG and NG 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.

52

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,654		$	528		$	440		$	(943	)	$	1,679
OPERATING EXPENSES:
Fuel	—			249			55			—			304
Purchased power from affiliates	1,009			—			65			(942		)	132
Purchased power from non-affiliates	720			4			—			—			724
Other operating expenses	147			65			114			13			339
Provision for depreciation	1			33			46			—			80
General taxes	21			9			5			—			35
Total operating expenses	1,898			360			285			(929		)	1,614
OPERATING INCOME (LOSS)	(244		)	168			155			(14		)	65
OTHER INCOME (EXPENSE):
Loss on debt redemptions	—			—			—			—			—
Investment income (loss)	2			—			(1		)	(4		)	(3		)
Miscellaneous income, including net income from equity investees	180			19			—			(178		)	21
Interest expense — affiliates	(3		)	(2		)	(1		)	5			(1		)
Interest expense — other	(13		)	(24		)	(13		)	15			(35		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	166			(6		)	(7		)	(162		)	(9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(78		)	162			148			(176		)	56
INCOME TAXES (BENEFITS)	(118		)	111			28			2			23
NET INCOME FROM CONTINUING OPERATIONS	40			51			120			(178		)	33
Discontinued operations (net of income taxes of $5)	—			7			—			—			7
NET INCOME	$	40		$	58		$	120		$	(178	)	$	40
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	40		$	58		$	120		$	(178	)	$	40
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available-for-sale securities	5			—			5			(5		)	5
Other comprehensive income (loss)	(1		)	(5		)	5			—			(1		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(2		)	3			(1		)	(1		)
Other comprehensive income (loss), net of tax	—			(3		)	2			1			—
COMPREHENSIVE INCOME	$	40		$	55		$	122		$	(177	)	$	40

53

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

For the Nine Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	4,575		$	1,612		$	1,337		$	(2,869	)	$	4,655
OPERATING EXPENSES:
Fuel	—			782			154			—			936
Purchased power from affiliates	3,072			—			197			(2,868		)	401
Purchased power from non-affiliates	1,749			6			—			—			1,755
Other operating expenses	484			208			376			37			1,105
Provision for depreciation	4			96			134			(3		)	231
General taxes	60			28			18			—			106
Total operating expenses	5,369			1,120			879			(2,834		)	4,534
OPERATING INCOME (LOSS)	(794		)	492			458			(35		)	121
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(103		)	—			—			—			(103		)
Investment income	4			—			3			(11		)	(4		)
Miscellaneous income, including net income from equity investees	543			23			—			(537		)	29
Interest expense — affiliates	(10		)	(4		)	(5		)	12			(7		)
Interest expense — other	(50		)	(79		)	(42		)	45			(126		)
Capitalized interest	1			1			26			—			28
Total other income (expense)	385			(59		)	(18		)	(491		)	(183		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(409		)	433			440			(526		)	(62		)
INCOME TAXES (BENEFITS)	(380		)	215			138			8			(19		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(29		)	218			302			(534		)	(43		)
Discontinued operations (net of income taxes of $8)	—			14			—			—			14
NET INCOME (LOSS)	$	(29	)	$	232		$	302		$	(534	)	$	(29	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(29	)	$	232		$	302		$	(534	)	$	(29	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(16		)	(15		)	—			15			(16		)
Amortized gain on derivative hedges	(3		)	—			—			—			(3		)
Change in unrealized gain on available-for-sale securities	2			—			2			(2		)	2
Other comprehensive income (loss)	(17		)	(15		)	2			13			(17		)
Income taxes (benefits) on other comprehensive income (loss)	(7		)	(6		)	1			5			(7		)
Other comprehensive income (loss), net of tax	(10		)	(9		)	1			8			(10		)
COMPREHENSIVE INCOME (LOSS)	$	(39	)	$	223		$	303		$	(526	)	$	(39	)

54

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,523		$	610		$	395		$	(978	)	$	1,550
OPERATING EXPENSES:
Fuel	—			248			55			—			303
Purchased power from affiliates	1,042			—			67			(978		)	131
Purchased power from non-affiliates	499			3			—			—			502
Other operating expenses	130			78			122			12			342
Provision for depreciation	1			29			41			(1		)	70
General taxes	20			10			5			—			35
Total operating expenses	1,692			368			290			(967		)	1,383
OPERATING INCOME (LOSS)	(169		)	242			105			(11		)	167
OTHER INCOME (EXPENSE):
Investment income	1			5			37			(5		)	38
Miscellaneous income, including net income from equity investees	317			—			—			(316		)	1
Interest expense — affiliates	(5		)	(2		)	(1		)	5			(3		)
Interest expense — other	(25		)	(27		)	(15		)	16			(51		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	288			(23		)	29			(300		)	(6		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	119			219			134			(311		)	161
INCOME TAXES (BENEFITS)	18			(14		)	59			2			65
NET INCOME FROM CONTINUING OPERATIONS	101			233			75			(313		)	96
Discontinued operations (net of income taxes of $3)	—			5			—			—			5
NET INCOME	$	101		$	238		$	75		$	(313	)	$	101
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	101		$	238		$	75		$	(313	)	$	101
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available for sale securities	(2		)	—			(1		)	1			(2		)
Other comprehensive loss	(9		)	(4		)	(1		)	5			(9		)
Income tax benefits on other comprehensive loss	(3		)	(2		)	—			2			(3		)
Other comprehensive loss, net of tax	(6		)	(2		)	(1		)	3			(6		)
COMPREHENSIVE INCOME	$	95		$	236		$	74		$	(310	)	$	95

55

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Nine Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	4,443		$	1,777		$	1,262		$	(2,971	)	$	4,511
OPERATING EXPENSES:
Fuel	—			824			154			—			978
Purchased power from affiliates	3,163			—			189			(2,971		)	381
Purchased power from non-affiliates	1,420			5			—			—			1,425
Other operating expenses	313			268			410			37			1,028
Provision for depreciation	3			87			114			(4		)	200
General taxes	60			28			16			—			104
Total operating expenses	4,959			1,212			883			(2,938		)	4,116
OPERATING INCOME (LOSS)	(516		)	565			379			(33		)	395
OTHER INCOME (EXPENSE):
Investment income	2			14			49			(15		)	50
Miscellaneous income, including net income from equity investees	854			19			—			(848		)	25
Interest expense — affiliates	(14		)	(5		)	(3		)	15			(7		)
Interest expense — other	(72		)	(79		)	(36		)	47			(140		)
Capitalized interest	—			3			24			—			27
Total other income (expense)	770			(48		)	34			(801		)	(45		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	254			517			413			(834		)	350
INCOME TAXES (BENEFITS)	32			(25		)	124			8			139
NET INCOME FROM CONTINUING OPERATIONS	222			542			289			(842		)	211
Discontinued operations (net of income taxes of $6)	—			11			—			—			11
NET INCOME	$	222		$	553		$	289		$	(842	)	$	222
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	222		$	553		$	289		$	(842	)	$	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(2		)	(1		)	—			1			(2		)
Amortized gain on derivative hedges	(6		)	—			—			—			(6		)
Change in unrealized gain on available-for-sale securities	11			—			12			(12		)	11
Other comprehensive income (loss)	3			(1		)	12			(11		)	3
Income taxes (benefits) on other comprehensive income (loss)	1			(1		)	5			(4		)	1
Other comprehensive income, net of tax	2			—			7			(7		)	2
COMPREHENSIVE INCOME	$	224		$	553		$	296		$	(849	)	$	224

56

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of September 30, 2013	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	524		—		—		—			524
Affiliated companies	420		445		285		(631		)	519
Other	76		22		25		—			123
Notes receivable from affiliated companies	337		163		764		(1,010		)	254
Materials and supplies	64		161		214		—			439
Derivatives	139		—		—		—			139
Prepayments and other	61		37		6		1			105
	1,621		830		1,294		(1,640		)	2,105
PROPERTY, PLANT AND EQUIPMENT:
In service	104		6,068		6,719		(383		)	12,508
Less — Accumulated provision for depreciation	26		1,928		2,882		(187		)	4,649
	78		4,140		3,837		(196		)	7,859
Construction work in progress	21		115		980		—			1,116
	99		4,255		4,817		(196		)	8,975
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,270		—			1,270
Investment in affiliated companies	5,503		—		—		(5,503		)	—
Other	1		10		—		—			11
	5,504		10		1,270		(5,503		)	1,281
ASSETS HELD FOR SALE (NOTE 16)	—		121		—		—			121
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	16		169		—		(185		)	—
Customer intangibles	99		—		—		—			99
Goodwill	23		—		—		—			23
Property taxes	—		14		22		—			36
Unamortized sale and leaseback costs	—		—		—		161			161
Derivatives	65		—		—		—			65
Other	174		242		14		(162		)	268
	377		425		36		(186		)	652
	$	7,601	$	5,641	$	7,417	$	(7,525	)	$	13,134
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	366	$	514	$	(22	)	$	859
Short-term borrowings-
Affiliated companies	696		314		—		(1,010		)	—
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	643		386		378		(631		)	776
Other	88		125		—		—			213
Accrued taxes	7		17		37		(19		)	42
Derivatives	103		—		—		—			103
Other	46		72		22		36			176
	1,584		1,284		951		(1,646		)	2,173
CAPITALIZATION:
Total equity	5,229		2,010		3,469		(5,479		)	5,229
Long-term debt and other long-term obligations	712		1,873		789		(1,196		)	2,178
	5,941		3,883		4,258		(6,675		)	7,407
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		866			866
Accumulated deferred income taxes	—		—		770		(71		)	699
Asset retirement obligations	—		176		983		—			1,159
Retirement benefits	27		228		—		—			255
Derivatives	22		—		—		—			22
Other	27		70		455		1			553
	76		474		2,208		796			3,554
	$	7,601	$	5,641	$	7,417	$	(7,525	)	$	13,134

57

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2012	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	3	$	—	$	—		$	3
Receivables-
Customers	483		—		—		—			483
Affiliated companies	232		417		478		(748		)	379
Other	56		19		16		—			91
Notes receivable from affiliated companies	366		7		607		(704		)	276
Materials and supplies	66		231		208		—			505
Derivatives	158		—		—		—			158
Prepayments and other	38		39		10		—			87
	1,399		716		1,319		(1,452		)	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	91		5,899		6,391		(384		)	11,997
Less — Accumulated provision for depreciation	32		1,915		2,646		(185		)	4,408
	59		3,984		3,745		(199		)	7,589
Construction work in progress	34		230		877		—			1,141
	93		4,214		4,622		(199		)	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,283		—			1,283
Investment in affiliated companies	4,972		—		—		(4,972		)	—
Other	—		12		—		—			12
	4,972		12		1,283		(4,972		)	1,295
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		313		—		(313		)	—
Customer intangibles	110		—		—		—			110
Goodwill	24		—		—		—			24
Property taxes	—		14		22		—			36
Unamortized sale and leaseback costs	—		—		—		119			119
Derivatives	99		—		—		—			99
Other	160		194		5		(106		)	253
	393		521		27		(300		)	641
	$	6,857	$	5,463	$	7,251	$	(6,923	)	$	12,648
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	586	$	537	$	(22	)	$	1,102
Short-term borrowings-
Affiliated companies	358		346		—		(704		)	—
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	748		143		583		(748		)	726
Other	63		96		—		—			159
Accrued taxes	126		25		20		—			171
Derivatives	124		—		—		—			124
Other	71		148		15		46			280
	1,491		1,348		1,155		(1,428		)	2,566
CAPITALIZATION:
Total equity	3,763		1,787		3,165		(4,952		)	3,763
Long-term debt and other long-term obligations	1,482		2,009		834		(1,207		)	3,118
	5,245		3,796		3,999		(6,159		)	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		892			892
Accumulated deferred income taxes	28		—		714		(227		)	515
Asset retirement obligations	—		29		936		—			965
Retirement benefits	26		215		—		—			241
Derivatives	37		—		—		—			37
Other	30		75		447		(1		)	551
	121		319		2,097		664			3,201
	$	6,857	$	5,463	$	7,251	$	(6,923	)	$	12,648

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(1,018	)	$	712		$	705		$	(10	)	$	389
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	338			—			—			(338		)	—
Equity contribution from parent	1,500			—			—			—			1,500
Redemptions and Repayments-
Long-term debt	(769		)	(352		)	(68		)	10			(1,179		)
Short-term borrowings, net	—			(32		)	—			32			—
Tender premiums	(67		)	—			—			—			(67		)
Other	(3		)	(4		)	—			—			(7		)
Net cash provided from (used for) financing activities	999			(388		)	(68		)	(296		)	247
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(9		)	(192		)	(276		)	—			(477		)
Nuclear fuel	—			—			(159		)	—			(159		)
Proceeds from asset sales	—			21			—			—			21
Sales of investment securities held in trusts	—			—			650			—			650
Purchases of investment securities held in trusts	—			—			(694		)	—			(694		)
Loans to affiliated companies, net	28			(156		)	(156		)	306			22
Other	—			2			(2		)	—			—
Net cash provided from (used for) investing activities	19			(325		)	(637		)	306			(637		)
Net change in cash and cash equivalents	—			(1		)	—			—			(1		)
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(971	)	$	683		$	799		$	(10	)	$	501
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			317			243			—			560
Short-term borrowings, net	982			49			—			(1,028		)	3
Redemptions and Repayments-
Long-term debt	—			(169		)	(87		)	10			(246		)
Short-term borrowings, net	—			—			(32		)	32			—
Other	(1		)	(6		)	(2		)	—			(9		)
Net cash provided from financing activities	981			191			122			(986		)	308
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(10		)	(175		)	(350		)	—			(535		)
Nuclear fuel	—			—			(207		)	—			(207		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			1,167			—			1,167
Purchases of investment securities held in trusts	—			—			(1,194		)	—			(1,194		)
Loans to affiliated companies, net	1			(715		)	(337		)	996			(55		)
Other	(1		)	(5		)	—			—			(6		)
Net cash used for investing activities	(10		)	(878		)	(921		)	996			(813		)
Net change in cash and cash equivalents	—			(4		)	—			—			(4		)
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3

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15. SEGMENT INFORMATION

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does 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, SSO 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. This business segment currently controls approximately 4,000 MWs of capacity, including the net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). The segment's revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are derived from transmission services provided pursuant to the PJM open access transmission tariff to LSEs. Its results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

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 currently controls approximately14,500MWs of capacity, including885MWs of capacity subject to RMR arrangements with PJM and excluding2,080MWs of capacity deactivated on October 9, 2013 and a net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013. This segment 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 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.

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Segment Financial Information

Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate			Reconciling Adjustments			Consolidated
	(In millions)
September 30, 2013
External revenues	$	2,340	$	190	$	1,573		$	(31	)	$	(36	)	$	4,036
Internal revenues	—		—		196			—			(196		)	—
Total revenues	2,340		190		1,769			(31		)	(232		)	4,036
Depreciation, amortization and deferrals	460		31		125			12			—			628
Investment income (loss)	14		—		(5		)	3			(7		)	5
Interest expense	134		23		53			47			—			257
Income taxes (benefits)	50		32		47			(44		)	(8		)	77
Income from continuing operations	85		54		68			—			2			209
Discontinued operations, net of tax	—		—		9			—			—			9
Net income (loss)	85		54		77			(10		)	12			218
Total assets	27,030		4,953		17,809			591			—			50,383
Total goodwill	5,025		526		867			—			—			6,418
Property additions	261		105		162			20			—			548
September 30, 2012
External revenues	$	2,483	$	187	$	1,462		$	(31	)	$	(49	)	$	4,052
Internal revenues	—		—		209			—			(209		)	—
Total revenues	2,483		187		1,671			(31		)	(258		)	4,052
Depreciation, amortization and deferrals	193		28		102			9			1			333
Investment income	20		—		36			(2		)	(15		)	39
Interest expense	136		24		73			(3		)	—			230
Income taxes (benefits)	168		35		74			(8		)	38			307
Income from continuing operations	286		59		126			—			(49		)	422
Discontinued operations, net of tax	—		—		3			—			—			3
Net income (loss)	286		59		129			(13		)	(36		)	425
Total assets	26,122		4,519		16,846			1,251			—			48,738
Total goodwill	5,025		526		893			—			—			6,444
Property additions	308		47		412			8			—			775
Nine Months Ended
September 30, 2013
External revenues	$	6,593	$	546	$	4,350		$	(89	)	$	(130	)	$	11,270
Internal revenues	—		—		588			—			(588		)	—
Total revenues	6,593		546		4,938			(89		)	(718		)	11,270
Depreciation, amortization and deferrals	882		91		347			32			—			1,352
Investment income (loss)	41		—		(6		)	6			(33		)	8
Interest expense	404		68		187			112			—			771
Income taxes (benefits)	284		93		(189		)	(55		)	(4		)	129
Income (loss) from continuing operations	474		156		(317		)	—			(80		)	233
Discontinued operations, net of tax	—		—		17			—			—			17
Net income (loss)	474		156		(300		)	(92		)	12			250
Total assets	27,030		4,953		17,809			591			—			50,383
Total goodwill	5,025		526		867			—			—			6,418
Property additions	980		291		630			59			—			1,960
September 30, 2012
External revenues	$	6,976	$	557	$	4,465		$	(78	)	$	(142	)	$	11,778
Internal revenues	—		—		686			—			(684		)	2
Total revenues	6,976		557		5,151			(78		)	(826		)	11,780
Depreciation, amortization and deferrals	618		86		303			25			—			1,032
Investment income	62		1		48			(1		)	(47		)	63
Interest expense	405		70		209			66			—			750
Income taxes	355		101		165			(49		)	78			650
Income from continuing operations	603		171		284			—			(150		)	908
Discontinued operations, net of tax	—		—		11			—			—			11
Net income (loss)	603		171		295			(82		)	(68		)	919
Total assets	26,122		4,519		16,846			1,251			—			48,738
Total goodwill	5,025		526		893			—			—			6,444
Property additions	751		169		715			51			—			1,686

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16. DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

On September 4, 2013, certain of FirstEnergy subsidiaries applied for authorization from the FERC to sell eleven hydroelectric power stations in Pennsylvania, Virginia and West Virginia to subsidiaries of Harbor Hydro, a subsidiary of LS Power, for approximately $400 million. The asset purchase agreement was entered into on August 23, 2013, as amended and restated as of September 4, 2013. The proposed transaction is expected to close in the fourth quarter of 2013. The asset purchase agreement is subject to customary and other closing conditions, including, without limitation, the resolution of a potential competing license application, and receipt of approvals by FERC and the VSCC, which is pending. On September 27, 2013, the Federal Trade Commission advised that the Hart-Scott-Rodino waiting period was terminated, meaning this item is complete. As of September 30, 2013, FirstEnergy classified the hydroelectric power stations, with a carrying value of $234 million (FES - $121 million) as Assets held for sale in the Consolidated Balance Sheets. Included in the carrying value of the assets held for sale is goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold. Net pre-tax results for the hydroelectric facilities of $12 million and $26 million (FES - $12 million and $22 million) for the three and nine months ended September 30, 2013, respectively, and $5 million and $19 million (FES - $8 million and $17 million) for three and nine months ended September 30, 2012, respectively, were reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Revenues for the hydroelectric facilities of $11 million and $24 million (FES - $10 million and $22 million) for the three and nine months ended September 30, 2013, respectively, and $6 million and $24 million (FES - $8 million and $18 million) for the three and nine months ended September 30, 2012 respectively, are reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations.

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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

Net income in the third quarter of 2013 was $218 million, or basic and diluted earnings of $0.52 per share of common stock, compared with net income of $425 million, or basic and diluted earnings of $1.02 per share of common stock in the third quarter of 2012. The principal reasons for the changes in basic earnings per share for the three and nine months ended September 2013, are summarized below.

Change In Basic Earnings (Losses) Per Share From Prior Year	Three Months Ended September 30			Nine Months Ended September 30
Basic Earnings Per Share - 2012	$	1.02		$	2.20
Segment operating results(1) -
Regulated Distribution	(0.08		)	0.07
Regulated Transmission	—			(0.03		)
Competitive Energy Services	(0.17		)	(0.39		)
Regulatory charges	(0.32		)	(0.36		)
Non-core asset sales/impairments	—			(0.02		)
Merger-related costs	—			0.01
Merger accounting — commodity contracts	0.01			0.03
Trust securities impairments	(0.03		)	(0.08		)
Mark-to-market adjustments	(0.03		)	(0.07		)
Plant deactivation costs(2)	—			(0.73		)
Debt redemption costs	0.02			(0.20		)
Interest expense, net of amounts capitalized	(0.01		)	(0.03		)
Investment income	(0.03		)	(0.01		)
Income tax legislative changes - 2012	0.03			0.07
Change in effective tax rate	0.09			0.11
Discontinued operations	0.01			0.01
Other	0.01			0.02
Basic Earnings Per Share - 2013	$	0.52		$	0.60

⁽¹⁾ Excludes amounts shown separately.

⁽²⁾ Includes impairments of long lived assets of $0.71 per share, severance charges of $0.02 per share and a valuation reserve against net operating loss carryforwards of $0.05 per share recognized in the second quarter of 2013 related to the deactivation of Hatfield's Ferry and Mitchell generating units, which occurred on October 9, 2013.

FirstEnergy continues to be exposed to weak economic conditions across its multi-state utility service territory, as evidenced by relatively flat distribution sales over the last three years. This prolonged decrease in demand, coupled with excess generation supply in the region, has caused a period of protracted low power and capacity prices. Further, the PJM RPM Auction for 2016/2017 capacity that was conducted in May 2013 produced prices in the regions served by FirstEnergy's Competitive Energy Services Segment that were lower than expected. This result is a broader indication of an underlying supply/demand imbalance that is expected to continue to affect power producers in this region, adding pressure on already depressed energy prices and potentially pushing any significant power price recovery further into the future than FirstEnergy, or the industry at large, previously expected.

Over the course of 2013, FirstEnergy has taken a number of actions designed to reposition the Competitive Energy Services Segment, including adjusting its hedging strategy by slowing forward sales in order to capture any potential future improvements in power prices, being more selective in the customers targeted and focusing more on customers with higher profit margins. With the deactivation of Hatfield’s Ferry and Mitchell plants and Harrison/Pleasants asset transfer in October of 2013, as well as the proposed sale of 527 MW of hydro assets, FirstEnergy will have reduced the size of the competitive fleet and changed the mix of its assets. While these actions will result in the competitive fleet being about the same size as before the Allegheny merger, FirstEnergy believes it is a much stronger, more efficient, and environmentally controlled platform of units. After the transactions

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discussed above, the remaining competitive fleet will be less than 50% coal, over 30% nuclear, and more than 20% natural gas, hydro, wind and solar. Capital reductions, primarily over the next four years, of approximately $1 billion have been announced with the remaining capital investments over the next several years expected to primarily support the nuclear fleet life extensions at Davis-Besse tied to the steam generator replacement in 2014 and a new reactor vessel head and steam generator at Beaver Valley 2 in 2017. This capital reduction includes reduced MATS spending that is now anticipated to be approximately $465 million, including approximately $240 million at the Competitive Energy Services segment.

These actions are expected to support operations during this continuing stagnant economic period, and position the Competitive Energy Services Segment to take advantage of improving power markets when the economy eventually recovers.

FirstEnergy intends to focus on growing its regulated operations - particularly in transmission. FirstEnergy plans to implement a four-year, $2.8 billion Transmission Reliability Excellence Plan (TREP) designed to improve operating flexibility, increase the reliability of the regional transmission system, position capacity for future load growth and facilitate response to system events. Beginning in 2014, FirstEnergy plans to deploy the $2.8 billion of incremental investments associated with TREP, in addition to the baseline capital program expenditures forecasted at $1.8 billion over the same time period. Currently, FirstEnergy estimates that 2014 capital expenditures associated with TREP will be approximately $500 million in 2014, growing to approximately $700 million in 2015 and approximately $800 million in both 2016 and 2017. These investments will focus primarily in ATSI, which has a formula rate recovery mechanism, but will ultimately extend throughout FirstEnergy's service area. FirstEnergy currently expects to fund the TREP capital investments through the issuance of debt and equity.

Financial Plan

Earlier this year, FirstEnergy announced the 2013 financial plan intended to strengthen the balance sheet of the Competitive Energy Services Segment by reducing its debt by approximately $1.5 billion. Completion of the plan is expected to significantly improve credit metrics at the Competitive Energy Services Segment. This plan also included the net transfer of 1,476 MW between AE Supply and MP of the Harrison and Pleasants power plants, and the proposed sale of up to 1,240 MW of unregulated hydro assets. Finally, as part of the 2013 financial plan, FirstEnergy announced earlier this year that it had expected to issue a modest amount of equity in late 2013.

In line with these efforts, FirstEnergy continued to execute its 2013 financial plan as follows:

• On August 21, 2013, MP and PE, along with the majority of the parties to the companies' generation transaction proceedings involving the Harrison Power Station, filed a comprehensive settlement agreement with the WVPSC. On October 7, 2013, the WVPSC issued an Order authorizing the transaction with certain conditions and on October 9, 2013, MP sold its approximate 8% share of Pleasants at its fair market value of $73 million to AE Supply, and AE Supply sold its approximate 80% share of Harrison to MP at its book value of $1.2 billion. The transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. Currently, the $1.1 billion net consideration was financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million. In connection with the closing, in the fourth quarter of 2013, MP recorded a pre-tax impairment charge of approximately $330 million to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base. Additionally, MP recognized a regulatory liability of approximately $23 million in the fourth quarter of 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station.

• On September 4, 2013, FESC, on behalf of FG, AE Supply and Green Valley Hydro LLC applied for authorization from the FERC to sell eleven hydroelectric power stations in Pennsylvania, Virginia and West Virginia to subsidiaries of Harbor Hydro, a subsidiary of LS Power, for approximately $400 million. The hydroelectric power stations included in this proposed sale have a total generating capacity of approximately 527 MW, which represents less than 3 percent of FirstEnergy's competitive generation fleet output. An asset purchase agreement was entered into on August 23, and amended and restated as of September 4, 2013. Subject to receiving the required regulatory authorizations and the resolution of the potential competing license application and other claims and matters regarding the Seneca Pumped Storage Project, the proposed transaction is expected to close in the fourth quarter of 2013.

• On September 25, 2013, FE filed a registration statement with the SEC to register 4 million shares of common stock to be issued to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan. In addition, FE expects to also begin fulfilling certain share-based benefit plan obligations through the issuance of authorized but unissued common stock.

In addition, the Utilities continue to review their balance sheets and have taken the following actions in the third quarter:

• On August 21, 2013, JCP&L issued $500 million of 4.7% fixed-rate unsecured taxable long-term debt. The proceeds were used to pay down a portion if its short-term debt obligations.

• On August 28, 2013, the Ohio Companies redeemed $660 million of long-term debt. In addition, approximately $120 million was paid in make-whole premiums which was deferred as a regulatory asset and will be amortized over the original life of the redeemed debt.

• On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the facility.

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Similarly, the FES/AE Supply $2.5 billion revolving credit facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. The effect of these amendments will apply to the compliance reports for the period ended September 30, 2013, which are due November 29, 2013.

Overall, these actions, including debt reductions and cost savings across all of its businesses, are expected to advance FirstEnergy's progress in achieving its financial goals for each of its businesses, including strengthening their balance sheets, improving their liquidity and maintaining their credit ratings. FirstEnergy will continue to review and may refine or change the financial plan in the future as circumstances evolve.

Operational Matters

Employee Relations

FirstEnergy is engaged in negotiations with UWUA Local 102 which represents approximately 950 employees at WP, PE and FG. The current collective bargaining agreement expired on April 30, 2013. Although the parties continue to bargain, WP, PE and FG have work continuation plans in place in the event of any work stoppage.

FirstEnergy is engaged in negotiations with UWUA Local 180 which represents approximately 150 employees at PN. The current collective bargaining agreement expired on August 31, 2013. The parties are currently negotiating and, in the event of a work stoppage, a work continuation plan is in place.

Hatfield's Ferry & Mitchell Plant Closings

On September 23, 2013, PJM concluded that FirstEnergy could move forward with its plan to deactivate its 1,700-MW Hatfield's Ferry and 370-MW Mitchell coal-fired plants in Pennsylvania as it found no reliability issues and on October 9, 2013, the plants were deactivated.

Approximately 240 plant employees and generation related positions were affected by these plant deactivations. FirstEnergy recorded approximately $7 million (pre-tax) of severance related expenses that were recognized in Other operating expenses in the Consolidated Statements of Income for the nine months ended September 30, 2013.

Due to the termination of operations at Hatfield's Ferry Units 1-3, AE Supply has the right to redeem $235 million of its outstanding PCRBs at par. A conditional notice of full redemption was issued on October 18, 2013, calling the $235 million of outstanding PCRB's for redemption on November 15, 2013.

Davis-Besse Inspection

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station, FENOC had identified changes to the laminar cracking condition discovered in 2011. FENOC has expanded its sample size to include all of the existing core bores in the shield building. These inspections are now complete. FENOC has identified additional subsurface cracking that has been determined to be pre-existing, but not previously identified due to improved inspection technology. In addition, these inspections have revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspection results confirm that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

Beaver Valley 1 Refueling Outage

On September 30, 2013, the 911 MW Beaver Valley 1 Power Plant entered into a scheduled refueling and maintenance outage, including a turbine upgrade that is designed to improve efficiency and reliability. During the outage, 60 of the 157 fuel assemblies will be exchanged. Numerous inspections, maintenance activities and improvement projects designed to ensure continued safe and reliable operations have occurred. Prior to the outage, Beaver Valley operated safely and reliably for 507 consecutive days since the completion of its last refueling outage in May 2012.

Regulatory Matters

Ohio Alternative Energy Rider Update

On August 7, 2013 the PUCO disallowed the Ohio Companies' recovery of $43.4 million, plus interest, that related to 2011 RECs that were purchased in the August 2010 RFP. The Ohio Companies, along with other parties, timely filed applications for rehearing on September 6, 2013. On September 18, 2013, the PUCO issued an entry on rehearing granting rehearing solely for the purpose of further consideration of the matters specified therein.

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Pennsylvania Marginal Transmission Losses

On September 30, 2013, the U.S. District Court granted the PPUC's motion to dismiss the ME and PN proceedings on the recovery of marginal transmission losses through the TSC. On October 29, 2013, ME and PN filed a notice of appeal in the U.S. Court of Appeals for the Third Circuit with respect to the U.S. District Court's decision. As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. FirstEnergy continues to believe in the merits of its case.

JCP&L Rate Filing Update

JCP&L filed rebuttal testimony in response to the testimony of other parties on August 7, 2013, which included rebutting the testimony of the Division of Rate Counsel's witnesses that recommended that revenues produced by JCP&L's base rates for electric service be reduced by approximately $202.8 million (such amount did not address the revenue requirements associated with major storm events of 2011 and 2012, which are subject to review in the generic proceeding). Hearings in the rate case have commenced and are scheduled to continue through mid-November.

FIRSTENERGY’S BUSINESS

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, SSO 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. This business segment currently controls approximately 4,000 MWs of capacity, including the net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). The segment's revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are derived from transmission services provided pursuant to the PJM open access transmission tariff to LSEs. Its results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

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 currently controls approximately14,500MWs of capacity, including885MWs of capacity subject to RMR arrangements with PJM and excluding2,080MWs of capacity deactivated on October 9, 2013 and a net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013. This segment 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 to deliver energy to the segment’s customers.

The Competitive Energy Services segment derives its revenues from the sale of generation to direct and governmental aggregation, POLR and wholesale customers. The segment is exposed to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices may be impacted by the prices of other commodities, including coal and natural gas, and energy efficiency and demand response programs, as well as regulatory and legislative actions, such as MATS among other factors. The segment attempts to mitigate the market risk inherent in its energy position by economically hedging its exposure and continuously monitoring various risk measurement metrics to ensure compliance with its risk management policies.

The Competitive Energy Services segment economically hedges exposure to price risk on a ratable basis, which is intended to reduce the near-term financial impact of market price volatility. As of September 30, 2013, the percentage of expected physical sales economically hedged was 105% for 2013 (of a 104 million MWH target). As of September 30, 2013, committed sales for 2014 and 2015 are approximately 80 million MWHs and 41 million MWHs, respectively.

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 15, Segment Information, of the Combined Notes to Consolidated Financial Statements for further information on FirstEnergy's reportable operating segments.

FirstEnergy considers a variety of factors, including wholesale power prices, in its decision to operate, or not operate, a generating plant. If wholesale power prices represent a lower cost option, FirstEnergy may elect to fulfill its load obligation through purchasing

67

electricity in the wholesale market as opposed to operating a generating unit. The effect of this decision on its results of operations would be to displace higher per unit fuel expense with lower per unit purchased power.

FirstEnergy engages in discussions with various commodity vendors, from time to time, regarding the impact that these and other actions may have on certain of its long-term agreements and FirstEnergy cannot provide assurance that these discussions will be satisfactorily resolved.

RESULTS OF OPERATIONS

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 15, Segment Information, of the Combined Notes to Consolidated Financial Statements. Net income by business segment was as follows:

	Three Months Ended September 30								Nine Months Ended September 30
	2013		2012			Increase (Decrease)			2013			2012			Increase (Decrease)
	(In millions, except per share)
Earnings (Losses) By Business Segment:
Regulated Distribution	$	85	$	286		$	(201	)	$	474		$	603		$	(129	)
Regulated Transmission	54		59			(5		)	156			171			(15		)
Competitive Energy Services	77		129			(52		)	(300		)	295			(595		)
Other and reconciling adjustments (1)	2		(49		)	51			(80		)	(151		)	71
Net Income	$	218	$	425		$	(207	)	$	250		$	918		$	(668	)
Basic Earnings Per Share:
Income from continuing operations	$	0.50	$	1.01		$	(0.51	)	$	0.56		$	2.17		$	(1.61	)
Discontinued operations (Note 16)	0.02		0.01			0.01			0.04			0.03			0.01
Net earnings per basic share	$	0.52	$	1.02		$	(0.50	)	$	0.60		$	2.20		$	(1.60	)
Diluted Earnings Per Share:
Income from continuing operations	$	0.50	$	1.00		$	(0.50	)	$	0.56		$	2.16		$	(1.60	)
Discontinued operations (Note 16)	0.02		0.01			0.01			0.04			0.03			0.01
Net earnings per diluted share	$	0.52	$	1.01		$	(0.49	)	$	0.60		$	2.19		$	(1.59	)

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

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Summary of Results of Operations — Third Quarter 2013 Compared with Third Quarter 2012

Financial results for FirstEnergy’s business segments in the third quarter of 2013 and 2012 were as follows:

Third Quarter 2013 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,282		$	190		$	1,508		$	(35	)	$	3,945
Other	58			—			65			(32		)	91
Internal	—			—			196			(196		)	—
Total Revenues	2,340			190			1,769			(263		)	4,036
Operating Expenses:
Fuel	88			—			569			—			657
Purchased power	910			—			406			(196		)	1,120
Other operating expenses	457			35			457			(72		)	877
Provision for depreciation	151			28			125			12			316
Amortization of regulatory assets, net	309			3			—			—			312
General taxes	173			15			49			5			242
Total Operating Expenses	2,088			81			1,606			(251		)	3,524
Operating Income	252			109			163			(12		)	512
Other Income (Expense):
Gain on debt redemptions	—			—			—			9			9
Investment income (loss)	14			—			(5		)	(4		)	5
Interest expense	(134		)	(23		)	(53		)	(47		)	(257		)
Capitalized interest	3			—			10			4			17
Total Other Expense	(117		)	(23		)	(48		)	(38		)	(226		)
Income From Continuing Operations Before Income Taxes	135			86			115			(50		)	286
Income taxes	50			32			47			(52		)	77
Income From Continuing Operations	85			54			68			2			209
Discontinued Operations, net of tax	—			—			9			—			9
Net Income	85			54			77			2			218
Income attributable to noncontrolling interest	—			—			—			—			—
Earnings Available to FirstEnergy Corp.	$	85		$	54		$	77		$	2		$	218

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Third Quarter 2012 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,426		$	187		$	1,428		$	(55	)	$	3,986
Other	57			—			34			(25		)	66
Internal	—			—			209			(209		)	—
Total Revenues	2,483			187			1,671			(289		)	4,052
Operating Expenses:
Fuel	76			—			560			—			636
Purchased power	1,010			—			263			(210		)	1,063
Other operating expenses	451			30			468			(88		)	861
Provision for depreciation	134			27			102			9			272
Amortization of regulatory assets, net	59			1			—			1			61
General taxes	187			12			52			6			257
Total Operating Expenses	1,917			70			1,445			(282		)	3,150
Operating Income	566			117			226			(7		)	902
Other Income (Expense):
Investment income	20			—			36			(17		)	39
Interest expense	(136		)	(24		)	(73		)	3			(230		)
Capitalized interest	4			1			11			2			18
Total Other Expense	(112		)	(23		)	(26		)	(12		)	(173		)
Income From Continuing Operations Before Income Taxes	454			94			200			(19		)	729
Income taxes	168			35			74			30			307
Income From Continuing Operations	286			59			126			(49		)	422
Discontinued Operations, net of tax	—			—			3			—			3
Net Income	286			59			129			(49		)	425
Income attributable to noncontrolling interest	—			—			—			—			—
Earnings Available to FirstEnergy Corp.	$	286		$	59		$	129		$	(49	)	$	425

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Changes Between Third Quarter 2013 and Third Quarter 2012 Financial Results Increase (Decrease)	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	(144	)	$	3		$	80		$	20		$	(41	)
Other	1			—			31			(7		)	25
Internal	—			—			(13		)	13			—
Total Revenues	(143		)	3			98			26			(16		)
Operating Expenses:
Fuel	12			—			9			—			21
Purchased power	(100		)	—			143			14			57
Other operating expenses	6			5			(11		)	16			16
Provision for depreciation	17			1			23			3			44
Amortization of regulatory assets, net	250			2			—			(1		)	251
General taxes	(14		)	3			(3		)	(1		)	(15		)
Total Operating Expenses	171			11			161			31			374
Operating Income (Loss)	(314		)	(8		)	(63		)	(5		)	(390		)
Other Income (Expense):
Gain (loss) on debt redemptions	—			—			—			9			9
Investment income (loss)	(6		)	—			(41		)	13			(34		)
Interest expense	2			1			20			(50		)	(27		)
Capitalized interest	(1		)	(1		)	(1		)	2			(1		)
Total Other Expense	(5		)	—			(22		)	(26		)	(53		)
Income (Loss) From Continuing Operations Before Income Taxes	(319		)	(8		)	(85		)	(31		)	(443		)
Income taxes (benefits)	(118		)	(3		)	(27		)	(82		)	(230		)
Income (Loss) From Continuing Operations	(201		)	(5		)	(58		)	51			(213		)
Discontinued Operations, net of tax	—			—			6			—			6
Net Income (Loss)	(201		)	(5		)	(52		)	51			(207		)
Income (loss) attributable to noncontrolling interest	—			—			—			—			—
Earnings (Losses) Available to FirstEnergy Corp.	$	(201	)	$	(5	)	$	(52	)	$	51		$	(207	)

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Regulated Distribution — Third Quarter 2013 Compared with Third Quarter 2012

Net income decreased by $201 million in the third quarter of 2013 compared to the same period of 2012, as more fully described below.

Revenues —

The $143 milliondecrease in total revenues resulted from the following sources:

	Three Months Ended September 30				Increase
Revenues by Type of Service	2013		2012		(Decrease)
	(In millions)
Distribution services	$	993	1,121		$	(128	)
Generation sales:
Retail	1,090		1,096		(6		)
Wholesale	81		86		(5		)
Total generation sales	1,171		1,182		(11		)
Transmission	118		123		(5		)
Other	58		57		1
Total Revenues	$	2,340	$	2,483	$	(143	)

The decrease in distribution services revenue is primarily related to a decrease in the ME and PN NUG riders which resulted from the expiration of certain NUG contracts in 2012 and 2013 and lower residential and commercial electric distribution MWH deliveries (described below), partially offset by an increase in the Ohio Companies' DCR rider. Distribution deliveries decreased by 2.1% in the third quarter of 2013 compared to the same period of 2012. Distribution deliveries by customer class are summarized in the following table:

	Three Months Ended September 30		Increase
Electric Distribution MWH Deliveries	2013	2012	(Decrease)
	(In thousands)
Residential	13,911	15,008	(7.3	)%
Commercial	11,368	11,436	(0.6	)%
Industrial	12,732	12,385	2.8	%
Other	147	146	0.7	%
Total Electric Distribution MWH Deliveries	38,158	38,975	(2.1	)%

Lower deliveries to residential customers primarily reflects decreased weather-related usage resulting from cooling degree days that were 18% below 2012, and 3% below normal. Lower deliveries to the commercial sector primarily reflect increasing energy efficiency mandates and demand response initiatives. In the Industrial sector, increased sales to steel, automotive, and shale gas customers, were partially offset by lower sales to chemical and petroleum customers. For 2013, FirstEnergy continues to expect an overall increase in industrial sales, with a majority of that increase resulting from shale gas activities. Additionally, FirstEnergy expects additional growth in the industrial sector beyond 2013 for potential shale gas projects. As the gas fields are developed, the opportunity for additional manufacturing expansion could further support growth.

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The following table summarizes the price and volume factors contributing to the $11 milliondecrease in generation revenues for the third quarter of 2013 compared to the same period of 2012:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(95	)
Change in prices	89
	(6		)
Wholesale:
Effect of decrease in sales volumes	(31		)
Change in prices	26
	(5		)
Decrease in Generation Revenues	$	(11	)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the Utilities' service territories during the third quarter of 2013, compared to the same period of 2012. This increased customer shopping, which does not impact earnings for the Regulated Distribution Segment, is expected to continue. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 82% from 80% for the Ohio Companies, 67% from 62% for the Pennsylvania Companies, 49% from 47% for PE and 50% from 47% for JCP&L. The increase in prices reflects the completion of marginal transmission loss refunds to ME and PN customers in the second quarter of 2013 and a higher generation rate at WP, which includes the recovery of transmission costs effective June 2013.

The decrease in wholesale generation revenues of $5 million in the third quarter of 2013 resulted from the expiration of NUG contracts, partially offset by higher energy and capacity prices in the third quarter of 2013.

The decrease in transmission revenues reflects the termination of WP's network transmission rider effective June 2013. Network transmission costs are now recovered through WP's generation rate.

Operating Expenses —

Total operating expenses increased by $171 million primarily due to the following:

• Fuel expense was $12 million higher in 2013 primarily related to increased generation at the Fort Martin plant during third quarter of 2013.

• Purchased power costs were $100 million lower in 2013 primarily due to a decrease in volumes required as a result of increased customer shopping, higher generation and reduced NUG purchases, partially offset by higher energy and capacity unit cost.

Source of Change in Purchased Power	Increase(Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(9	)
Change due to decreased volumes	(121		)
	(130		)
Purchases from affiliates:
Change due to increased unit costs	23
Change due to decreased volumes	(36		)
	(13		)
Decrease in costs deferred	43
Decrease in Purchased Power Costs	$	(100	)

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• Other operating expenses increased $6 million primarily due to:

• higher transmission expenses of $26 million primarily due to PJM transmission costs associated with RMR units, partially offset by

• lower distribution operating and maintenance expenses of $8 million primarily due to lower storm related maintenance activities during the third quarter of 2013, partially offset by more work allocated to capital in the third quarter of 2012 associated with integrating Allegheny's work management system,

• lower Pennsylvania state reimbursed program costs of $6 million, which are recovered through rates, and

• decreased regulated generation operating and maintenance expenses of $6 million primarily related to a forced outage at Fort Martin in the third quarter of 2012.

• Depreciation expense increased by $17 million due to a higher asset base and an adjustment in the third quarter of 2012 to reduce depreciation rates for WP that was approved by the PPUC in September 2012.

• Net regulatory asset amortization increased $250 million primarily due to a regulatory asset impairment associated with the recovery of marginal transmission losses at ME and PN, lower storm cost deferrals and higher default generation service costs recovery in Pennsylvania, partially offset by a reduction of NUG cost recovery at ME and PN and higher transmission cost deferrals in Ohio.

• General taxes decreased by $14 million primarily due to lower gross receipts and payroll taxes, partially offset by higher property taxes.

Other Expense —

Other expense increased $5 million in the third quarter of 2013 primarily due to lower investment income resulting from the liquidation of investments at Shippingport and lower NDT investment income.

Regulated Transmission — Third Quarter 2013 Compared with Third Quarter 2012

Net income decreased by $5 million in the third quarter of 2013 compared to the same period of 2012, as further described below.

Revenues —

Total revenues increased by $3 million principally due to higher revenue requirements at ATSI and TrAIL, partially offset by lower PJM network service revenues for the Utilities.

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

	Three Months Ended September 30				Increase
Revenues by Transmission Asset Owner	2013		2012		(Decrease)
	(In millions)
ATSI	$	56	$	53	$	3
TrAIL	56		51		5
PATH	5		4		1
Utilities	73		79		(6		)
Total Revenues	$	190	$	187	$	3

Operating Expenses —

Total operating expenses increased by $11 million principally due to higher asset removal costs and higher depreciation and property taxes, reflecting a higher asset base.

Competitive Energy Services — Third Quarter 2013 Compared with Third Quarter 2012

Net income decreased by $52 million in the third quarter of 2013, compared to the same period of 2012, as more fully described below.

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Revenues —

Total revenues increased by $98 million in the third quarter of 2013, compared to the same period of 2012, primarily due to growth in MWH sales for Direct, Governmental Aggregation, Mass Market, and POLR and Structured Sales channels. Revenues were adversely impacted by lower unit prices compared to 2012 as a result of a significant decrease in power prices beginning in the fourth quarter of 2011 when the 2013 Competitive retail sales position was approximately 50% committed. The increase in total revenues resulted from the following sources:

	Three Months Ended September 30				Increase (Decrease)
Revenues by Type of Service	2013		2012
	(In millions)
Direct	$	767	$	763	$	4
Governmental Aggregation	346		323		23
Mass Market	119		104		15
POLR and Structured	338		327		11
Wholesale	100		82		18
Transmission	34		37		(3		)
RECs	—		1		(1		)
Other	65		34		31
Total Revenues	$	1,769	$	1,671	$	98

	Three Months Ended September 30		Increase (Decrease)
MWH Sales by Channel	2013	2012
	(In thousands)
Direct	14,725	14,312	2.9	%
Governmental Aggregation	5,813	5,229	11.2	%
Mass Market	1,774	1,539	15.3	%
POLR and Structured	6,358	5,718	11.2	%
Wholesale	556	774	(28.2	)%
Total MWH Sales	29,226	27,572	6.0	%

The increase in Direct revenues of $4 million resulted from higher sales volumes due to the acquisition of new customers, partially offset by lower unit prices. The increase in Governmental Aggregation of $23 million resulted from the acquisition of new customers primarily in Illinois, partially offset by lower unit prices. The increase in Mass Market of $15 million resulted from the acquisition of new customers primarily in Ohio and Pennsylvania, partially offset by lower unit prices. The Direct, Governmental Aggregation and Mass Market customer base increased to 2.7 million customers as of September 30, 2013, as compared to 2.5 million as of September 30, 2012. The increase in retail sales was customer count driven as weather related usage was adversely affected with cooling degree days being 18% below the third quarter of 2012.

The increase in POLR and structured revenues of $11 million was due to higher structured sales, partially offset by lower prices and lower POLR sales. The decline in POLR sales is in line with FES' strategy to realign its sales portfolio.

Wholesale revenues increased $18 million due to a $33 million increase in capacity revenues primarily from higher capacity prices, partially offset by a $9 million reduction in gains on financially settled contracts, and a $6 million decrease in short-term (net hourly positions) transactions. The decrease in wholesale sales volumes was due to lower generation available for sale primarily as a result of the plants that were deactivated in 2012 and those under RMR arrangements and higher retail sales volumes.

Other revenue increased $31 million due to an $18 million pre-tax gain on the sale of property to a regulated affiliate and an increase in income from FEV's equity method investment in Global Holding.

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

Source of Change in Direct Revenues	Increase (Decrease)
	(In millions)
Direct :
Effect of increase in sales volumes	$	22
Change in prices	(18		)
	$	4

Source of Change in Governmental Aggregation Revenues	Increase (Decrease)
	(In millions)
Governmental Aggregation:
Effect of increase in sales volumes	$	36
Change in prices	(13		)
	$	23

Source of Change in Mass Market Revenues	Increase (Decrease)
	(In millions)
Mass Market:
Effect of increase in sales volumes	$	16
Change in prices	(1		)
	$	15

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of increase in sales volumes	$	47
Change in prices	(36		)
	$	11

Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(6	)
Gain on settled contracts	(9		)
Capacity revenue	33
	$	18

Operating Expenses —

Total operating expenses increased by $161 million in the third quarter of 2013 due to the following:

• Fuel costs increased $9 million due primarily to settlements associated with past damages on various coal and transportation contracts, partially offset by lower unit prices associated with new and restructured coal contracts. Volumes increased as a result of higher fossil generation driven by increased economic generation and the W.H. Sammis Plant being temporarily idled in September 2012, partially offset by lower nuclear generation due to unplanned outages.

• Purchased power costs increased $143 million due to higher capacity expenses ($43 million), higher volumes ($64 million) and increased prices ($46 million), partially offset by reduced losses on financially settled contracts ($10 million). The

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increase in rate was primarily a result of higher on-peak prices compared to 2012. The increase in capacity expenses and purchased power volumes relates to the overall increase in sales volumes. Additionally, higher capacity expenses were the result of higher capacity rates primarily in the MAAC zone.

• Fossil operating costs decreased by $10 million due primarily to lower labor costs resulting from previously deactivated units and lower compensation and benefit expenses based on plan changes.

• Nuclear operating costs decreased by $10 million due primarily to lower labor costs and lower compensation and benefit expenses based on plan changes.

• Transmission expenses increased $20 million due primarily to higher rates associated with higher congestion, network and line loss costs and additional retail load, partially offset by lower ancillary costs and a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units in the ATSI zone.

• General taxes decreased by $3 million due primarily to lower payroll taxes as a result of lower labor costs noted above, partially offset by higher property taxes.

• Depreciation expense increased $23 million primarily due to a higher asset base and accelerated depreciation associated with the deactivation of two unregulated coal-fired generating plants.

• Other operating expenses decreased by $11 million primarily due to reduced lease costs from the sale and leaseback repurchases and lower corporate support costs.

Other Expense —

Total other expense in the third quarter of 2013 increased $22 million compared to the same period of 2012 due to lower investment income of $41 million due to higher OTTI on the NDT investments, partially offset by lower net interest expense of $19 million due to debt redemptions and repurchases.

Other — Third Quarter 2013 Compared with Third Quarter 2012

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 $51 millionincrease in net income in the third quarter of 2013 compared to the same period of 2012 primarily due to reductions in certain state related deferred tax liabilities and valuation reserves against net operating loss carryforwards. This benefit was partially offset by increased interest expense due to the issuance of $1.5 billion of senior unsecured notes in the first quarter of 2013 and a gain on a forward starting interest rate swap agreement in the third quarter of 2012.

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Summary of Results of Operations — First Nine Months of 2013 Compared with the First Nine Months of 2012

Financial results for FirstEnergy’s business segments in the first nine months of 2013 and 2012 were as follows:

First Nine Months 2013 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	6,414		$	546		$	4,204		$	(128	)	$	11,036
Other	179			—			146			(91		)	234
Internal	—			—			588			(588		)	—
Total Revenues	6,593			546			4,938			(807		)	11,270
Operating Expenses:
Fuel	250			—			1,665			—			1,915
Purchased power	2,547			—			973			(588		)	2,932
Other operating expenses	1,274			98			1,517			(244		)	2,645
Provision for depreciation	446			84			347			32			909
Amortization of regulatory assets, net	436			7			—			—			443
General taxes	527			41			158			21			747
Impairment of long-lived assets	—			—			473			—			473
Total Operating Expenses	5,480			230			5,133			(779		)	10,064
Operating Income (Loss)	1,113			316			(195		)	(28		)	1,206
Other Income (Expense):
Loss on debt redemptions	—			—			(149		)	17			(132		)
Investment income (loss)	41			—			(6		)	(27		)	8
Interest expense	(404		)	(68		)	(187		)	(112		)	(771		)
Capitalized interest	8			1			31			11			51
Total Other Expense	(355		)	(67		)	(311		)	(111		)	(844		)
Income (Loss) From Continuing Operations Before Income Taxes	758			249			(506		)	(139		)	362
Income taxes (benefits)	284			93			(189		)	(59		)	129
Income (Loss) From Continuing Operations	474			156			(317		)	(80		)	233
Discontinued Operations, net of tax	—			—			17			—			17
Net Income (Loss)	474			156			(300		)	(80		)	250
Income attributable to noncontrolling interest	—			—			—			—			—
Earnings (Losses) Available to FirstEnergy Corp.	$	474		$	156		$	(300	)	$	(80	)	$	250

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First Nine Months 2012 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	6,818		$	557		$	4,355		$	(166	)	$	11,564
Other	158			—			110			(54		)	214
Internal	—			—			686			(684		)	2
Total Revenues	6,976			557			5,151			(904		)	11,780
Operating Expenses:
Fuel	173			—			1,660			—			1,833
Purchased power	2,987			—			1,064			(684		)	3,367
Other operating expenses	1,363			99			1,387			(252		)	2,597
Provision for depreciation	421			85			303			25			834
Amortization of regulatory assets, net	197			1			—			—			198
General taxes	543			33			161			23			760
Total Operating Expenses	5,684			218			4,575			(888		)	9,589
Operating Income	1,292			339			576			(16		)	2,191
Other Income (Expense):
Investment income	62			1			48			(48		)	63
Interest expense	(405		)	(70		)	(209		)	(66		)	(750		)
Capitalized interest	9			2			34			9			54
Total Other Expense	(334		)	(67		)	(127		)	(105		)	(633		)
Income From Continuing Operations Before Income Taxes	958			272			449			(121		)	1,558
Income taxes	355			101			165			29			650
Income From Continuing Operations	603			171			284			(150		)	908
Discontinued Operations, net of tax	—			—			11			—			11
Net Income	603			171			295			(150		)	919
Income attributable to noncontrolling interest	—			—			—			1			1
Earnings Available to FirstEnergy Corp.	$	603		$	171		$	295		$	(151	)	$	918

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Changes Between First Nine Months 2013 and First Nine Months 2012 Financial Results Increase (Decrease)	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	(404	)	$	(11	)	$	(151	)	$	38		$	(528	)
Other	21			—			36			(37		)	20
Internal	—			—			(98		)	96			(2		)
Total Revenues	(383		)	(11		)	(213		)	97			(510		)
Operating Expenses:
Fuel	77			—			5			—			82
Purchased power	(440		)	—			(91		)	96			(435		)
Other operating expenses	(89		)	(1		)	130			8			48
Provision for depreciation	25			(1		)	44			7			75
Amortization of regulatory assets, net	239			6			—			—			245
General taxes	(16		)	8			(3		)	(2		)	(13		)
Impairment of long-lived assets	—			—			473			—			473
Total Operating Expenses	(204		)	12			558			109			475
Operating Income (Loss)	(179		)	(23		)	(771		)	(12		)	(985		)
Other Income (Expense):
Gain (loss) on debt redemptions	—			—			(149		)	17			(132		)
Investment income	(21		)	(1		)	(54		)	21			(55		)
Interest expense	1			2			22			(46		)	(21		)
Capitalized interest	(1		)	(1		)	(3		)	2			(3		)
Total Other Expense	(21		)	—			(184		)	(6		)	(211		)
Income (Loss) From Continuing Operations Before Income Taxes	(200		)	(23		)	(955		)	(18		)	(1,196		)
Income taxes (benefits)	(71		)	(8		)	(354		)	(88		)	(521		)
Income (Loss) From Continuing Operations	(129		)	(15		)	(601		)	70			(675		)
Discontinued Operations, net of tax	—			—			6			—			6
Net Income (Loss)	(129		)	(15		)	(595		)	70			(669		)
Loss attributable to noncontrolling interest	—			—			—			(1		)	(1		)
Earnings (Losses) Available to FirstEnergy Corp.	$	(129	)	$	(15	)	$	(595	)	$	71		$	(668	)

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Regulated Distribution — First Nine Months of 2013 Compared with First Nine Months of 2012

Net income decreased by $129 million in the first nine months of 2013 compared to the same period of 2012, as more fully described below.

Revenues —

The $383 milliondecrease in total revenues resulted from the following sources:

	Nine Months Ended September 30				Increase
Revenues by Type of Service	2013		2012		(Decrease)
	(In millions)
Distribution services	$	2,861	$	3,006	$	(145	)
Generation sales:
Retail	3,014		3,200		(186		)
Wholesale	203		269		(66		)
Total generation sales	3,217		3,469		(252		)
Transmission	336		343		(7		)
Other	179		158		21
Total Revenues	$	6,593	$	6,976	$	(383	)

The decrease in distribution services revenue is primarily the result of a NJBPU-approved reduction to the JCP&L NUG Rider which became effective on March 1, 2012, and a decrease to the ME and PN NUG riders which resulted from the expiration of certain NUG contracts in 2012 and 2013 and lower recovery of energy efficiency expenses reflecting reduced costs, partially offset by an increase in the Ohio Companies' DCR rider. Distribution deliveries decreased by 0.1% in the first nine months of 2013 compared to the same period of 2012. Distribution deliveries by customer class are summarized in the following table:

	Nine Months Ended September 30		Increase
Electric Distribution MWH Deliveries	2013	2012	(Decrease)
	(In thousands)
Residential	40,996	40,934	0.2	%
Commercial	32,058	32,384	(1.0	)%
Industrial	37,851	37,740	0.3	%
Other	436	444	(1.8	)%
Total Electric Distribution MWH Deliveries	111,341	111,502	(0.1	)%

Higher deliveries to residential customers primarily reflects increased weather-related usage resulting from heating degree days that were 26% above 2012, and 2% above normal, partially offset by cooling degree days that were 18% below 2012, and 1% above normal. Lower deliveries to the commercial sector primarily reflect increasing energy efficiency mandates and demand response initiatives. In the Industrial sector, decreased sales to steel and automotive customers were partially offset by higher sales to chemical, petroleum and shale gas customers. Additionally, FirstEnergy expects additional growth in the industrial sector beyond 2013 for potential shale gas projects. As the gas fields are developed, the opportunity for additional manufacturing expansion could further support growth.

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The following table summarizes the price and volume factors contributing to the $252 milliondecrease in generation revenues for the first nine months of 2013 compared to the same period of 2012:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(193	)
Change in prices	7
	(186		)
Wholesale:
Effect of decrease in sales volumes	(96		)
Change in prices	30
	(66		)
Decrease in Generation Revenues	$	(252	)

The decrease in retail generation sales volume was primarily due to increased customer shopping in the Utilities' service territories during the first nine months of 2013, compared to the same period of 2012. This increased customer shopping, which does not impact earnings for the Regulated Distribution Segment, is expected to continue. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 81% from 79% for the Ohio Companies, 66% from 61% for the Pennsylvania Companies, 47% from 46% for PE and 52% from 49% for JCP&L. The increase in prices reflects the conclusion of marginal transmission loss refunds to ME and PN customers in the second quarter of 2013 and a higher generation rate at WP, which includes the recovery of transmission costs effective June 2013, partially offset by lower auction prices for power supply in the first nine months of 2013 compared to the same period of 2012.

The decrease in wholesale generation revenues of $66 million in the first nine months of 2013 resulted from the expiration of NUG contracts, partially offset by higher energy and capacity prices.

The decrease in transmission revenues reflects the termination of WP's network transmission rider effective June 2013. Network transmission costs are now recovered through WP's generation rate.

Other revenues increased by $21 million primarily due to more customer requested work in the first nine months of 2013 compared to the same period of 2012.

Operating Expenses —

Total operating expenses decreased by $204 million due to the following:

• Fuel expense was $77 million higher in 2013 primarily related to increased generation at Fort Martin as a result of planned and forced outages in the first nine months of 2012.

• Purchased power costs were $440 million lower in 2013 primarily due to a decrease in volumes required from increased customer shopping, higher generation, reduced NUG purchases and lower unit power supply costs during the first nine months of 2013 compared to the same period of 2012.

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Source of Change in Purchased Power	Increase(Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(118	)
Change due to decreased volumes	(333		)
	(451		)
Purchases from affiliates:
Change due to decreased unit costs	(6		)
Change due to decreased volumes	(80		)
	(86		)
Decrease in costs deferred	97
Decrease in Purchased Power Costs	$	(440	)

• Other operating expenses decreased $89 million primarily due to:

• a decrease in energy efficiency program expenses of $45 million resulting from the completion of certain initiatives in Ohio and Pennsylvania, which are recovered through rates,

• lower distribution operating and maintenance expenses of $58 million primarily due to lower storm related maintenance activities during the first nine months of 2013, and

• decreased regulated generation operating and maintenance expenses of $22 million primarily related to planned and forced outages at Fort Martin in the first nine months of 2012, partially offset by

• higher transmission expenses of $36 million primarily due to PJM transmission costs associated with RMR units.

• Depreciation expense increased by $25 million due to a higher asset base.

• Net regulatory asset amortization increased $239 million primarily due to a regulatory asset impairment associated with the recovery of marginal transmission losses at ME and PN, lower storm cost deferrals and higher default generation service costs recovery in Pennsylvania, partially offset by a reduction of NUG cost recovery at ME and PN and higher transmission cost deferrals in Ohio.

• General taxes decreased by $16 million primarily due to a decrease in gross receipt taxes, payroll taxes and West Virginia's business and occupation tax, partially offset by an increase in property taxes.

Other Expense —

Other expense increased $21 million in the first nine months of 2013 primarily due to lower investment income resulting from the liquidation of investments at Shippingport, higher OTTI and lower NDT investment income.

Regulated Transmission — First Nine Months of 2013 Compared with First Nine Months of 2012

Net income decreased by $15 million in the first nine months of 2013 compared to the same period of 2012, as further described below.

Revenues —

Total revenues decreased by $11 million principally due to lower PJM network service revenues for ATSI and the Utilities.

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

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	Nine Months Ended September 30				Increase
Revenues by Transmission Asset Owner	2013		2012		(Decrease)
	(In millions)
ATSI	$	156	$	160	$	(4	)
TrAIL	155		153		2
PATH	15		12		3
Utilities	220		232		(12		)
Total Revenues	$	546	$	557	$	(11	)

Operating Expenses —

Total operating expenses increased by $12 million principally due to higher property taxes, reflecting a higher asset base, and increased amortization of regulatory assets.

Competitive Energy Services — First Nine Months of 2013 Compared with First Nine Months of 2012

Net income decreased by $595 million in the first nine months of 2013, compared to the same period of 2012, as more fully described below.

Revenues —

Total revenues decreased by $213 million in the first nine months of 2013, compared to the same period of 2012, primarily due to a decline in wholesale sales. Revenues were adversely impacted by lower unit prices compared to 2012 as a result of a significant decrease in power prices beginning in the fourth quarter of 2011 when the 2013 Competitive retail sales position was approximately 50% committed. These decreases were partially offset by growth in governmental aggregation and mass market sales.

The decrease in total revenues resulted from the following sources:

	Nine Months Ended September 30				Increase
Revenues by Type of Service	2013		2012		(Decrease)
	(In millions)
Direct	$	2,202	$	2,223	$	(21	)
Governmental Aggregation	911		788		123
Mass Market	335		264		71
POLR and Structured	971		1,002		(31		)
Wholesale	258		637		(379		)
Transmission	115		122		(7		)
RECs	—		5		(5		)
Other	146		110		36
Total Revenues	$	4,938	$	5,151	$	(213	)

	Nine Months Ended September 30		Increase
MWH Sales by Channel	2013	2012	(Decrease)
	(In thousands)
Direct	42,347	41,029	3.2	%
Governmental Aggregation	15,975	12,833	24.5	%
Mass Market	5,045	3,865	30.5	%
POLR and Structured	18,716	17,740	5.5	%
Wholesale	1,394	3,513	(60.3	)%
Total MWH Sales	83,477	78,980	5.7	%

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The decrease in Direct revenues of $21 million resulted from lower unit prices partially offset by increased sales volumes due to the acquisition of new customers and weather related usage as heating degree days were 26% above 2012 levels, partially offset by cooling degree days which were 18% below 2012 levels. The increase in Governmental Aggregation of $123 million resulted from the acquisition of new customers primarily in Illinois and weather related usage, partially offset by lower unit prices. The increase in Mass Market of $71 million resulted from the acquisition of new customers primarily in Ohio and Pennsylvania and weather related usage, partially offset by lower unit prices. The Direct, Governmental Aggregation and Mass Market customer base increased to 2.7 million customers as of September 30, 2013 as compared to 2.5 million as of September 30, 2012.

The decrease in POLR and structured revenues of $31 million was due primarily to lower prices and lower POLR sales, partially offset by higher structured sales. The decline in POLR sales is in line with FES' strategy to realign its sales portfolio.

Wholesale revenues decreased $379 million due to a $185 million reduction in gains on financially settled contracts, a $145 million decrease in capacity revenues primarily from lower capacity prices and a $49 million decrease in short-term (net hourly positions) transactions. The decrease in wholesale sales volumes was due to lower generation available for sale, primarily as a result of plants that were deactivated in 2012 and those under RMR arrangements, lower nuclear generation and higher retail sales volumes.

Transmission revenue decreased $7 million due primarily to lower congestion revenue, partially offset by higher ancillary revenue associated with additional retail load.

Other revenue increased $36 million due to an $18 million pre-tax gain on the sale of property to a regulated affiliate and an increase in income from FEV's equity method investment in Global Holding.

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

Source of Change in Direct Revenues	Increase (Decrease)
	(In millions)
Direct :
Effect of increase in sales volumes	$	72
Change in prices	(93		)
	$	(21	)

Source of Change in Governmental Aggregation Revenues	Increase (Decrease)
	(In millions)
Governmental Aggregation:
Effect of increase in sales volumes	$	193
Change in prices	(70		)
	$	123

Source of Change in Mass Market Revenues	Increase (Decrease)
	(In millions)
Mass Market:
Effect of increase in sales volumes	$	80
Change in prices	(9		)
	$	71

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
POLR and Structured:
Effect of increase in sales volumes	$	66
Change in prices	(97		)
	$	(31	)

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Source of Change in Wholesale Revenues	Increase (Decrease)
	(In millions)
Wholesale:
Effect of decrease in sales volumes	$	(55	)
Change in prices	6
Gain on settled contracts	(185		)
Capacity revenue	(145		)
	$	(379	)

Operating Expenses —

Total operating expenses increased by $558 million in the first nine months of 2013 due to the following:

• Fuel costs increased $5 million due primarily to settlements associated with past damages on various coal and transportation contracts, partially offset by lower unit prices associated with new and restructured coal contracts. Volumes decreased as a result of lower nuclear generation due to unplanned outages, partially offset by higher fossil generation driven by increased economic generation and the W.H. Sammis Plant being temporarily idled in September 2012.

• Purchased power costs decreased $91 million due to reduced capacity expenses ($170 million) and lower losses on financially settled contracts ($218 million) partially offset by higher volumes ($218 million) and prices ($79 million). The increase in purchased power volumes relates to lower generation primarily from the plants that were deactivated in 2012 and those under RMR arrangements, lower nuclear generation and the overall increase in sales volumes.

• Fossil operating costs decreased by $9 million due primarily to lower labor costs resulting from previously deactivated units and lower compensation and benefit expenses based on plan changes. The lower labor costs were partially offset by higher contractor, materials and equipment costs resulting from an increase in planned generating unit outages in the first nine months of 2013 as compared to the same period in 2012.

• Nuclear operating costs decreased by $27 million due primarily to lower contractor, materials and equipment costs. In 2013, there was a single refueling outage at Perry while there were two refueling outages during the same period of 2012. Additionally, compensation and benefit expenses were lower as a result of plan changes in 2013.

• Transmission expenses increased $79 million due primarily to higher rates associated with higher ancillary, network and line loss costs and additional retail load, partially offset by lower congestion costs and a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units.

• Impairments of long-lived assets increased by $473 million due to the decision to deactivate two unregulated, coal-fired generating plants in the second quarter of 2013.

• Depreciation expense increased $44 million primarily due to the absence of credits in 2013 from a 2012 settlement with the DOE, higher asset base, and accelerated depreciation associated with deactivation noted above.

• General taxes decreased by $3 million due primarily to lower payroll taxes as a result of lower labor costs noted above, partially offset by higher property taxes.

• Other operating expenses increased by $87 million primarily due to an increase in mark-to-market expense on commodity contract positions ($99 million) and increased retail expenses ($13 million), partially offset by reduced lease costs from sale and leaseback repurchases ($25 million).

Other Expense —

Total other expense in the first nine months of 2013 increased $184 million compared to the same period of 2012 primarily due to a $149 million loss on debt redemptions in connection with senior notes that were repurchased and lower investment income of $54 million due to higher OTTI on NDT investments, partially offset by lower net interest expense of $19 million due to debt redemptions and repurchases.

Other — First Nine Months of 2013 Compared with First Nine Months of 2012

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 $70 millionincrease in net income in the first nine months of 2013 compared to the same period of 2012 due to lower income tax expense resulting from a change in state income tax allocation factors and reductions in state deferred tax liabilities, partially offset by net increases in valuation reserves against net operating

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loss carryforwards. This benefit was partially offset by increased interest expense due to the issuance of $1.5 billion of senior unsecured notes in the first quarter of 2013.

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 table provides information about the composition of net regulatory assets as of September 30, 2013 and December 31, 2012, and the changes during the nine months ended September 30, 2013:

Regulatory Assets by Source	September 30, 2013			December 31, 2012			Increase (Decrease)
	(In millions)
Regulatory transition costs	$	265		$	293		$	(28	)
Customer receivables for future income taxes	505			508			(3		)
Nuclear decommissioning and spent fuel disposal costs	(191		)	(219		)	28
Asset removal costs	(358		)	(372		)	14
Deferred transmission costs	154			390			(236		)
Deferred generation costs	408			379			29
Deferred distribution costs	205			231			(26		)
Contract valuations	435			463			(28		)
Storm-related costs	463			469			(6		)
Other	260			233			27
Total	$	2,146		$	2,375		$	(229	)

Regulatory assets that do not earn a current return totaled approximately $509 million as of September 30, 2013 primarily related to storm damage costs.

As of September 30, 2013 and December 31, 2012, FirstEnergy had approximately $362 million and $392 million, respectively, of net regulatory liabilities that are primarily related to asset removal costs. Net regulatory liabilities are classified within Other noncurrent liabilities on the Consolidated Balance Sheets.

CAPITAL RESOURCES AND LIQUIDITY

FirstEnergy expects its existing sources of liquidity to remain sufficient to meet its anticipated obligations and those of its subsidiaries. FirstEnergy’s business is capital intensive, requiring significant resources to fund operating expenses, construction expenditures, scheduled debt maturities and interest and dividend payments. In addition to internal sources to fund liquidity and capital requirements for 2013 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 discussed in the Overview, FirstEnergy's 2013 financial plan also includes a series of actions, including the net transfer of 1,476 MW between AE Supply and MP of the Harrison and Pleasants power plants, which closed on October 9, 2013, and the proposed sale of 527 MWs of unregulated hydro assets. Proceeds from both of these transactions are expected to be used to further reduce debt at the Competitive Energy Services and Corporate Segment. FirstEnergy also anticipates refinancing maturing debt at certain Utilities and reducing short-term borrowings. In addition, on October 18, 2013, a conditional notice of full redemption was issued calling the $235 million of outstanding PCRB's for redemption on November 15, 2013.

On September 25, 2013, FE filed a registration statement with the SEC to register 4 million shares of common stock to be issued to registered shareholders and its employees and the employees of its subsidiaries under its Stock Investment Plan. In addition, FE expects to also begin fulfilling certain share-based benefit plan obligations through the issuance of authorized but unissued common stock.

FirstEnergy intends to focus on growing its regulated operations - particularly in transmission. FirstEnergy plans to implement a four-year, $2.8 billion Transmission Reliability Excellence Plan (TREP) designed to improve operating flexibility, increase the reliability of the regional transmission system, position capacity for future load growth and facilitate response to system events. Beginning in 2014, FirstEnergy plans to deploy the $2.8 billion of incremental investments associated with TREP, in addition to the baseline capital program expenditures forecasted at $1.8 billion over the same time period. Currently, FirstEnergy estimates that 2014 capital expenditures associated with TREP will be approximately $500 million in 2014, growing to approximately $700 million in 2015 and

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approximately $800 million in both 2016 and 2017. These investments will focus primarily in ATSI, which has a formula rate recovery mechanism, but will ultimately extend throughout FirstEnergy's service area. FirstEnergy currently expects to fund the TREP capital investments through the issuance of debt and equity.

Because the activities contemplated by the 2013 financial plan are subject to market conditions and other factors, no assurance can be given that FirstEnergy will complete all of the remaining components of its 2013 financial plan including that the hydro assets will be sold or additional equity will be issued within the currently expected timeframes or at all. In addition, FirstEnergy expects to consider changes or additions to the 2013 financial plan from time to time.

As of September 30, 2013, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to currently payable long-term debt and short-term borrowings. Currently payable long-term debt as of September 30, 2013, included the following:

Currently Payable Long-Term Debt	(In millions)
PCRBs supported by bank LOCs (1)	$	809
Unsecured notes	827
Unsecured PCRBs (1)	50
Collateralized lease obligation bonds	67
Sinking fund requirements	120
Other notes	16
	$	1,889

⁽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 $3,404 million of short-term borrowings as of September 30, 2013, and $1,969 million as of December 31, 2012. FirstEnergy’s available liquidity as of October 31, 2013, was as follows:

Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	May 2018	$	2,500	$	294
FES / AE Supply	Revolving	May 2018	2,500		2,499
FET(2)	Revolving	May 2018	1,000		—
AGC	Revolving	Dec. 2013	50		45
		Subtotal	$	6,050	$	2,838
		Cash	—		119
		Total	$	6,050	$	2,957

⁽¹⁾  FE 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 $6.0 billion (Facilities). The Facilities consist of a $2.5 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 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. 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 75% for FET, measured at the end of each fiscal quarter.

On May 8, 2013, FE, FES, and FE's other borrowing subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each facility was extended until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. The FE Facility was amended to increase the lending banks' commitments under the facility by $500 million to a total of $2.5 billion and to increase the individual borrower sub-limits for FE by $500 million to a total of $2.5 billion and for JCP&L by $175 million to a total of $600 million.

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On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the facility. Similarly, the FES/AE Supply $2.5 billion revolving credit facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. The effect of these amendments will apply to the compliance reports for the period ended September 30, 2013, which are due November 29, 2013.

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 amended) as of September 30, 2013:

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		$	2,500		$	—		$	—		$	—	(1)	59.8	%
FES		—			1,500			—			—		(2)	35.3	%
AE Supply		—			1,000			—			—		(2)	27.2	%
FET		—			—			1,000			—		(1)	64.2	%
OE		500			—			—			500		(3)	46.5	%
CEI		500			—			—			500		(3)	54.0	%
TE		500			—			—			500		(3)	49.7	%
JCP&L		600			—			—			850		(3)	47.6	%
ME		300			—			—			500		(3)	51.4	%
PN		300			—			—			300		(3)	54.3	%
WP		200			—			—			200		(3)	47.7	%
MP		150			—			—			150		(3)	46.6	%
PE		150			—			—			150		(3)	49.8	%
ATSI		—			—			100			100		(3)	40.3	%
Penn		50			—			—			50		(3)	38.2	%
TrAIL		—			—			200			400		(3)	44.3	%

⁽¹⁾  No limitations.

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

⁽³⁾  Includes amounts which may be borrowed under the regulated companies' money pool.

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 (subject to borrowings drawn under the Facilities) 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 September 30, 2013, the debt to total capitalization ratio for AGC (as defined under this credit facility) was 41%.

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FirstEnergy Money Pools

FirstEnergy’s regulated companies also have the ability to borrow from each other and the holding company to meet their short-term working capital requirements. A similar but separate arrangement exists among FirstEnergy’s unregulated companies. FESC administers these two money pools and tracks surplus funds of FirstEnergy and the respective regulated and unregulated subsidiaries, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first nine months of 2013 was 0.47% per annum for the regulated companies’ money pool and 1.46% per annum for the unregulated companies’ money pool.

Pollution Control Revenue Bonds

As of September 30, 2013, FirstEnergy’s currently payable long-term debt included approximately $809 million ($736 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 outstanding as of September 30, 2013 were issued by the following banks:

Bank	Aggregate Amount(1)		Termination Date	Reimbursements of Draws Due
	(In millions)
UBS	$	268	April 2014	April 2014
CitiBank N.A.	164		June 2014	June 2014
Wells Fargo	151		March 2014	March 2014
The Bank of Nova Scotia	48		April 2014	April 2014
The Bank of Nova Scotia	82		April 2015	April 2015
The Bank of Nova Scotia	96		December 2015	December 2015
Total	$	809

⁽¹⁾  Excludes approximately $9 million of applicable interest coverage.

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Long-Term Debt Capacity

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’ credit ratings as of September 30, 2013:

	Senior Secured			Senior Unsecured
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FE	—	—	—	BB+	Baa3	BB+
FES	—	—	—	BBB-	Baa3	BB+
AE Supply	—	—	—	BBB-	Baa3	BB+
AGC	—	—	—	BBB-	Baa3	BBB
ATSI	—	—	—	BBB-	Baa2	BBB+
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-	Baa1	BBB+
WP	BBB+	A3	A-	BBB-	Baa2	BBB+

On September 16, 2013, Fitch affirmed the issuer default ratings of FirstEnergy (BB+) and all its subsidiaries (ranging from BB+ to BBB). Fitch's outlook for FE and all of its subsidiaries is stable.

Debt capacity is subject to the consolidated debt to total capitalization limits in the Facilities discussed above as such Facilities have been amended as of October 31, 2013 for periods ending on or after September 30, 2013. As of September 30, 2013, FE and its subsidiaries could issue additional debt of approximately $5.1 billion and remain within the limitations of the financial covenants required by the Facilities (as amended). As of September 30, 2013, FES' incremental debt capacity under its consolidated debt to total capitalization financial covenant (as amended) is also $5.1 billion given FE's debt to total capitalization ratio of 59.8%.

Changes in Cash Position

As of September 30, 2013, FirstEnergy had $222 million of cash and cash equivalents compared to $172 million of cash and cash equivalents as of December 31, 2012. As of September 30, 2013 and December 31, 2012, FirstEnergy had approximately $82 million and $62 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 by its regulated distribution, regulated transmission and competitive energy services businesses (see Results of Operations above). Net cash provided from operating activities was $1,671 million during the first nine months of 2013 compared with $1,276 million provided from operating activities during the first nine months of 2012, as summarized in the following table:

	Nine Months Ended September 30
Operating Cash Flows	2013			2012			Increase (Decrease)
	(In millions)
Net income	$	250		$	919		$	(669	)
Non-cash charges	2,064			1,520			544
Pension trust contributions	—			(600		)	600
Working capital and other	(643		)	(563		)	(80		)
	$	1,671		$	1,276		$	395

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The $395 million increase in cash from operations is primarily a result of a $600 million pension contribution in 2012 that did not occur in 2013. The increase was partially offset by $80 million more in cash outflows in 2013 from changes in operating assets and liabilities primarily as a result of payments in 2013 associated with 2012 storm restoration activities.

The $544 million increase in non-cash charges is primarily due to the following:

• $473 million increase from impairment of long-lived assets due to the Hatfield's Ferry and Mitchell plant deactivations.

• $132 million increase from the loss on debt redemptions associated with the completion of the FES/AE Supply tender offers and the $400 million FES debt redemption described below.

• $153 million increase from lower deferred purchased power and other costs primarily due to the expiration of certain NUG agreements.

• $40 million increase from higher deferred rents and market lease valuation as a result of increased net amortization of lease expense.

• $245 million increase in amortization of regulatory assets primarily due to a regulatory asset impairment charge at ME and PN associated with the recovery of marginal transmission losses.

• $104 million increase due to net commodity derivative transactions.

• $598 million decrease in deferred income taxes and investment tax credits. Of the decrease, $156 million was the result of the reversal of deferred income tax liabilities associated with the impairment of Hatfield's Ferry and Mitchell.

Cash Flows From Financing Activities

In the first nine months of 2013, cash provided from financing activities was $654 million compared to $662 million of net cash provided from financing activities during the first nine months of 2012. The following table summarizes new debt financing (net of any discounts) and redemptions:

	Nine Months Ended September 30
Securities Issued or Redeemed / Repaid	2013			2012
	(In millions)
New Issues
PCRBs	$	—		$	560
Long-term revolving credit	—			—
Senior secured notes	445			—
FMBs	—			100
Unsecured Notes	2,300			—
	$	2,745		$	660
Redemptions / Repayments
PCRBs	$	(234	)	$	(188	)
Long-term revolving credit	(40		)	—
Senior secured notes	(353		)	(99		)
Unsecured notes	(2,035		)	(583		)
	$	(2,662	)	$	(870	)
Short-term borrowings, net	$	1,435		$	1,604

During the first quarter of 2013, FE issued in aggregate $1.5 billion of senior unsecured notes in two series: $650 million of 2.75% senior notes due March 15, 2018 and $850 million of 4.25% senior notes due March 15, 2023. The stated interest rates are subject to adjustments based upon changes in the credit ratings of FirstEnergy but will not decrease below the issued rates. The proceeds were used to repay short-term borrowings and to invest in the money pool for FES and AE Supply's use in funding a portion of their concurrent tender offers.

Also during the first quarter of 2013, pursuant to tender offers launched in February 2013, FES and AE Supply repurchased $369 million and $294 million, respectively, of outstanding senior notes with interest rates ranging from 5.75% to 6.8%. The $369 million of FES repurchases consisted of original maturities of $252 million due 2021 and $117 million due 2039. The $294 million of AE Supply repurchases consisted of original maturities of $194 million due 2019 and $100 million due 2039. FES and AE Supply paid $67 million and $43 million, respectively, in tender premiums to repurchase the tendered senior notes. FirstEnergy recorded a loss on debt redemption of $119 million (FES - $71 million), including such premiums and other related expenses. The tender premiums paid are included in cash flows from financing activities in the Consolidated Statement of Cash Flows.

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In March 2013, ME issued $300 million of 3.50% senior unsecured notes due March 15, 2023. Proceeds from this offering were used to repay $150 million of ME 4.95% senior unsecured notes that matured in March 2013 and short-term borrowings.

On April 15, 2013, FES redeemed $400 million of its 4.80% senior notes due 2015 and recorded a loss on debt redemption of $32 million including $31 million of make-whole premiums paid. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

On June 3, 2013, FG exercised a mandatory put option and repurchased approximately $235 million of PCRBs due 2023, which FG is currently holding for remarketing subject to future market and other conditions.

As discussed in Note 8, Variable Interest Entities, in June 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors.The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. In addition, during the second quarter FirstEnergy Corp. completed a $1.5 billion equity contribution to FES.

During August the Ohio Companies redeemed an additional $660 million of long-term debt with interest rates ranging from 5.65% to 7.25% and paid approximately $120 million of make-whole premiums that were deferred as a regulatory asset and will be amortized over the original life of the redeemed debt. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. Additionally, during August, JCP&L issued $500 million of 4.7% unsecured notes due April 2024 and used the proceeds to pay down a portion of its short-term debt obligations.

Cash Flows From Investing Activities

Cash used for investing activities in the first nine months of 2013 principally represented cash used for property additions. The following table summarizes investing activities for the first nine months of 2013 and the comparable period of 2012:

	Nine Months Ended September 30
Cash Used for Investing Activities	2013		2012			Increase (Decrease)
	(In millions)
Property Additions:
Regulated distribution	$	980	$	751		$	229
Regulated transmission	291		169			122
Competitive energy services	630		715			(85		)
Other and reconciling adjustments	59		51			8
Nuclear fuel	159		207			(48		)
Investments	34		(45		)	79
Other	122		142			(20		)
	$	2,275	$	1,990		$	285

Net cash used for investing activities during the first nine months of 2013 increased by $285 million compared to the same period of 2012. The increase was principally due to an increase in property additions of $274 million primarily from 2012 storm costs, including costs associated with Hurricane Sandy, paid in 2013 and a decrease in proceeds from investments primarily as a result of the liquidation of Shippingport investments, partially offset by a decrease in nuclear fuel procurement costs.

In 2012, FG acquired certain equity and other lessor interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $262 millionand in March of 2013, FG acquired the remaining interests for approximately $221 million.

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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 be required to make under these guarantees as of September 30, 2013, was approximately $4.4 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)	$	269
LOC (long-term debt) - interest coverage(2)	5
OVEC obligations	300
Deferred compensation arrangements	504
Other(3)	325
	1,403
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts	66
LOC (long-term debt) - interest coverage(2)	3
FES’ guarantee of NG’s nuclear property insurance	88
FES’ guarantee of FG’s sale and leaseback obligations	2,064
Other	11
	2,232
Global Holding facility	350
Surety Bonds	265
LOCs(4)	132
	747
Total Guarantees and Other Assurances	$	4,382

⁽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 $809 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

⁽³⁾  Includes guarantees of $136 million for nuclear decommissioning funding assurances, $161 million supporting OE’s sale and leaseback arrangements, and $21 million for railcar leases.

⁽⁴⁾  Includes $7 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $97 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $28 million pledged in connection with the sale and leaseback of Perry by OE.

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

Collateral and Contingent-Related Features

In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE'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 FE and its subsidiaries have margining provisions that require posting of collateral.Based on FES' power portfolio exposure as ofSeptember 30, 2013, FES has posted collateral of$150 millionand AE supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of$16 million.

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These credit-risk-related contingent features stipulate that if the subsidiary 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, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries.The following table discloses the additional credit contingent contractual obligations as ofSeptember 30, 2013:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	440	$	6	$	55	$	501
BB+/Ba1 Credit Ratings	$	484	$	6	$	55	$	545
Full impact of credit contingent contractual obligations	$	755	$	58	$	90	$	903

Excluded from the preceding chart is the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Services Segment.As ofSeptember 30, 2013, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$77 millionand$2 million, respectively.

Other Commitments and Contingencies

FirstEnergy is a guarantor under a syndicated three-year senior secured term loan facility due October 18, 2015, under which Global Holding borrowed $350 million. Proceeds from the loan were used to repay Signal Peak's and Global Rail's maturing$350 millionsyndicated two-year senior secured term loan facility. In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, have also provided their joint and several guaranties of the obligations of Global Holding under the new facility.

In connection with the new facility,69.99%of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective33-1/3%membership interests in Global Holding, are pledged to the lenders under the new facility as collateral.

FirstEnergy, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed to use their best efforts to refinance the new facility no later than July 20, 2015, which reflects the terms of an amendment dated August 14, 2013, on a non-recourse basis so that FirstEnergy's guaranty can be terminated and/or released.If that refinancing does not occur, FirstEnergy may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the new facility in full.In lieu of providing such funding, the co-owners, at FirstEnergy's option, may provide their several guaranties of Global Holding's obligations under the facility.FirstEnergy receives a fee for providing its guaranty, payable semiannually, which accrued at a rate of4%through December 31, 2012, and accrues at a rate of5%from January 1, 2013 through October 18, 2015, which amends the rate in the prior agreement, in each case based upon the average daily outstanding aggregate commitments under the facility for such semiannual period.

OFF-BALANCE SHEET ARRANGEMENTS

FES and certain of the Ohio Companies have obligations that are not included on their Consolidated Balance Sheets related to the Perry Unit 1, Beaver Valley Unit 2, and 2007 Bruce Mansfield Plant sale and leaseback arrangements, which are satisfied through operating lease payments. The total present value of these sale and leaseback operating lease commitments, net of trust investments, was $1.2 billion as of September 30, 2013. From time to time FirstEnergy and these companies enter into discussions with certain parties to the arrangements regarding acquisition of owner participant and other interests. However, FirstEnergy cannot provide assurance that any such acquisitions will occur on satisfactory terms or at all.

During the second quarter of 2013, in connection with the Perry sale and leaseback arrangement, OE provided notice to return the leased interests in the plant to the owner participants (representing an aggregate of approximately 103 MWs of the 1,268 MWs of total capacity of the Perry Plant) at the expiration of the lease (May 2016) in lieu of extending the lease or buying the interest at the then appraised FMV.

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.

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Commodity Price Risk

FirstEnergy is exposed to financial risks resulting from fluctuating commodity prices, including prices for electricity, natural gas, coal and energy transmission. FirstEnergy's Risk Management Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.

The valuation of derivative contracts is based on observable market information to the extent that such information is available. In 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 9, Fair Value Measurements, of the Combined Notes to Consolidated Financial Statements). Sources of information for the valuation of commodity derivative contracts assets and liabilities as of September 30, 2013 are summarized by year in the following table:

Source of Information- Fair Value by Contract Year	2013			2014			2015			2016			2017			Thereafter			Total
	(In millions)
Prices actively quoted(1)	$	(2	)	$	1		$	—		$	—		$	—		$	—		$	(1	)
Other external sources(2)	(8		)	(31		)	(35		)	(33		)	—			—			(107		)
Prices based on models	(2		)	(5		)	—			—			(23		)	(160		)	(190		)
Total(3)	$	(12	)	$	(35	)	$	(35	)	$	(33	)	$	(23	)	$	(160	)	$	(298	)

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

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

⁽³⁾  Includes $(376) million in non-hedge derivative contracts that are primarily related to NUG and LCAPP contracts. NUG and LCAPP 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 September 30, 2013, a 10% adverse change in commodity prices would decrease net income by approximately $27 million during the next 12 months.

Equity Price Risk

As of September 30, 2013, the FirstEnergy pension plan assets were approximately 24% in equity securities, 42% in fixed income securities, 25% in absolute return strategies, 6% in real estate, 1% in private equity and 2% in cash and short-term securities. 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 nine months ended September 30, 2013, FirstEnergy made no contributions to its qualified pension plans. See Note 5, Pensions and Other Postemployment Benefits, of the Combined Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension plans and OPEB. Through September 30, 2013, FirstEnergy's pension plan assets earned approximately (1)% as compared to an expected return on plan assets of 7.75%.

NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of September 30, 2013, approximately 75% of the funds were invested in fixed income securities, 21% of the funds were invested in equity securities and 4% 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 $1,630 million, $461 million and $80 million for fixed income securities, equity securities and short-term investments, respectively, as of September 30, 2013, excluding $12 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $46 million reduction in fair value as of September 30, 2013. Certain FirstEnergy subsidiaries recognize in earnings the unrealized losses on AFS securities held in its 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 nine months ended September 30, 2013, FirstEnergy contributed approximately $5 million to the NDT. On June 18, 2013, FE submitted a revised $125 million parental guaranty for NRC review relating to a shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry. On this date, FE also submitted to the NRC a revised $11 million parental guaranty in support of the decommissioning of the spent fuel storage facilities located at its Davis-Besse and Perry nuclear facilities.

Interest Rate Risk

FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year. A primary factor contributing to these actuarial gains and losses are changes in the discount rates used to value pension and OPEB obligations as of the measurement date of December 31 and the difference between expected and actual returns on the plans' assets. While FirstEnergy is unable to determine or project the mark-to-market adjustment that may be recorded as of December

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31, 2013, based on current market indications FirstEnergy expects a pre-tax mark-to-market gain (net of amounts capitalized) to be in the range of approximately $50 million and $150 million in the aggregate.

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 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's portfolio of energy contracts has a current 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.

As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates.In addition, if FES, AE Supply or any of their subsidiaries were to engage in the construction of significant new generation facilities in any of those states, they would also be subject to state siting authority.

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 that are overseen by the MDPSC and a third party monitor.Although settlements with respect to residential SOS for PE customers expired on December 31, 2012, by statute, service continues in the same manner unless changed by order of the MDPSC.The settlement provisions relating to non-residential SOS have also expired, however, 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.PE's initial plan submitted in compliance with the statute was approved in 2009 and covered 2009-2011, the first three years of the statutory period.Expenditures were originally estimated to be approximately$101 millionfor the PE programs for the entire period of 2009-2015.Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, on August 31, 2011, PE filed a new comprehensive plan for the second three year period, 2012-2014, that includes additional and improved programs.The 2012-2014 plan is expected to cost approximately$66 millionout

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of the original$101 millionestimate for the entire EmPOWER program.On December 22, 2011, the MDPSC issued an order approving PE's second plan with various modifications and follow-up assignments.PE continues to recover program costs subject to afive-year amortization.Maryland law only allows for the utility to recover lost distribution revenue attributable to 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.

Pursuant to a bill passed by the Maryland legislature in 2011, the MDPSC adopted rules, effective May 28, 2012, 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 MDPSC will be required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day, per violation.The new rules set utility-specific SAIDI and SAIFI targets for 2012-2015; prescribe detailed tree-trimming requirements, outage restoration and downed wire response deadlines; and impose other reliability and customer satisfaction requirements.PE has advised the MDPSC that compliance with the new rules is expected to increase costs by approximately$106 millionover the period 2012-2015.On April 1, 2013, the Maryland electric utilities, including PE, filed their first annual reports on compliance with the new rules.The MDPSC conducted a hearing on August 20, 2013 to discuss the reports, after which an order was issued on September 3, 2013, which accepted PE's filing and the operational changes proposed therein.

Following a "derecho" storm through the region on June 29, 2012, the MDPSC convened a new proceeding to consider matters relating to the electric utilities' performance in responding to the storm.Hearings on the matter were conducted in September 2012.Concurrently, Maryland's governor convened a special panel to examine possible ways to improve the resilience of the electric distribution system.On October 3, 2012, that panel issued a report calling for various measures including: acceleration and expansion of some of the requirements contained in the reliability standards which had become final on May 28, 2012; for selective increased investment in system hardening; for creation of separate recovery mechanisms for the costs of those changes and investments; and penalties or bonuses on returns earned by the utilities based on their reliability performance.On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the utilities to submit several reports over a series of months, relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations.The order further requires the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information.PE has responded to the requirements in the order consistent with the schedule set forth therein.PE's final filing on September 3, 2013, discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 27 Order, and projected that it would expect to make approximately$2.7 billionin infrastructure investments over15years to attempt to achieve the quickest level of response for the largest storm projected in the February 27 Order.The MDPSC has ordered that certain reports of its Staff relating to these matters be provided by May 1, 2014, and otherwise, has not issued a schedule for further proceedings in this matter.

NEW JERSEY

JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service.The supply for BGS, which is comprised oftwocomponents, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU.OneBGS 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.

On September 7, 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, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that JCP&L 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.The rate case petition was filed on November 30, 2012.In the filing, JCP&L requested approval to increase its revenues by approximately$31.5 millionand reserved the right to update the filing to include costs associated with the impact of Hurricane Sandy.The NJBPU has transmitted the case to the New Jersey Office of Administrative Law for further proceedings and an ALJ has been assigned.On February 22, 2013, JCP&L updated its filing to request recovery of$603 millionof distribution-related Hurricane Sandy restoration costs, resulting in increasing the total revenues requested to approximately$112 million.On June 14, 2013, JCP&L further updated its filing to: 1) include the impact of a depreciation study which had been directed by the NJBPU; 2) remove costs associated with 2012 major storms, consistent with the NJBPU orders establishing a generic proceeding to review 2011 and 2012 major storm costs (discussed below); and 3) reflect other revisions to JCP&L's filing.That filing represented an increase of approximately$20.6 millionover the revenues produced by existing base rates.Testimony has also been filed in the matter by the Division of Rate Counsel and several other intervening parties in opposition to the base rate increase JCP&L requested. Specifically, the testimony of the Division of Rate Counsel's witnesses recommended that revenues produced by JCP&L's base rates for electric service be reduced by approximately$202.8 million(such amount did not address the revenue requirements associated with major storm events of 2011 and 2012, which are subject to review in the generic proceeding).JCP&L filed rebuttal

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testimony in response to the testimony of other parties on August 7, 2013. Hearings in the rate case have commenced and are scheduled to continue through mid-November.

On March 20, 2013, the NJBPU ordered that a generic proceeding be established to investigate the prudence of costs incurred by all New Jersey utilities for service restoration efforts associated with the major storm events of 2011 and 2012.The Order provided that if any utility had already filed a proceeding for recovery of such storm costs, to the extent the amount of approved recovery had not yet been determined, the prudence of such costs would be reviewed in the generic proceeding.On May 31, 2013, the NJBPU clarified its earlier order to indicate that the 2011 major storm costs would be reviewed expeditiously in the generic proceeding with the goal of maintaining the base rate case schedule established by the ALJ where recovery of such costs would be addressed.The NJBPU further indicated in the May 31 clarification that it would review the 2012 major storm costs in the generic proceeding and the recovery of such costs would be considered through a Phase II in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding.On June 21, 2013, consistent with NJBPU's orders, JCP&L filed the detailed report in support of recovery of major storm costs with the NJBPU.On October 23, 2013, a prehearing order was issued and established that evidentiary hearings in this proceeding will be held in January 2014. JCP&L intends to vigorously pursue its position in the base rate case and full recovery of the costs associated with the major storm events of 2011 and 2012 but we cannot predict the outcome of these proceedings.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held in September 2011 to solicit comments regarding the state of preparedness and responsiveness of New Jersey's EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011.Additionally, the NJBPU accepted written comments through October 28, 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 consultant's report was submitted to and subsequently accepted by the NJBPU on September 12, 2012.JCP&L submitted written comments on the report.On January 24, 2013, based upon recommendations in its consultant's report, the NJBPU ordered the New Jersey EDCs to take a number of specific actions to improve their preparedness and responses to major storms.The order includes specific deadlines for implementation of measures with respect to preparedness efforts, communications, restoration and response, post event and underlying infrastructure issues.On May 31, 2013, the NJBPU ordered that the New Jersey EDCs implement a series of new communications enhancements intended to develop more effective communications among EDCs, municipal officials, customers and the NJBPU during extreme weather events and other expected periods of extended service interruptions.The new requirements include making information regarding estimated times of restoration available on the EDC's web sites and through other technological expedients.JCP&L is implementing the required measures consistent with the schedule set out in the above NJBPU's orders.

OHIO

The Ohio Companies primarily operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include:

• Generation supplied through a CBP;

• 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 thefive-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 million, subject to the outcome of certain PJM proceedings.The Ohio Companies have also agreed to establish a$12 millionfund 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 fortwoyears.The ESP 3 Application was approved by the PUCO on July 18, 2012.Several parties timely filed applications for rehearing.The PUCO issued an Entry on Rehearing on January 30, 2013 denying all applications for rehearing.Notices of appeal to the Supreme Court of Ohio were filed bytwoparties in the case, Northeast Ohio Public Energy Council and the ELPC.The matter has not yet been scheduled for oral argument.

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As approved, the ESP 3 plan continues certain provisions from the current ESP including:

• Continuing the current base distribution rate freeze through May 31, 2016;

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

• A6%generation rate 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);

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

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

As approved, the ESP 3 plan will provide additional provisions, including:

• Securing generation supply for a longer period of time by conducting an auction for athree-year period rather than aone-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

• Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

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.The Ohio Companies were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.On May 15, 2013, the Ohio Companies filed their 2012 Status Update Report in which they indicated compliance with 2012 statutory energy efficiency and peak demand reduction benchmarks.

In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.Estimated costs for thethreeOhio Companies' plans total approximately$250 millionover the three-year period, which is expected to be recovered in rates to the extent approved by the PUCO.Hearings were held with the PUCO in October 2012.On March 20, 2013, the PUCO approved the three-year portfolio plan for 2013-2015.Applications for rehearing were filed by the Ohio Companies and several other parties on April 19, 2013.The Ohio Companies filed their request for rehearing primarily to challenge the PUCO's decision to mandate that they offer planned energy efficiency resources into PJM's base residual auction.On May 15, 2013, the PUCO granted the applications for rehearing for the sole purpose of further consideration of the matter.On July 17, 2013, the PUCO issued an entry on rehearing denying the Ohio Companies' application for rehearing, in part, but authorizing the Ohio Companies' to receive20%of any revenues obtained from bidding energy efficiency and demand response reserves into the PJM auction.The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to the extent that such costs or penalties are prudently incurred.On August 16, 2013, ELPC and OCC filed applications for rehearing under the basis that the PUCO's authorization for the Ohio Companies to share in the PJM revenues was unlawful.The PUCO granted rehearing on September 11, 2013 for the sole purpose of further consideration of the issue.

On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with and are not supported by statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal. The Ohio Companies' response was filed on November 4, 2013.

Additionally, under SB221, electric utilities and electric service companies in Ohio are required to serve part of their load from renewable energy resources measured by an annually increasing percentage amount.In August and October 2009 and in August 2010, the Ohio Companies conducted RFPs to secure RECs.The RECs acquired through thesethreeRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conductedtwoRFP processes to obtain RECs to meet the statutory benchmarks for 2011 and contribute toward meeting the benchmark for future years.On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies will recover the costs of acquiring these RECs.The PUCO selected auditors to perform a financial and management audit, and final audit reports were filed with the PUCO on August 15, 2012.While generally supportive of the Ohio Companies' approach to procurement of RECs, the management/performance auditor recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state all renewable obligations that the auditor characterized as excessive.A hearing for this matter commenced on February 19, 2013, and concluded on February 25, 2013.The PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of renewable energy credits to meet statutory mandates in all instances except for part of the purchases arising from one auction and directing the Ohio Companies to credit non-shopping customers in the amount of$43.3 million, plus interest, with such crediting to commence within60days following the issuance of a final appealable order on the basis that the Ohio Companies did not prove such purchases were prudent.The Ohio Companies, along with other parties, timely filed applications for rehearing on September 6, 2013. On September 18, 2013, the PUCO issued an entry on rehearing granting rehearing solely for the purpose of further consideration of the matters specified therein.

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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 achieved their in-state solar compliance requirements for 2012.The Ohio Companies also held a short-term RFP process to obtain all state SRECs and both in-state and all state non-solar RECs to help meet the statutory benchmarks for 2012.The Companies recently reported that all of the Ohio Companies met their annual renewable energy resource requirements for reporting year 2012.The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.

The PUCO instituted a statewide investigation on December 12, 2012 to evaluate the vitality of the competitive retail electric service market in Ohio.The PUCO provided interested stakeholders the opportunity to provide comments ontwenty-twoquestions.The questions posed are categorized as market design and corporate separation.The Ohio Companies timely filed their comments on March 1, 2013, and filed reply comments on April 5, 2013.The PUCO has scheduled a series of workshops for the remainder of 2013, the first of which commenced on July 9, 2013.The Ohio Companies cannot predict the outcome of this investigation.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expired on May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs 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 DSPs 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.The PPUC entered an opinion and order on August 16, 2012, which primarily resolved those issues related to procurement and rate design, but required the submission of revised proposals regarding the retail market enhancement programs.The Pennsylvania Companies filed revised proposals on the retail market enhancements on November 14, 2012.A final order was entered on February 15, 2013, which addressed minor changes to the Pennsylvania Companies' revised enhancement proposals and ordered two choices for cost recovery of those programs.On February 28, 2013, the Pennsylvania Companies filed a petition to amend the August 16, 2012, order related to the description of how the hourly industrial product is to be priced.On April 4, 2013, the PPUC entered a Final Order postponing the implementation ofoneof the retail market enhancements.On March 20, 2013, answers supporting and opposing the Pennsylvania Companies' February 28 petition were filed by several parties.On July 16, 2013, the PPUC entered an order granting the Pennsylvania Companies' February 28, 2013 petition, thereby amending its August 16, 2012 order and clarifying the description of the hourly industrial product pricing. The Pennsylvania Companies are actively implementing their DSPs as of June 1, 2013. On November 4, 2013, the Pennsylvania Companies filed a default service plan that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2015 through May 31, 2017. The Pennsylvania Companies proposed programs call for quarterly descending clock auctions to procure 3, 12, 24, and 48-month energy contracts, as well as, one RFP seeking 2-year contracts to secure solar renewable energy credits for ME, PN, and Penn. The Pennsylvania Companies expect a decision from the PPUC within nine months.

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 refunded those amounts to customers over a29-month period that began in January of 2011.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's and PN's TSC riders.The Pennsylvania Supreme Court denied ME's and PN's Petition for Allowance of Appeal on February 28, 2012, and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari on October 9, 2012.On July 13, 2011, ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania for the purpose of obtaining an order that would enjoin enforcement of the PPUC and Pennsylvania court orders under a theory of federal preemption on the question of retail rate recovery of the marginal transmission loss charges.Proceedings in the U.S. District Court effectively were suspended until conclusion of the proceedings before the United States Supreme Court.Pursuant to procedural orders issued by U.S. District Court Judge Gardner, on December 21, 2012, the PPUC submitted its motion to dismiss the U.S. District Court proceedings.ME and PN submitted their answers on January 9, 2013, and subsequent pleadings were submitted by the PPUC, ME and PN.Oral arguments on the PPUC motion to dismiss took place on May 20, 2013.On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss. On October 29, 2013, ME and PN filed a notice of appeal in the U.S. Court of Appeals for the Third Circuit with respect to the U.S. District Court's decision.As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately$254 million(pre-tax) in the quarter ended September 30, 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. FirstEnergy continues to believe in the merits of its case.

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.

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 on utilities that fail to achieve the required reductions in consumption and peak demand.The Pennsylvania Companies submitted an interim 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 did not.WP could be subject to a statutory penalty of up to$20 millionand is unable to predict the outcome of this matter.On July 15, 2013, the Pennsylvania Companies filed their preliminary energy efficiency and demand reduction results for the period ending May 31, 2013, indicating that all Pennsylvania Companies are expected to meet their statutory obligations.The Pennsylvania Companies are expected to report their final energy efficiency and demand reduction results for the period ending May 31, 2013, by November 15, 2013.

Pursuant to Act 129, the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs.The PPUC found the energy efficiency programs to be cost effective and in an Order entered on August 3, 2012, the PPUC directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016.The PPUC has deferred ruling on the need to create peak demand reduction targets until it receives more information from the EE&C statewide evaluator.The Pennsylvania Companies filed their Phase II plans and supporting testimony in November 2012.On January 16, 2013, the Pennsylvania Companies reached a settlement with all but one party on all but one issue.The settlement provides for the Pennsylvania Companies to meet with interested parties to discuss ways to expand upon the EE&C programs and incorporate any such enhancements after the plans are approved, provided that these enhancements will not jeopardize the Pennsylvania Companies' compliance with their required targets or exceed the statutory spending caps.On February 6, 2013, the Pennsylvania Companies filed revised Phase II EE&C Plans to conform the plans to the terms of the settlement.Total costs of these plans are expected to be approximately$234 million.All such costs are expected to be recoverable through the Pennsylvania Companies reconcilable Phase II EE&C Plan C riders.The remaining issue, raised by a natural gas company, involved the recommendation that the Pennsylvania Companies include in their plans incentives for natural gas space and water heating appliances.On March 14, 2013 the PPUC approved the 2013-2016 EE&C plans of the Pennsylvania Companies, adopting the settlement, and rejecting the natural gas companies recommendations.

In addition, Act 129 required utilities to file a SMIP with the PPUC.On December 31, 2012, the Pennsylvania Companies filed their Smart Meter Deployment Plan.The Deployment Plan requests deployment of approximately98.5%of the smart meters to be installed over the period 2013 to 2019, and the remaining meters in difficult to reach locations to be installed by 2022, with an estimated life cycle cost of about$1.25 billion.Such costs are expected to be recovered through the Pennsylvania Companies' PPUC-approved Riders SMT-C.Evidentiary hearings have been held and briefs were submitted by the Pennsylvania Companies and the Office of Consumer Advocate.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market would 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 onelevendirected 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.A final order was issued on February 15, 2013 providing recommendations on the entities to provide default service, the products to be offered, billing options, customer education, and licensing fees and assessments, among other items.Subsequently, the PPUC establishedfiveworkgroups andonecomment proceeding in order to seek resolution of certain matters and to clarify certain obligations that arose from that order.

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 electricity 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 the Pennsylvania Companies and FES on March 27, 2012.If implemented these rules could require a significant change in the ways FES and the Pennsylvania Companies 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 the proposed rulemaking on April 26, 2012, 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.The House Consumer Affairs Committee of the Pennsylvania

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General Assembly also sent a letter to the Independent Regulatory Review Commission on July 12, 2012, noting its opposition to the proposed regulations as modified.

WEST VIRGINIA

MP and PE currently operate under a Joint Stipulation and Agreement of Settlement reached with the other parties and approved by the WVPSC in June 2010 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.

In February 2011, MP and PE filed a petition with the WVPSC seeking an order declaring that MP owns all RECs associated with the 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, opposed the petition.On November 22, 2011, the WVPSC granted ownership of all RECs produced by the facilities to MP, and held that an electric utility that purchases electric energy and capacity under an electric power purchase agreement with a Qualifying Facility under PURPA owns the RECs associated with that purchase.The West Virginia Supreme Court upheld the WVPSC's decision.The City of New Martinsville and Morgantown Energy Associates filed petitions at FERC alleging the WVPSC order violated PURPA and requested that FERC initiate an enforcement action.On April 24, 2012, FERC issued an order declining to act on the petitions and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court.MP and PE filed for rehearing of FERC's order, which was denied on September 20, 2012.The City of New Martinsville filed a complaint in the U.S. District Court for the Southern District of West Virginia on June 1, 2012, alleging that the WVPSC order violates PURPA.Morgantown Energy Associates has joined in filing a similar complaint and requesting damages in the same U.S. District Court.MP and PE filed for judgment on the pleadings in both cases on January 25, 2013.The WVPSC filed a motion to dismiss on June 28, 2013.On September 30, 2013, the District Court ruled in favor of MP and PE and the WVPSC and dismissed the proceedings with prejudice.

The WVPSC opened a general investigation into the June 29, 2012, derecho windstorm with data requests for all utilities.A public meeting for presentations on utility responses and restoration efforts was held on October 22, 2012 and two public input hearings have been held.The WVPSC issued an Order in this matter on January 23, 2013 closing the proceeding and directing electric utilities to file a vegetation management plan withinsix monthsand to propose a cost recovery mechanism.This Order also requires MP and PE to file a status report regarding improvements to their storm response procedures by the same date.On July 23, 2013, MP and PE filed their vegetation management plans, which provided for recovery of costs through a surcharge mechanism.On October 3, 2013, the WVPSC issued a procedural schedule for the vegetation management plan proceeding and scheduled a hearing for December 3, 2013.

MP and PE filed their Resource Plan with the WVPSC in August 2012 detailing both supply and demand forecasts and noting a substantial capacity deficiency.MP and PE have filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposes a net ownership transfer of1,476MW of coal-fired generation capacity to MP.The proposed transfer would involve MP's acquisition of the remaining ownership of the Harrison Power Station from AE Supply and the sale of MP's minority interest in the Pleasants Power Station to AE Supply.The proposed transfer would implement a cost-effective plan to assist MP in meeting its energy and capacity obligations with its own generation resources, eliminating the need to make unhedged electricity and capacity purchases from the spot market, which is expected to result in greater rate stability for MP's customers.The plan is expected to remedy MP's capacity and energy shortfalls, which are projected to worsen due to a projected increase in annual load growth of approximately1.4%.MP and PE will file a base rate case no later thansix monthsfrom the completion of the transaction.On February 11, 2013, the WVPSC issued an order adopting a procedural schedule for this matter and testimony and briefing has followed.MP and PE also filed with FERC for authorization to effect these transfers and on April 23, 2013, FERC issued an order authorizing the transfers.MP's application for FERC authorization to effect the financing was approved on May 13, 2013.Hearings were held at the WVPSC in late May and briefs and reply briefs have been submitted.A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013.On October 7, 2013, WVPSC issued an order authorizing the transaction, with certain conditions and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately$330 millionin the fourth quarter of 2013 to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base.Additionally, MP recognized a regulatory liability of approximately$23 millionin the fourth quarter of 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station. The transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. Currently, the $1.1 billion net consideration was financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million.

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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, FG, FENOC, ATSI and TrAIL.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 toeightregional 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.Any 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.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities.While FirstEnergy and other parties advocated for a traditional "beneficiary pays" (or usage based) 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.On August 6, 2009, 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 LSEs in PJM bearing the majority of the costs.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 (or socialized) 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 and on March 22, 2013, FERC denied rehearing.On March 29, 2013, FirstEnergy filed its Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated for briefing and disposition before that court. Briefing commenced on September 11, 2013, and is expected to continue into early 2014.Thereafter, the case will be scheduled for oral argument, with a decision currently expected in 2014.

Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order.To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of50%beneficiary pays and50%postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing.On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing.On March 22, 2013, FERC granted final acceptance of the hybrid method.Certain parties have sought rehearing of parts of FERC's March 22, 2013 order.These requests for rehearing are pending before FERC.On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the New York Independent System Operator region and; (2) the PJM region and the FERC-jurisdictional members of the Southeastern Regional Transmission Planning region.These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region.On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000.The July 10, 2013 filings are pending before FERC.

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”

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transmission project continues to be disputed; the details of the dispute are discussed below under "MISO Multi-Value Project Rule Proposal."In addition, FERC denied recovery of certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation issues by means of ATSI's transmission rate totaling approximately$78.8 millionuntil 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.On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve certain of the exit fee and transmission cost allocation issues that are outstanding with regard to ATSI's transmission rate revisions related to ATSI's move into PJM.On September 19, 2013, FERC rejected that settlement stating ATSI had not shown why its tariff changes are just and reasonable. FERC further stated, consistent with its initial May 31, 2011 ruling on this issue that its September 19, 2013 order is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the costs that are sought to be recovered in ATSI's transmission rates.On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

In the May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM could be charged to transmission customers in the ATSI zone.ATSI sought rehearing of the question of whether the ATSI zone should pay these legacy RTEP charges and, on September 20, 2012, FERC denied ATSI's request for rehearing.On November 19, 2012, ATSI filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit of FERC's ruling on the "legacy RTEP" issue, and ATSI's initial brief was filed with that court on April 11, 2013.FERC filed its brief on June 25, 2013, and FirstEnergy filed its reply brief on August 9, 2013, and final reply brief on August 28, 2013.FERC filed its final brief on August 30, 2013. The court has scheduled oral argument for December 11, 2013, and a decision is expected in the second quarter of 2014.

The 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 project that was approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would be allocated to and charged to ATSI.MISO estimated that approximately$16 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction.In addition, the MISO's MVP tariffs could assess costs on PJM loads that purchase energy that has flowed over the transmission systems into the MISO.

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.FirstEnergy asserts legal, factual and policy arguments.To date, FERC has responded in a series of orders that may require ATSI to absorb the charges for the Michigan Thumb Project pending the outcome of further regulatory proceedings and appeals.These further proceedings can be divided into two tracks: litigation related to MISO's generic MVP cost allocation proposal; and litigation related to MISO's "Schedule 39" tariff that purports to charge the MVP costs to ATSI.

Regarding the first litigation track, in 2010 and 2011 FERC issued orders that approved the MISO proposal.On October 31, 2011, FirstEnergy filed a Petition of Review of those 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 appeals were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit.Briefs were filed in late 2012 and early 2013, and the court heard oral arguments on April 10, 2013.On June 7, 2013, the Seventh Circuit issued an order that ratified FERC's acceptance of the MISO's proposed MVP tariff.On October 7, 2013, several parties, including FirstEnergy, filed appeals of the Seventh Circuit's decision with the U.S. Supreme Court.FirstEnergy continues to evaluate the Seventh Circuit's order and its substantive and procedural options on other holdings in the opinion.

Regarding the second litigation track, in February 2012, FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI.FERC 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.The hearings took place in April 2013, and on July 16, 2013 the ALJ issued an Initial Decision ruling that ATSI must pay the "Schedule 39" MVP costs.FirstEnergy and other parties submitted Briefs on Exceptions on August 15, 2013.The MISO and other parties filed Briefs Opposing Exceptions on September 4, 2013.The matter is pending before FERC for final decision.

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

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 U.S. Court of Appeals for the Ninth Circuit in several pending

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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 had previously remandedoneof those proceedings to FERC, which dismissed the claims of the California Parties in May 2011, and affirmed the dismissal in June 2012.On June 20, 2012, the California Parties appealed FERC's decision back to the Ninth Circuit.Briefing was completed before the Ninth Circuit on October 23, 2013.The timing of further action by the Ninth Circuit is unknown.

In another proceeding, in June 2009, the California Attorney General, on behalf of certain California parties, filed another complaint with FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during 2000 and 2001.The above-noted transactions with CDWR are the basis for including AE Supply in this complaint.AE Supply filed a motion to dismiss, which was granted by FERC in May 2011, and affirmed by FERC in June 2012.The California Attorney General has appealed FERC's dismissal of its complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and stayed the proceedings pending further order.

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 was proposed to be comprised of a765kV transmission line 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.On August 24, 2012, the PJM Board of Managers canceled the PATH project, which it had suspended in February 2011.As a result, approximately$62 millionand approximately$59 millionin costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery.On September 28, 2012, those companies requested authorization from FERC to recover the costs with a proposed return on equity of10.9%(10.4%base plus0.5%RTO membership) from PJM customers over the nextfiveyears.Several parties protested the request.On November 30, 2012, FERC issued an order denying the0.5%return on equity adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012 subject to settlement judge procedures and hearing if the parties do not agree to a settlement.The issues subject to settlement include the prudence of the costs, the base return on equity and the period of recovery.PATH-Allegheny and PATH-WV are currently engaged in settlement discussions with the other parties.Depending on the outcome of a possible settlement or hearing, if settlement is not achieved, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

PATH-Allegheny and PATH-WV have requested rehearing of FERC's denial of the0.5%return on equity adder for RTO membership; that request for rehearing remains pending before FERC.In addition, FERC has consolidated for settlement judge procedures and hearing purposes three formal challenges to the PATH formula rate annual updates submitted to FERC in June 2010, June 2011 and June 2012, with the September 28, 2012 filing for recovery of costs associated with the cancellation of the PATH project.FirstEnergy cannot predict the outcome of these matters or estimate the possible loss or range of loss.

Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FG.FG 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, FG initiated the ILP relicensing process by filing its notice of intent to relicense and related documents in the license docket.

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.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.FG believes it is entitled to a statutory “incumbent preference” under Section 15 and that it ultimately should prevail in these proceedings.Nevertheless, the Seneca Nation's pleadings reflect the Nation's apparent intent to obtain the license for the facility, and to assume ownership and operation of the facility as contemplated by the statute.

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 January 7, 2013, FirstEnergy and the Seneca Nation submitted their respective reports for the 2012 study season.On January 31 and February 1, 2013, respectively, the Seneca Nation and FirstEnergy each submitted their respective proposed study plans for the 2013 study season.On March 4, 2013, the Seneca Nation and other parties submitted comments regarding FirstEnergy's proposed study plans.In its comments, the Seneca Nation alleges that FirstEnergy does not hold the real estate rights necessary

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to operate a hydroelectric project in circumstances where there is flowage over the Seneca Nation's lands.On April 3, 2013, FirstEnergy filed its response to these and other assertions by the Seneca Nation and its allied parties.On May 3, 2013, FERC's Director of the Office of Energy Projects issued FERC Staff's study plan determinations for the 2013 study year.The Director determined that water level fluctuations in the lower reservoir due to hydroelectric project operations have no discernible effect on reservoir lands or environmental resources.This finding is expected to strengthen FirstEnergy's position that the project boundary should be defined to exclude the U.S. Army Corps of Engineers dam and reservoir facilities.FERC Staff's determinations also largely adopted FirstEnergy's position and arguments as to the proper scope of environmental studies for the 2013 study season.The study processes will extend through approximately November 2013.

On July 3, 2013, FirstEnergy and the Seneca Nation each submitted "Preliminary License Proposals" in the relicensing dockets.These submissions are intended to be non-binding indications of types of project upgrades that may be proposed in the parties' respective final licensing applications, as well as an indication of the scope and direction of the parties' plans for the upcoming final licensing applications.On October 1, 2013, FERC staff provided comments on FirstEnergy's and the Seneca Nation's Preliminary Licensing Proposals, including identifying deficiencies for the applicants to address in their applications. FirstEnergy and the Seneca Nation each are required to submit their application for the project license by December 2, 2013.

Hydroelectric Asset Sale

On September 4, 2013, certain of FirstEnergy’s subsidiaries submitted filings with FERC for authorization to sellelevenhydroelectric power plant projects to subsidiaries of Harbor Hydro Holdings, LLC (Harbor Hydro), a subsidiary of LS Power Equity Partners II, LP (LS Power) for approximately$400 million.Theelevenhydroelectric projects are: the Seneca Pumped Storage Project, Allegheny Lock & Dam No. 5, Allegheny Lock & Dam No. 6, the Lake Lynn Project, the Millville Hydro Project, the Dam No. 4 Project, the Dam No. 5 Project, and four additional projects located in Shenandoah, Front Royal and Luray, Virginia.Theelevenprojects have a combined generating capacity of approximately527MW.Resolution of the potential competing hydro license application of the Seneca Nation for the Seneca Pumped Storage Project and other claims and matters is a condition to closing of the proposed asset sale.FirstEnergy’s submittals for regulatory authorization include a request for authorization to transfer the hydroelectric licenses under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the hydroelectric projects under Part II of the FPA.On September 25, 2013, the Seneca Nation submitted a pleading in the Part II regulatory proceeding wherein the Seneca Nation reiterated the real estate and other claims that the Seneca Nation has advanced in the Seneca Pumped Storage Project relicensing proceeding. On October 18, 2013, the Seneca Nation reiterated its real estate claims in comments on the Part I application to transfer the license for the Seneca Pumped Storage Project.However, the Seneca Nation noted in both sets of comments that it does not oppose the proposed sale or license transfer “at this time.” On November 1, 2013, FERC issued an order granting the FPA Part II authorization to transfer the hydro assets (the license transfer application remains pending before FERC).Additional filings have been submitted to FERC for the purpose of implementing the transaction once regulatory approval is obtained. The VSCC also must approve the sale for the assets that are located in Virginia, and the application for such approval was submitted on September 19, 2013.Once the regulatory authorizations are granted and the other closing conditions are satisfied, FirstEnergy expects to close this asset sale transaction in the fourth quarter of 2013. See Note 16, Discontinued Operations and Assets Held for Sale for additional information regarding the potential asset sales.

MISO Capacity Portability

On June 11, 2012, 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 and the 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.FirstEnergy submitted comments and reply comments in August 2012.In the fall of 2012, FirstEnergy participated in certain stakeholder meetings to review various proposals advanced by MISO.Although none of MISO's proposals attracted significant stakeholder support, on January 3, 2013, MISO filed a pleading with FERC that renewed many of the arguments advanced in prior MISO filings and asked FERC to take expedited action to address MISO's allegations.FirstEnergy and other parties subsequently submitted filings arguing that MISO's concerns largely are without foundation and suggesting that FERC order that the remaining concerns be addressed in the existing stakeholder process that is described in the PJM/MISO Joint Operating Agreement.On April 2, 2013, FERC issued an order directing MISO and PJM to make presentations to FERC regarding ongoing regional efforts to address whether barriers to transfer capability exist between the MISO and PJM regions and the actions the FERC should take to address any such barriers.The RTOs presented their respective positions to FERC on June 20, 2013 and provided additional information regarding their stakeholder prioritization survey, in response to a FERC request on June 27, 2013.On September 26, 2013, the RTOs jointly submitted an informational filing providing a description of and schedule for their Joint and Common Market initiatives. FERC has not acted on the presentations, and the RTOs and affected parties are working to address the MISO's proposal in stakeholder proceedings.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 a negative impact on the prices at which those auctions would clear.

MOPR Reform

On December 7, 2012, PJM filed amendments to its tariff to revise the MOPR used in the RPM. PJM revised the MOPR to add two broad, categorical exemptions, eliminate an existing exemption, and to limit the applicability of the MOPR to certain capacity resources.The filing also included related and conforming changes to the RPM posting requirements and to those provisions

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describing the role of the Independent Market Monitor for the PJM Region.On May 2, 2013, FERC issued an order in large part accepting PJM's proposed reform of the MOPR, including the proposed exemptions and applicability but also requiring PJM to commit to future review and, if necessary, additional revisions to the MOPR to accommodate changing market conditions.On June 3, 2013, FirstEnergy submitted a request for rehearing of FERC's May 2, 2013 order.In its rehearing request, FirstEnergy referenced the results of the May 2013 PJM RPM capacity auction, and the data that is available in the public domain about the reasons for the unexpectedly low "rest-of-RTO" clearing price of $59 per MW-day, as supporting its contention that the MOPR reform depressed prices as predicted in FirstEnergy's December 28, 2012 and January 25, 2013 comments.FirstEnergy's request for rehearing is pending before FERC.

Synchronous Condensers

On December 20, 2012, FERC approved the transfer by FG to ATSI of certain deactivated generation assets associated with Eastlake Units 1 through 5 and Lakeshore Unit 18 to facilitate their conversion to synchronous condensers to provide voltage support on the ATSI transmission system.The transfer price of the assets was approximately$21.5 millionand the estimated conversion cost was approximately$60 million.The transfer of Eastlake Units 4 and 5 was completed on January 31, 2013 andATSI completed the conversion of Eastlake Unit 5 in July 2013 and is expected to complete Eastlake Unit 4 by June 1, 2014.The transfer of each of the remaining units and conversion to synchronous condensers will occur when the use of the unit for RMR purposes is no longer required.On January 22, 2013, ATSI requested clarification or, in the alternative, rehearing with respect to a statement in the FERC order authorizing the transfer that ATSI's current formula rate does not include the accounts and components necessary to allow for recovery of the costs associated with acquisition of the transferred assets and that ATSI must make a filing under Section 205 of the FPA in order to recover those costs.ATSI requested clarification from FERC noting its formula rate currently includes the necessary accounts and components to allow for such recovery and that a Section 205 filing is not required.On August 5, 2013, FERC clarified that the issue of whether the cost of the transferred facilities and any conversion costs could be included in ATSI’s formula rates is more appropriately addressed during ATSI’s yearly formula rate update process.Based on this clarification by FERC, FE and FES recognized a pre-tax gain of approximately$17 millionin the third quarter of 2013 representing the sales price to ATSI over the net book value.

FTR Underfunding Complaint

In PJM, FTRs are a mechanism to hedge congestion and they operate as a financial replacement for physical firm transmission service.FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price differences across a specific transmission path in the PJM Day-ahead Energy Market.FE also performs bilateral transactions for the purpose of hedging the price differences between the location of supply resources and retail load obligations. Due to certain language in the PJM tariff, the funds that are set aside to pay FTRs can be diverted to other uses, resulting in “underfunding” of FTR payments.Since June of 2010, FES and AE Supply have lost more than$63.5 millionin revenues that they otherwise would have received as FTR holders to hedge congestion costs.FES and AE Supply expect to continue to experience significant underfunding.

On December 28, 2011, FES and AE Supply filed a complaint with FERC for the purpose of modifying certain provisions in the PJM tariff to eliminate FTR underfunding.On March 2, 2012, FERC issued an order dismissing the complaint.In its order, FERC ruled that it was not appropriate to initiate action at that time because of the unknown root causes of FTR underfunding.FERC directed PJM to convene stakeholder proceedings for the purpose of determining the root causes of the FTR underfunding.FERC went on to note that its dismissal of the complaint was without prejudice to FES and AE Supply or any other affected entity filing a complaint if the stakeholder proceedings proved unavailing.FES and AE Supply sought rehearing of FERC's order and, on July 19, 2012, FERC denied rehearing.In April, 2012, PJM issued a report on FTR underfunding.However, the PJM stakeholder process proved unavailing as the stakeholders were not willing to change the tariff to eliminate FTR underfunding.Accordingly, on February 15, 2013, FES and AE Supply refiled their complaint with FERC for the purpose of changing the PJM tariff to eliminate FTR underfunding.Various parties filed responsive pleadings, including PJM.On June 5, 2013, FERC issued its order denying the new complaint.On July 5, 2013, FirstEnergy filed a request for rehearing of FERC's order.FirstEnergy's request for rehearing is pending before FERC.

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, utilizing 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 FG 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

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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.FG believes the claims are without merit and intends to vigorously 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 possible loss or range of loss.

In January 2009, the EPA issued an 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, as a former owner of the facilities, is 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 during 1991 to 1994 without pre-construction 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 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. DOJ 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 which affirmed the dismissal on August 21, 2013.PN believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints.The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.PN is unable to predict the outcome of this matter or estimate the loss or possible range of loss.

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.FG intends to comply with the CAA and Ohio regulations, 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 an 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, January 31, 2013, and March 27, 2013, EPA issued additional CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007.AE 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 June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Allegheny Utilities 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.

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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 December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit and was ultimately vacated by the Court on August 21, 2012.The Court has ordered EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR.On January 24, 2013, EPA and intervenors' petitions seeking rehearing or rehearing en banc were denied by the U.S. Court of Appeals for the District of Columbia Circuit.On June 24, 2013, the Supreme Court of the United States agreed to review the decision vacating CSAPR.Oral argument is scheduled for December 10, 2013.Depending on the outcome of these proceedings and how any final rules are ultimately implemented, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' 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.On December 28, 2012, the WVDEP granted a conditional extension through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants stations.On March 20, 2013, the PA DEP granted an extension through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Mansfield stations.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.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. Oral argument is scheduled for December 10, 2013.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 currently estimated to be approximately$465 million.

As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated.FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated.As of October 9, 2013, the Hatfield's Ferry and Mitchell stations were also deactivated.

FirstEnergy and FES have various long-term coal transportation agreements, some of which run through 2025 and certain of which are related to the plants described above.We have asserted force majeure defenses for delivery shortfalls under certain agreements, and we are in discussion with the applicable counterparties.Under one agreement, we have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately$45 million, and agreed to pay liquidated damages for delivery shortfalls, if any, for 2013 and 2014.As to another agreement, based on the state of current negotiations, penalties of approximately$25 millionfor delivery shortfalls for 2012 were recorded in the third quarter of 2013, and we could incur additional penalties for any delivery shortfalls in 2013 and 2014.If we fail to reach a resolution with applicable counterparties for the unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to our belief, the force majeure provisions or other defenses do not excuse delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the state, federal and international level.Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs to control emissions of certain GHGs.In his 2013 State of the Union address, President Obama called for Congressional action on GHG emissions indicating his administration will take action in the event Congress fails to act.In June 2013, the President's Climate Action Plan outlined Executive action to: (1) cut carbon pollution in America, including EPA carbon pollution standards for both new and existing power plants by17%by 2020 (from 2005 levels), (2) prepare the United States for the impacts of climate change, and (3) lead international efforts to combat global climate change and prepare for its impacts.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required the measurement and reporting of 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

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until January 2, 2011, at the earliest.In May 2010, the EPA finalized new thresholds for GHG emissions that define when NSR pre-construction permits would be required including an emissions applicability threshold of75,000tons per year of CO₂equivalents for existing facilities under the CAA's PSD program. On April 13, 2012, the EPA proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units that are larger than25MW, which were ultimately withdrawn.On June 25, 2013, a Presidential memorandum directed EPA to complete, in a timely fashion, proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units, starting with re-proposal by September 20, 2013, and propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units.On September 20, 2013, EPA proposed a new source performance standard of 1,000 lbs. CO₂/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for fossil fuel fired units which would require partial carbon capture and storage.On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 D.C. Circuit Court of Appeals decision upholding EPA's May 2010 regulations to decide a single narrow question: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases?" Depending on the outcome of these proceedings and how any final rules are ultimately implemented, future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.

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 by 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.In December 2010, the U.N. Climate Change Conference in Cancun, Mexico resulted in an acknowledgment to reduce emissions from industrialized countries by 25 to 40 percent from 1990 emissions by 2020 and support enhanced action on climate change in the developing world.In December 2011 the 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.In December 2012, the U.N. Climate Change Conference in Doha, Qatar, resulted in countries agreeing to a new commitment period under the Kyoto Protocol beginning in 2020.The new Doha Amendment to establish a second commitment period requires the ratification of three-quarters of the parties to the Kyoto Protocol before it becomes effective.

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 operate 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.The period for finalizing the Section 316(b) regulation has been extended to November 20, 2013 under a Settlement Agreement between EPA and certain NGOs.FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore power plant's water intake channel to divert fish away from the plant's water intake system.Depending on the results of such studies and the EPA's further rulemaking and any final action taken by the states exercising best professional judgment, the future costs of compliance with these standards may require material capital expenditures.

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On April 19, 2013, the EPA proposed regulatory changes to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423).The EPA proposedeighttreatment options for waste water discharges from electric power plants, of which four are "preferred" by the Agency.The preferred options range from more stringent chemical and biological treatment requirements to zero discharge requirements.The EPA is required to finalize this rulemaking by May 22, 2014, under a consent decree entered by a U.S. District Court and the treatment obligations are proposed to phase-in as waste water discharge permits are renewed on a5-year cycle from 2017 to 2022.Depending on the content of the EPA's final rule, the future costs of compliance with these standards may require material capital expenditures.

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 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$150 millionin 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 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 which requires the development of a TMDL limit for the river, a process that will take PA DEP approximately five years.However, the Hatfield's Ferry and Mitchell Plants in Pennsylvania that discharge into the Monongahela River were deactivated on October 9, 2013.

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 RCRA 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 April 19, 2013, the EPA stated it would "align" its proposed coal combustion residuals regulations with revised waste water discharge effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) that were proposed on that date.On July 25, 2013, the House of Representatives passed H.R. 221 that would require CCRs to be regulated under Subtitle D of RCRA, as non-hazardous.Depending on the content of the EPA's final effluent limitations rule and the specifics of any "alignment", the future costs of compliance with such standards may require material capital expenditures.

On July 27, 2012, the PA DEP filed a complaint against FG in the U.S. District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FG to resolve those claims.On December 14, 2012, a modified Consent Decree that addresses public comments received by PA DEP was entered by the court, requiring FG 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 modified Consent Decree also requires payment of civil penalties of$800,000to resolve claims under the Solid Waste Management Act.On February 1, 2013, FG submitted a Feasibility Study analyzing various technical issues relevant to the closure of LBR.On March 28, 2013, FG submitted to the PA DEP a Closure Plan Major Permit Modification Application which provides for placing a final cap over LBR that would require15years to fully implement following the closure of LBR.The estimated cost for the proposed closure plan is$234 million, including environmental and other post closure costs.On October 3, 2013, the PA DEP issued a technical deficiency letter citing four main deficiencies with the Closure Plan: (1) seeking to accelerate the 15 year period proposed by FG for closure activities to complete closure in 9 years by commencing closure activities prior to 2017 as proposed by FG; (2) seeking to extend bond closure and post closure activities beyond the 45 years proposed by FG; (3) seeking active dewatering of the CCBs in areas where there are seeps impacted by the Impoundment; and (4) seeking an abatement plan for groundwater impacted by arsenic.The Bruce Mansfield Plant is pursuing several options for its CCBs following December 31, 2016, and on January 23, 2013, announced a plan for beneficial use of its CCBs for mine reclamation in LaBelle, Pennsylvania.In June 2013, a complaint filed in the U.S. District Court for the Western District of Pennsylvania, alleges the LaBelle site is in violation of RCRA and state laws.On December 20, 2012, the Environmental Integrity Project and others served FG with a citizen suit notice alleging CWA and PA Clean Streams Law Violations at LBR.

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On October 10, 2013, a complaint was filed on behalf of approximately50individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment.The complaint states claims for private nuisance, negligence, negligence per se, reckless conduct and trespass related to alleged groundwater contamination and odors emanating from the Impoundment.FE, FG and FES believe the claims are without merit and intend to vigorously defend themselves against the allegations made in this complaint, but, at this time, are unable to predict the outcome of the above matter or estimate the possible loss or range of loss.

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 FirstEnergy's 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 ofSeptember 30, 2013based 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$124 millionhave been accrued throughSeptember 30, 2013. Included in the total are accrued liabilities of approximately$82 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 ofSeptember 30, 2013, FirstEnergy had approximately$2.2 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 guaranty, 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.FE maintains a$125 millionparental guaranty relating to a potential shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry.FE also maintains an$11 millionparental guaranty in support of the decommissioning of the spent fuel storage facilities located at its Davis-Besse and Perry nuclear facilities.

On October 4, 2013, during a refueling outage for Beaver Valley Unit 1, FENOC conducted a planned visual examination of the interior containment liner and coatings. The containment design for Beaver Valley includes an interior steel liner that is surrounded by reinforced concrete. A penetration through the containment steel liner plate of approximately 0.4 inches by 0.28 inches was discovered. A detailed investigation was initiated, including laboratory analysis that has indicated that the degraded area was initiated by foreign material inadvertently left in the concrete during construction. An assessment has been performed which concluded that any postulated leakage through the affected area was within overall allowable limits for the containment building. The structural integrity of the containment building is not affected. Repair of the containment liner has been completed and is not expected to impact the restart of the Unit.

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.An NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners.On July 9, 2012, the petitioners' proposed a contention on the environmental impacts of spent fuel storage in the Davis-Besse license renewal proceeding.In an order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the challenges to the NRC Waste Confidence Decision and Temporary Storage Rule and all pending contentions on this topic should be held in abeyance.The ASLB has suspended further consideration of the petitioners' proposed contention on the environmental impacts of spent fuel storage at Davis-Besse.The NRC Staff issued Waste Confidence Draft Generic Environmental Impact Statement and published a proposed rule on this subject in September of 2013.

In May 2013, four petitioners requested a hearing on an NRC LAR submitted by FENOC to amend the Technical Specifications for the Davis-Besse plant to support plant operations following replacement of the steam generators, which is scheduled to be completed in April 2014.The petitioners also challenged FENOC's ability to replace the steam generators at the Davis-Besse plant under the NRC regulations, 10 CFR §50.59 without submitting a formal LAR.By an order dated August 12, 2013, the NRC denied the request for a hearing.

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station FENOC identified changes to the laminar cracking condition discovered in 2011. FENOC expanded its sample size to include all of the existing core bores in the shield building. These inspections are now complete. FENOC identified additional subsurface cracking that determined to be pre-existing, but not previously identified, due to improved inspection technology. In addition, these inspections revealed that the cracking

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condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirm that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

By a 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 conducted several supplemental inspections, including inspections using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues were understood, the extent of condition was identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.On August 12, 2013, the NRC issued an inspection report for the final 95002 Supplemental Inspection for Perry and returned Perry to the Licensee Response Column (Column 1) of the NRC's ROP Action Matrix.

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.

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 millionfor 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, the defendants posted bond and filed a Notice of Appeal with the Superior Court.On August 13, 2012, the Superior Court affirmed the$14 millionpast damages award but vacated the$90 millionfuture damages award.While the Superior Court found that the defendants still owed future damages, it remanded the calculation of those damages back to the trial court.The specific amount of those future damages is not known at this time, but they are expected to be calculated at a market price of coal that is significantly lower than the price used by the trial court.On August 27, 2012, AE Supply and MP filed an Application for Reargument En Banc with the Superior Court, which was denied on October 19, 2012.AE Supply and MP filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on November 19, 2012.On July 2, 2013, the Petition for Allowance of Appeal was denied and in the second quarter of 2013 the now final past damage award of$15.5 million(including interest) was recognized.The case was sent back to the trial court to recalculate the future damages only and is currently in the discovery phase.

Other Legal Matters

In 2010, a lawsuit was filed in Allegheny County Court of Common Pleas by Michael Goretzka, for wrongful death and negligence after his wife was fatally electrocuted when she contacted a downed power line.The trial resulted in a verdict against WP and the parties settled this matter.WP's portion of the settlement was covered by insurance subject to the remainder of its deductible.On May 30, 2012, the PPUC's Bureau of Investigation and Enforcement (I&E) filed a Formal Complaint at the PPUC regarding this matter.On February 13, 2013, WP and I&E filed a Joint Petition for Full Settlement that includes, among other things, WP's agreement to conduct an infrared inspection of its primary distribution system, modify certain training programs, and pay an$86,000civil penalty, which settlement is subject to PPUC approval.On August 29, 2013, the PPUC entered an Order granting the Goretzka family limited party status for the sole purpose of submitting comments to the settlement and issuing the settlement for comment by the parties.On September 16, 2013, the Goretzka family filed Limited Objections to the settlement. Reply comments were filed by WP on September 30, 2013.

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 12, Regulatory Matters of the Combined Notes to 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 if such estimate can be made.

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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 retail and wholesale customers, and through its principal subsidiaries, FG and NG, owns or leases, operates and maintains FirstEnergy’s fossil and hydroelectric generation facilities (excluding the Allegheny facilities), and owns, through its subsidiary, NG, 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 FG and NG, and may purchase 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 primarily 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.

FES is exposed to various market and financial risks, including the risk of price fluctuations in the wholesale power markets. Wholesale power prices may be impacted by the prices of other commodities, including coal and natural gas, and energy efficiency and demand response programs, as well as regulatory and legislative actions, such as MATS among other factors. FES attempts to mitigate the market risk inherent in its energy position by economically hedging its exposure and continuously monitoring various risk measurement metrics to ensure compliance with its risk management policies.

During the second quarter FirstEnergy Corp. completed a $1.5 billion equity contribution to FES.

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 decreased by $251 million in the first nine months of 2013 compared to the same period of 2012, as more fully described below.

Revenues -

Total revenues increased$144 million, in the first nine months of 2013, compared to the same period of 2012, primarily due to growth in governmental aggregation and mass market sales and an increase in POLR and structured sales, partially offset by a decline in wholesale sales. Revenues were adversely impacted by lower unit prices compared to 2012 as a result of a significant decrease in market prices beginning in the fourth quarter of 2011 when the 2013 Competitive retail sales position was approximately 50% committed.

The increase in total revenues resulted from the following sources:

	Nine Months Ended September 30				Increase
Revenues by Type of Service	2013		2012		(Decrease)
	(In millions)
Direct	$	2,162	$	2,157	$	5
Governmental Aggregation	911		788		123
Mass Market	335		264		71
POLR and Structured	862		693		169
Wholesale	180		429		(249		)
Transmission	98		84		14
RECs	—		5		(5		)
Other	107		91		16
Total Revenues	$	4,655	$	4,511	$	144

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	Nine Months Ended September 30		Increase
MWH Sales by Channel	2013	2012	(Decrease)
	(In thousands)
Direct	41,678	39,922	4.4	%
Governmental Aggregation	15,975	12,833	24.5	%
Mass Market	5,045	3,865	30.5	%
POLR and Structured	16,780	12,300	36.4	%
Wholesale	—	96	(100.0	)%
Total MWH Sales	79,478	69,016	15.2	%

The increase in Direct revenues of $5 million resulted from higher sales volumes due to the acquisition of new customers and weather related usage as heating degree days were 26% above 2012 levels, partially offset by cooling degree days, which were 18% below 2012 levels, and lower unit prices. The increase in Governmental Aggregation of $123 million resulted from the acquisition of new customers primarily in Illinois and weather related usage, partially offset by lower unit prices. The increase in Mass Market of $71 million resulted from the acquisition of new customers primarily in Ohio and Pennsylvania and weather related usage, partially offset by lower unit prices. The Direct, Governmental Aggregation and Mass Market customer base increased to 2.7 million customers as of September 30, 2013, as compared to 2.5 million as of September 30, 2012.

The increase in POLR and structured revenues of $169 million was due primarily to increased sales volumes in each channel, which were partially offset by lower unit prices.

Wholesale revenues decreased $249 million primarily due to lower gains of $189 million on financially settled contracts, a $58 million decrease in capacity revenues resulting primarily from lower capacity prices and $2 million in lower sales volumes. The decrease in wholesale sales volumes was due to lower generation available for sale, primarily as a result of the plants that were deactivated in 2012 and those under RMR arrangements, lower nuclear generation and higher retail sales volumes.

Transmission revenue increased $14 million due to higher congestion revenue and higher ancillary revenue associated with additional retail load.

Other revenue increased $16 million due primarily to repurchases in 2012 of third-party lessor equity interests in OE’s existing sale and leaseback of Beaver Valley Unit 2. FES earns lease revenue associated with the equity interests it repurchased.

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

Source of Change in Direct Revenues	Increase (Decrease)
	(In millions)
Effect of increase in sales volumes	$	95
Change in prices	(90		)
	$	5

Source of Change in Governmental Aggregation Revenues	Increase (Decrease)
	(In millions)
Effect of increase in sales volumes	$	193
Change in prices	(70		)
	$	123

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Source of Change in Mass Market Revenues	Increase (Decrease)
	(In millions)
Effect of increase in sales volumes	$	80
Change in prices	(9		)
	$	71

Source of Change in POLR and Structured Revenues	Increase (Decrease)
	(In millions)
Effect of increase in sales volumes	$	260
Change in prices	(91		)
	$	169

Source of Change in Wholesale Revenues	Decrease
	(In millions)
Gain on settled contracts	$	(189	)
Effect of decrease in sales volumes	(2		)
Capacity revenue	(58		)
	$	(249	)

Operating Expenses -

Total operating expenses increased by $418 million in the first nine months of 2013 compared to the same period of 2012.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first nine months of 2013 compared with the same period of 2012:

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Source of Change in Fuel and Purchased Power	Increase (Decrease)
	(In millions)
Fossil Fuel:
Change due to increased unit costs	$	21
Change due to volume consumed	(63		)
	(42		)
Nuclear Fuel:
Change due to increased unit costs	5
Change due to volume consumed	(5		)
	—
Non-affiliated Purchased Power:
Change due to increased unit costs	96
Change due to volume purchased	560
Loss on settled contracts	(201		)
Capacity expense	(125		)
	330
Affiliated Purchased Power:
Change due to increased unit costs	23
Change due to volume purchased	(14		)
Loss on settled contracts with AE Supply	11
	20
Net Increase in Fuel and Purchased Power Costs	$	308

Fuel costs decreased$42 million primarily due to lower volumes associated with the plants that were deactivated in 2012 and those under RMR arrangements, partially offset by higher unit costs. The increase in unit costs is due to settlements of past damages on transportation contracts associated with plants deactivated in 2012 and those under RMR arrangements, partially offset by lower unit prices resulting from new and restructured coal contracts. The increase in non-affiliated purchased power expense was due to higher volumes and unit prices, partially offset by fewer losses on settled contracts and lower capacity expense.

Other operating expenses increased by $77 million in the first nine months of 2013, compared to the same period of 2012 due to the following:

• Fossil operating costs decreased by $31 million due primarily to lower labor costs resulting from previously deactivated units and lower compensation and benefit expenses based on plan changes.

• Nuclear operating costs decreased by $27 million due primarily to lower contractor, materials and equipment costs. In 2013, there was a single refueling outage at Perry while there were two refueling outages during the same period of 2012. Additionally, compensation and benefit expenses were lower as a result of plan changes in 2013.

• Transmission expenses increased $71 million due primarily to higher rates associated with higher ancillary, network and line loss costs and additional retail load, partially offset by lower congestion costs and a credit received in the third quarter of 2013 for previously incurred PJM transmission costs associated with RMR units.

• Other operating expenses increased by $64 million primarily due to an increase in mark-to-market expense on commodity contract positions ($88 million) partially offset by reduced lease expense ($24 million) from repurchasing interests in sale and leaseback transactions during 2012.

Depreciation expense increased $31 million primarily due to credits in 2012 from a settlement with the DOE and an increase in depreciable base as a result of capital expenditures and repurchasing interests in Bruce Mansfield and Beaver Valley Unit 2 sale leasebacks noted above.

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Other Expense -

Total other expense increased by $138 million in the first nine months of 2013, compared to the same period of 2012, primarily due to a $103 million loss on debt redemptions associated with the repurchase of senior notes, lower investment income of $54 million due to higher OTTI on the NDT investments, lower net interest expense of $15 million due to debt redemptions and repurchases and higher miscellaneous income of $4 million due to a $17 million pre-tax gain on the sale of property to a regulated affiliate, partially offset by pre-tax gains of $13 million on 2012 asset sales.

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 FirstEnergy and FES, 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 FE and FES have concluded that their 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 September 30, 2013, there were no changes in internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, FE's and FES' internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.        LEGAL PROCEEDINGS

Information required for Part II, Item 1 is incorporated by reference to the discussions in Note 12, Regulatory Matters, and Note 13, Commitments, Guarantees and Contingencies, of the Combined Notes to the Consolidated Financial Statements in Part I, Item 1 of this Form 10-Q.

ITEM 1A.    RISK FACTORS

During the quarter ended September 30, 2013, there were no material changes to the risk factors included in our Annual Report or Form 10-K for the year ended December 31, 2012, and the Form 10-Q for the quarter ended June 30, 2013.

ITEM 2.        UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

(c) The table below includes information on a monthly basis regarding purchases of FE common stock during the third quarter of 2013:

	Period
	July		August		September		Third Quarter
Total Number of Shares Purchased(1)	34,101		40,043		489,291		563,435
Average Price Paid per Share	$	37.22	$	37.82	$	37.38	$	37.40
Total Number of Shares Purchased As Part of Publicly Announced Plans or Programs(2)	—		—		—		—
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, Deferred Compensation Plan for Outside Directors, Executive Deferred Compensation Plan, Savings Plan, Director Compensation, Allegheny Energy, Inc., 1998 Long-Term Incentive Plan, Allegheny Energy, Inc., 2008 Long-Term Incentive Plan, Allegheny Energy, Inc., Non-Employee Director Stock Plan, Allegheny Energy, Inc., Amended and Restated Revised Plan for Deferral of Compensation of Directors, and Stock Investment Plan.

⁽²⁾  FirstEnergy does not currently have any publicly announced plan or program for share purchases.

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ITEM 3.        DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.        MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.        OTHER INFORMATION

On October 31, 2013, FirstEnergy and certain of its subsidiaries entered into amendments to the two existing multi-year syndicated revolving credit facilities (Amendments). Pursuant to the Amendments, certain after-tax, non-cash write downs and non-cash charges are to be excluded from the debt total capitalization ratio calculations with respect to the following facilities:

(1) the $2.5 billion Credit Agreement, dated as of June 17, 2011, as amended, among FirstEnergy, CEI, ME, OE, Penn, TE, JCP&L, MP, PN, PE and WP, as borrowers, The Royal Bank of Scotland plc, as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (FirstEnergy Facility); and

(2) the $2.5 billion Credit Agreement, dated as of June 17, 2011, as amended, among FES and AE Supply, as borrowers, and JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein (FES/AE Supply Facility).

The Amendment to the FirstEnergy Facility permits the exclusion of certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the Amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the FirstEnergy Facility. Similarly, the FES/AE Supply Facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. The exclusion of such after-tax non-cash write-downs and non-cash charges permitted in the Amendments are attributable or relate to (i) pension and other postemployment benefits, (ii) impairment of regulatory and other long-lived assets, (iii) disallowance of regulatory assets, and (iv) goodwill impairment. The effect of these Amendments will apply to the compliance reports for the period ended September 30, 2013, which are due November 29, 2013.

The borrowers and their affiliates maintain ordinary banking and investment banking relationships with certain of the lenders under these credit facilities.

The above descriptions of the Amendments do not purport to be a complete statement of the relevant parties' rights and obligations thereunder and the transactions contemplated thereby, and are qualified in their entirety by reference to the Amendments, copies of which are filed as Exhibits 10.1(a) and 10.1(b), respectively, to this Form 10-Q and are incorporated herein by reference.

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ITEM 6.        EXHIBITS

Exhibit Number
FirstEnergy
(A)	10.1(a)	Amendment, dated as of October 31, 2013, to the Credit Agreement, dated as of June 17, 2011, as amended as of May 8, 2012 and May 8, 2013, among FirstEnergy, The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, 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.
(A)	10.2	Guarantee, dated as of September 16, 2013 by FirstEnergy Corp. in favor of participants under the FirstEnergy Corp. Executive Deferred Compensation Plan.
(A)	12	Fixed charge ratio
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2013, 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
(A)	10.1(b)	Amendment, dated as of October 31, 2013, to the Credit Agreement, dated as of June 17, 2011, as amended as of October 3, 2011, May 8, 2012 and May 8, 2013, among FirstEnergy Solutions Corp. and Allegheny Energy Supply Company, LLC, as borrowers, and JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended September 30, 2013, 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) Provided herein in electronic format as an exhibit.

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

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SIGNATURES

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

November 5, 2013

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

/s/ K. Jon Taylor

K. Jon Taylor

Vice President, Controller

and Chief Accounting Officer 

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EXHIBIT INDEX

Exhibit Number
FirstEnergy
(A)	10.1(a)	Amendment, dated as of October 31, 2013, to the Credit Agreement, dated as of June 17, 2011, as amended as of May 8, 2012 and May 8, 2013, among FirstEnergy, The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, 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.
(A)	10.2	Guarantee, dated as of September 16, 2013 by FirstEnergy Corp. in favor of participants under the FirstEnergy Corp. Executive Deferred Compensation Plan.
(A)	12	Fixed charge ratio
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended September 30, 2013, 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
(A)	10.1(b)	Amendment, dated as of October 31, 2013, to the Credit Agreement, dated as of June 17, 2011, as amended as of October 3, 2011, May 8, 2012 and May 8, 2013, among FirstEnergy Solutions Corp. and Allegheny Energy Supply Company, LLC, as borrowers, and JPMorgan Chase Bank, N.A., as administrative agent, and the lending banks, fronting banks and swing line lenders identified therein.
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended September 30, 2013, 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) Provided herein in electronic format as an exhibit.

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EX-10.1(A)

EXHIBIT 10.1(a)

AMENDMENT

Dated as of October 31, 2013

To the Lenders party to the Credit Agreement

and the Administrative Agent referred to below

Ladies and Gentlemen:

Reference is made to the Credit Agreement, dated as of June 17, 2011 and as amended as of May 8, 2012 and May 8, 2013 (the “Credit Agreement”), among FirstEnergy Corp., The Cleveland Electric Illuminating Company, Metropolitan Edison Company, Ohio Edison Company, Pennsylvania Power Company, The Toledo Edison Company, Jersey Central Power & Light Company, Monongahela Power Company, Pennsylvania Electric Company, The Potomac Edison Company and West Penn Power Company, as the Borrowers, The Royal Bank of Scotland plc, as Administrative Agent for the Lenders thereunder, the fronting banks party thereto, the swing line lenders party thereto and the Lenders party thereto. This amendment of the Credit Agreement is hereinafter referred to as this “Amendment”, and the Credit Agreement, as amended by this Amendment, is referred to as the “Amended Credit Agreement”. Capitalized terms used herein and not otherwise defined herein have the meanings given such terms in the Credit Agreement.

Section 1. Credit Agreement Amendment. The parties agree that, subject to the satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is amended as follows:

(a)The following new term is inserted in Section 1.01 in appropriate alphabetical order:

“‘PPUC Order’ means the Pennsylvania Public Utility Commission opinion and order Pennsylvania Public Utility Commission v. Pennsylvania Electric Company and Pennsylvania Public Utility Commission v. Metropolitan Edison Company [consolidated], 210 WL 2911737 (Pa.P.U.C.) (March 3, 2010), as subsequently affirmed by an opinion and order of the Commonwealth Court of Pennsylvania on June 14, 2011, Metropolitan Edison Company v. Pennsylvania Public Utility Commission, 22 A.3d 353 (Pa.Commw. 2011), and left undisturbed by the United States District Court for the Eastern District of Pennsylvania in its order issued on September 30, 2013 (Civil Action No. 11-cv-04474).”

(b)The defined term “Total Capitalization” set forth in Section 1.01 is amended and restated in its entirety to read as follows:

“‘Total Capitalization’ means, with respect to any Borrower at any date of determination the sum, without duplication, of (i) Consolidated Debt of such Borrower, (ii) the capital stock (but excluding treasury stock and capital stock subscribed and unissued) and other equity accounts (including retained earnings and paid in capital but excluding

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accumulated other comprehensive income and loss) of such Borrower and its Consolidated Subsidiaries, (iii) consolidated equity of the preference stockholders of such Borrower and its Consolidated Subsidiaries, and (iv) the aggregate principal amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Debt Obligations of such Borrower and its Consolidated Subsidiaries; provided, however, that, commencing with the fiscal quarter ended September 30, 2013 and for each fiscal quarter ending thereafter, ‘Total Capitalization’ shall be determined subject to the following adjustments:

(A)    as applicable, for the respective Borrowers, there shall be excluded in such determination the following after-tax effects resulting from non-cash write-downs and non-cash charges occurring and recognized for the periods indicated below as reflected in the consolidated financial statements of the applicable Borrowers for such periods:

(1)    in respect of pension and other postemployment benefits occurring and recognized in fiscal years 2011 and 2012, which shall not exceed in the aggregate $691,600,000 for all Borrowers (without duplication but allowing for, as applicable, consolidation);

(2)    in respect of asset impairments attributable to the Albright, Rivesville and Willow Island Plants owned by MP, the Armstrong and R. Paul Plants owned by AESC, and the Bay Shore (Units 2-4 only), Eastlake (Units 4-5 only), Fremont and Richland Plants owned by FirstEnergy Generation, LLC occurring and recognized in fiscal year 2011, which shall not exceed in the aggregate $255,400,000 for all Borrowers (without duplication but allowing for, as applicable, consolidation); and

(3)    in respect of asset impairments attributable to the Hatfield’s Ferry Power Station and the Mitchell Power Station owned by AESC occurring and recognized in fiscal year 2013 through September 30, 2013, which shall not exceed in the aggregate $317,300,000 for all Borrowers (without duplication but allowing for, as applicable, consolidation); and

(B)    in addition to the adjustments described in clause (A) above, for the respective Borrowers there shall be excluded in such determination the after-tax effects resulting from non-cash write-downs and non-cash charges attributable or relating to the following: (1)(i) pension and other postemployment benefits, (ii) impairment of regulatory and other long-lived assets, (iii) disallowance of regulatory assets, and (iv) goodwill impairment, in each case, occurring and recognized during the fiscal quarter ending December 31, 2013 and in any fiscal quarter ending thereafter as reflected in the consolidated financial statements of the respective Borrowers for such periods, and (2) disallowance of regulatory assets consisting of marginal transmission line losses of Met-Ed and Penelec occurring during the period from January 11, 2007 through December 31, 2010 as described in the PPUC Order, in each case, occurring and recognized during the fiscal quarter ended September 30, 2013 as reflected in the consolidated financial statements of the respective Borrowers for such period, but such adjustments shall not exceed in the aggregate $1,500,000,000 for all Borrowers (without duplication but allowing for, as applicable, consolidation).”

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Section 2. Conditions to Effectiveness of this Amendment. This Amendment shall be effective as of the date hereof when and if (such date being the “Amendment Date”) the following conditions are satisfied:

(a)The Administrative Agent shall have received the following, each dated as of the Amendment Date, in form and substance satisfactory to the Administrative Agent and with one copy for each Lender:

(i)    Counterparts of this Amendment, duly executed by each of the Borrowers and Lenders constituting Majority Lenders;

(ii)    A certificate of an Authorized Officer of each Borrower stating that both before and after giving effect to this Amendment (A) no event has occurred and is continuing that constitutes an Event of Default or an Unmatured Default and (B) all representations and warranties made by such Borrower in the Amended Credit Agreement are true and correct in all material respects, except for those made specifically as of another date, in which case such representations and warranties shall be true as of such other date; and

(iii)    Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent or such other Lender (as the case may be).

(b)The Borrowers shall have paid an amendment fee equal to 0.05% of the Commitment of each Lender that executes this Amendment at or before 5:00 p.m. (New York City time) on September 27, 2013, payable on the Amendment Date to the Administrative Agent for the account of each such Lender.

(c)Each of the representations and warranties in Section 4 of this Amendment shall be true and correct.

Section 3. Borrower Sublimit Increase.

(a)The parties agree that, subject to the satisfaction of the conditions precedent set forth in Section 3(b), in addition to those in Section 2 above, MP may increase its Borrower Sublimit to an amount equal to the lesser of (i) $500,000,000 and (ii) the amount approved under the MP FERC Order (such lesser amount, the “New MP Sublimit”; and such increase, the “MP Sublimit Increase”).

(b)The MP Sublimit Increase shall be effective as of the date (such date being the “MP Sublimit Increase Date”) when and if the Administrative Agent shall have received the following, each dated as of the MP Sublimit Increase Date, in form and substance satisfactory to the Administrative Agent and with one copy for each Lender:

(i)Certified copies of (A) the resolutions of the Board of Directors of MP approving the MP Sublimit Increase and (B) all documents evidencing any other necessary corporate action with respect to the MP Sublimit Increase;

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(ii)A certificate of the Secretary or an Assistant Secretary of MP certifying that attached thereto are true and correct copies of all governmental and regulatory authorizations and approvals (including the MP FERC Order) required for the MP Sublimit Increase; and

(iii)Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent or such other Lender (as the case may be).

(c)On the MP Sublimit Increase Date, the term “Borrower Sublimit” set forth in Section 1.01 shall automatically be amended by replacing the amount “$150,000,000” appearing opposite the text “MP” with an amount equal to the New MP Sublimit.

Section 4. Representations and Warranties. Each Borrower represents and warrants that (i) the representations and warranties of such Borrower contained in Section 4.01 of the Amended Credit Agreement (with each reference therein to “this Agreement”, “hereunder” and words of like import referring to the Credit Agreement being deemed to be a reference to the Amended Credit Agreement and each reference therein to “Loan Document” and words of like import being deemed to be a reference that includes this Amendment and the Amended Credit Agreement) are true and correct on and as of the Amendment Date as though made on and as of the Amendment Date (other than, as to any such representation or warranty that by its terms refers to a specific date other than the Amendment Date, in which case, such representation and warranty shall be true and correct as of such specific date); and (ii) no event has occurred and is continuing, or would result from the execution, delivery or performance by such Borrower of this Amendment or the performance by such Borrower of the Amended Credit Agreement that constitutes an Event of Default or an Unmatured Default with respect to such Borrower.

Section 5. Effect on the Loan Documents. The execution, delivery and effectiveness of this Amendment shall not, except as expressly set forth herein, operate as a waiver of any right, power or remedy of any Lender, Swing Line Lender or Fronting Bank or the Administrative Agent under the Credit Agreement or any other Loan Document, or constitute a waiver of any provision of the Credit Agreement or any other Loan Document. Except as expressly set forth herein, each of the Credit Agreement and the other Loan Documents is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. This Amendment shall constitute a Loan Document and shall be binding on the parties hereto and their respective successors and permitted assigns under the Amended Credit Agreement. Upon and after the execution of this Amendment by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Amended Credit Agreement.

Section 6.    Costs, Expenses and Taxes. Each Borrower agrees to pay on demand all reasonable out-of-pocket costs and expenses incurred by the Administrative Agent in connection with the preparation, execution, delivery and syndication administration of this Amendment and the other documents to be delivered hereunder, including, without limitation, the reasonable fees and out‑of‑pocket expenses of counsel for the Administrative Agent with respect thereto and with

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respect to advising the Administrative Agent as to their rights and responsibilities under this Amendment. Each Borrower further agrees to pay on demand all reasonable out-of-pocket costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses of counsel), incurred by the Administrative Agent and the Lenders in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment, the Amended Credit Agreement and the other documents to be delivered hereunder, including, without limitation, counsel fees and expenses in connection with the enforcement of rights under this Section.

Section 7. Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

Section 8. Governing Law. This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York.

If you agree to the foregoing, please evidence such agreement by (i) executing and returning one counterpart of this Amendment by facsimile or e-mail to Kai-Ting Yang (fax no. 212-556-2222; e-mail: kyang@kslaw.com) and (ii) executing and returning five original counterparts to this Amendment by overnight mail to King & Spalding LLP, 1185 Avenue of the Americas, New York, New York 10036, Attention: Kai-Ting Yang.

[Remainder of page intentionally left blank.]

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Very truly yours,

FIRSTENERGY CORP.

THE CLEVELAND ELECTRIC ILLUMINATING COMPANY

METROPOLITAN EDISON COMPANY

OHIO EDISON COMPANY

PENNSYLVANIA POWER COMPANY

THE TOLEDO EDISON COMPANY

MONONGAHELA POWER COMPANY

PENNSYLVANIA ELECTRIC COMPANY

THE POTOMAC EDISON COMPANY

WEST PENN POWER COMPANY

By /s/Steven R. Staub            

Steven R. Staub

Vice President and Treasurer

JERSEY CENTRAL POWER & LIGHT COMPANY

By /s/Weizhong Wang         _

Weizhong (Bill) Wang

Treasurer

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

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The undersigned hereby agree to the foregoing:

THE ROYAL BANK OF SCOTLAND PLC, as Administrative Agent and as a Lender

By /s/Andrew N. Taylor            

Name: Andrew Taylor

Title: Vice President

JPMORGAN CHASE BANK, N.A., as a Lender

By /s/Peter Christensen            

Name: Peter Christensen

Title: Vice President

BARCLAYS BANK PLC, as a Lender

By /s/Alicia Borys                

Name: Alicia Borys

Title: Vice President

Bank of America, N.A., as a Lender

By /s/Jerry Wells            

Name: Jerry Wells

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

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CITIBANK, N.A., as a Lender

By /s/D. Scott McMurtry        

Name: D. Scott McMurtry

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

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KeyBank National Association, as a Lender

By /s/Sherrie I. Manson        

Name: Sherrie I. Manson

Title: Senior Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-5

The Bank of Tokyo-Mitsubishi UFJ, Ltd. as a Lender

By /s/Robert MacFarlane            

Name: Robert MacFarlane

Title: VP

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-6

UNION BANK, N.A., as a Lender

By /s/Y. Joanne Si            

Name: Y. Joanne Si

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-7

The Bank of Nova Scotia, as a Lender

By /s/Thane Rattew            

Name: Thane Rattew

Title: Managing Director

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-8

Goldman Sachs Bank USA, as a Lender

By /s/Michelle Latzoni            

Name: Michelle Latzoni

Title: Authorized Signatory

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-9

MORGAN STANLEY BANK, N.A., as a Lender

By /s/John Durland            

Name: John Durland

Title: Authorized Signatory

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-10

MORGAN STANLEY SENIOR FUNDING, INC., as a Lender

By /s/John Durland            

Name: John Durland

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-11

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender

By /s/Vipul Dhadda            

Name: Vipul Dhadda

Title: Authorized Signatory

By /s/Philipp Horst            

Name: Philipp Horst

Title: Authorized Signatory

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-12

BNP Paribas, as a Lender

By /s/Denis O’Meara            

Name: Dennis O’Meara

Title: Managing Director

By /s/Pasquale Perraglia        

Name: Pasquale Perraglia

Title: Director

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-13

Royal Bank of Canada, as a Lender

By /s/Frank Lambrinos        

Name: Frank Lambrinos

Title: Authorized Signatory

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-14

MIZUHO BANK, LTD., as a Lender

By /s/Raymond Ventura            

Name: Raymond Ventura

Title: Deputy General Manager

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-15

SUMITOMO MITSUI BANKING CORPORATION, as a Lender

By /s/James D. Weinstein            

Name: James D. Weinstein

Title: Managing Director

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-16

WELLS FARGO BANK, N.A., as a Lender

By /s/Fredrick W. Price            

Name: Fredrick W. Price

Title: Managing Director

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-17

U.S. Bank National Association, as a Lender

By /s/Eric J. Cosgrove            

Name: Eric J. Cosgrove

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-18

PNC Bank, N.A., as a Lender

By /s/Christian S. Brown        

Name: Christian S. Brown

Title: Senior Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-19

The Bank of New York Mellon, as a Lender

By /s/Richard K. Fronapfel, Jr.     

Name: Richard K. Fronapfel, Jr.

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-20

Canadian Imperial Bank of Commerce, New York Branch, as a Lender

By /s/Gordon R. Eadon        

Name: Gordon R. Eadon

Title: Authorized Signatory

By /s/Robert W. Casey Jr.        

Name: Robert W. Casey Jr.

Title: Authorized Signatory

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-21

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Lender

By /s/Darrell Stanley            

Name: Darrell Stanley

Title: Managing Director

By /s/ David Gurghigian        

Name: David Gurghigian

Title: Managing Director

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-22

SOVEREIGN BANK, N.A., as a Lender

By /s/William Maag            

Name: William Maag

Title: Senior Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-23

COBANK, ACB, as a Lender

By /s/ Josh Batchelder         

Name: Josh Batchelder

Title: Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-24

BANCO BILBAO VIZCAYA ARGENTINA, S.A. NEW YORK BRANCH, as a Lender

By /s/ Luca Sacchi            

Name: Luca Sacchi

Title: Executive Director

By /s/ Veronica Incera            

Name: Veronica Incera

Title: Executive Director

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-25

THE HUNTINGTON NATIONAL BANK, as a Lender

By /s/Brian H. Gallagher        

Name: Brian H. Gallagher

Title: Senior Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-26

NATIONAL COOPERATIVE SERVICES CORPORATION, as a Lender

By /s/ Daniel Lyzinski         

Name: Daniel Lyzinski

Title: Assistant Secretary Treasurer

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

S-27

TD Bank, N.A., as a Lender

By /s/Stephen Levi            

Name: Stephen Levi

Title: Senior Vice President

Amendment to FirstEnergy Corp. Credit Agreement Signature Page

EX-10.1(B)

EXHIBIT 10.1(b)

AMENDMENT

Dated as of October 31, 2013

To the Lenders party to the Credit Agreement

and the Administrative Agent referred to below

Ladies and Gentlemen:

Reference is made to the Credit Agreement, dated as of June 17, 2011 and as amended as of October 3, 2011, May 8, 2012 and May 8, 2013 (the “Credit Agreement”), among FirstEnergy Solutions Corp. and Allegheny Energy Supply Company, LLC, as the Borrowers, JPMorgan Chase Bank, N.A., as Administrative Agent for the Lenders thereunder, the fronting banks party thereto, the swing line lenders party thereto and the Lenders party thereto. This amendment of the Credit Agreement is hereinafter referred to as this “Amendment”, and the Credit Agreement, as amended by this Amendment, is referred to as the “Amended Credit Agreement”. Capitalized terms used herein and not otherwise defined herein have the meanings given such terms in the Credit Agreement.

Section 1. Credit Agreement Amendment. The parties agree that, subject to the satisfaction of the conditions precedent set forth in Section 2 below, the Credit Agreement is amended as follows:

(a)The following new terms are inserted in Section 1.01 in appropriate alphabetical order:

“‘Allegheny-FES Guaranty’ means any guaranty of Allegheny with respect to certain indebtedness of FES, entered into as provided in the last sentence of Section 5.03(c).”

“‘FES-Allegheny Guaranty’ means any guaranty of FES with respect to certain indebtedness of Allegheny, entered into as provided in the last sentence of Section 5.03(c).”

“‘October 2013 Amendment’ means the Amendment dated as of October 31, 2013, among the Borrowers, certain of the Lenders comprising the Majority Lenders, and the Administrative Agent, amending this Agreement in certain respects.”

“‘Sole Borrower’ means the surviving or resulting Borrower upon the effectiveness of a Sole Borrower Transaction as described in the final sentence of Section 5.03(c).”

“‘Sole Borrower Transaction’ means a merger, consolidation, transfer of capital stock (including limited liability company interests) or transfer of assets and liabilities, or a combination of the foregoing transactions, as described in the final sentence of Section 5.03(c), pursuant to which the surviving or resulting Person has become the sole Borrower

2

for purposes of this Agreement and all conditions set forth in such final sentence of Section 5.03(c) and in Section 3(b) of the October 2013 Amendment have been satisfied.”

(b)The defined term “Borrower Sublimit” set forth in Section 1.01 is amended and restated in its entirety to read as follows:

“‘Borrower Sublimit’ means: (i) with respect to FES, $1,500,000,000, and (ii) with respect to Allegheny, $1,000,000,000, in each case as modified from time to time pursuant to Section 2.06; provided, however, that upon the effectiveness of a Sole Borrower Transaction, the Borrower Sublimit applicable to the Sole Borrower shall be the total amount of the Commitments as in effect from time to time.”

(c)The defined term “Genco” set forth in Section 1.01 is amended and restated in its entirety to read as follows:

“‘Genco’ means each of FGC, NGC and, in the event Allegheny becomes a Consolidated Subsidiary of FES in a transaction pursuant to clause (C) of the last sentence of Section 5.03(c), Allegheny.”

(d)The defined term “Genco Guarantees” set forth in Section 1.01 is amended and restated in its entirety to read as follows:

“‘Genco Guarantees’ means (i) the FES-FGC Guaranty, the FES-NGC Guaranty, the FGC-FES Guaranty and the NGC-FES Guaranty and (ii) in the event Allegheny becomes a Consolidated Subsidiary of FES in a transaction pursuant to clause (C) of the last sentence of Section 5.03(c), the Allegheny-FES Guaranty and the FES-Allegheny Guaranty.”

(e)The defined term “Total Capitalization” set forth in Section 1.01 is amended and restated in its entirety to read as follows:

“‘Total Capitalization’ means, with respect to any Borrower at any date of determination the sum, without duplication, of (i) Consolidated Debt of such Borrower, (ii) the capital stock (including limited liability company interests, but excluding treasury stock and capital stock subscribed and unissued) and other equity accounts (including retained earnings and paid in capital but excluding accumulated other comprehensive income and loss) of such Borrower and its Consolidated Subsidiaries, (iii) consolidated equity of the preference stockholders of such Borrower and its Consolidated Subsidiaries, and (iv) the aggregate principal amount of Trust Preferred Securities and Junior Subordinated Deferred Interest Debt Obligations of such Borrower and its Consolidated Subsidiaries; provided, however, that, commencing with the fiscal quarter ended September 30, 2013 and for each fiscal quarter ending thereafter, ‘Total Capitalization’ shall exclude, as applicable, for the respective Borrowers, the following after-tax effects resulting from non-cash write-downs and non-cash charges occurring and recognized for the periods indicated below as reflected in the consolidated financial statements of the applicable Borrowers for such periods:

(A)    in respect of pension and other postemployment benefits occurring and recognized in fiscal years 2011 and 2012, which shall not exceed in the aggregate

3

$267,400,000 for both Borrowers (without duplication but allowing for, as applicable, consolidation);

(B)    in respect of asset impairments attributable to the Armstrong and R. Paul Plants owned by Allegheny and the Bay Shore (Units 2-4 only), Eastlake (Units 4-5 only), Fremont and Richland Plants owned by FGC occurring and recognized in fiscal year 2011, which shall not exceed in the aggregate $201,100,000 for both Borrowers (without duplication but allowing for, as applicable, consolidation); and

(C)    in respect of asset impairments attributable to the Hatfield’s Ferry Power Station and the Mitchell Power Station owned by Allegheny occurring and recognized in fiscal year 2013 through September 30, 2013, which shall not exceed in the aggregate $317,300,000 for both Borrowers (without duplication but allowing for, as applicable, consolidation).”

(f)Section 4.01(m) is amended and restated in its entirety to read as follows:

“Genco Guarantees. (i) All Indebtedness of FES (including, without limitation, its Indebtedness under the Loan Documents and pursuant to the FES-FGC Guaranty and, if applicable, the FES-Allegheny Guaranty) is guaranteed by NGC pursuant to the NGC-FES Guaranty; (ii) all Indebtedness of FES (including, without limitation, its Indebtedness under the Loan Documents and pursuant to the FES-NGC Guaranty and, if applicable, the FES-Allegheny Guaranty) is guaranteed by FGC pursuant to the FGC-FES Guaranty; and (iii) in the event Allegheny becomes a Consolidated Subsidiary of FES in a transaction pursuant to clause (C) of the last sentence of Section 5.03(c), all Indebtedness of FES (including, without limitation, its Indebtedness under the Loan Documents and pursuant to the FES-FGC Guaranty and the FES-NGC Guaranty) is guaranteed by Allegheny pursuant to the Allegheny-FES Guaranty.”

(g)Section 5.03(c) is amended to replace the last sentence therein with the following:

“Without limiting the foregoing, (A) each Borrower may merge with or into or consolidate with or into (x) the other Borrower or into a newly-formed Person into which both Borrowers are being merged or consolidated (which will become the sole Borrower hereunder) or (y) a wholly-owned Subsidiary of the other Borrower (in which case such other Borrower will become the sole Borrower hereunder); (B) each Borrower may transfer all or substantially all of its assets and liabilities to the other Borrower, to a wholly-owned Subsidiary of the other Borrower (in which case such other Borrower will become the sole Borrower hereunder) or to a newly-formed Person to which all or substantially all of the assets and liabilities of both Borrowers are being transferred (which will become the sole Borrower hereunder) and (C) in connection with a transfer of the limited liability company interests of Allegheny to FES pursuant to which Allegheny becomes a Consolidated Subsidiary of FES, FES will become the sole Borrower hereunder if (1) in each case of clauses (A), (B) and (C), the surviving Person, transferee or Person otherwise specified above to become the sole Borrower hereunder, as applicable, assumes both Borrowers’ obligations under this Agreement and the other Loan Documents pursuant to an instrument in form and substance reasonably satisfactory to the Administrative Agent; (2)(x) in each

4

case of clauses (A) and (B), the Administrative Agent receives evidence reasonably satisfactory to it that, after giving effect to such transactions, the Genco Guarantees will remain in full force and effect and will apply (either as a result of such merger, consolidation or transfer or pursuant to amendments to the Genco Guarantees) to the obligations of Allegheny under this Agreement and the other Loan Documents (as so transferred or assumed) in the same manner and to the same extent as such Genco Guaranties applied to the obligations of FES under this Agreement and the other Loan Documents on the date hereof, and (y) in the case of clause (C), the Administrative Agent receives evidence reasonably satisfactory to it that, after giving effect to such transfer, the FES-Allegheny Guaranty and the Allegheny-FES Guaranty have been executed and are in full force and effect, and the Genco Guarantees will apply to the indebtedness of Allegheny in the same manner and to the same extent as such Genco Guarantees applied to the indebtedness of each Genco on the date hereof and will otherwise remain in full force and effect; (3) in each case of clauses (A), (B) and (C), the Reference Ratings of the surviving or resulting Borrower are not, after giving effect to such transactions, any lower than the Reference Ratings of each Borrower that was a party to such transactions immediately prior to the consummation of such transactions, unless the Reference Ratings of such surviving or resulting Borrower are at least BBB- and Baa3; and (4) in each case of clauses (A), (B) and (C), the parties to such transaction deliver to the Administrative Agent certified copies of all corporate or limited liability company, equity holder and Governmental Authority approvals required in connection with such transactions and legal opinions of counsel to such parties relating to such transactions, the assumption agreement described in clause (1) above and the Genco Guarantees and amendments thereof described in clause (2) above, as applicable.”

Section 2. Conditions to Effectiveness of this Amendment. This Amendment shall be effective as of the date hereof when and if (such date being the “Amendment Date”) the following conditions are satisfied:

(a)The Administrative Agent shall have received the following, each dated as of the Amendment Date, in form and substance satisfactory to the Administrative Agent and with one copy for each Lender:

(i)    Counterparts of this Amendment, duly executed by each of the Borrowers, and Lenders constituting Majority Lenders;

(ii)     A certificate of an Authorized Officer of each Borrower stating that both before and after giving effect to this Amendment (A) no event has occurred and is continuing that constitutes an Event of Default or an Unmatured Default and (B) all representations and warranties made by such Borrower in the Amended Credit Agreement are true and correct in all material respects, except for those made specifically as of another date, in which case such representations and warranties shall be true as of such other date; and    

(iii)    Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent or such other Lender (as the case may be).

5

(b)The Borrowers shall have paid an amendment fee equal to 0.05% of the Commitment of each Lender that executes this Amendment at or before 5:00 p.m. (New York City time) on September 27, 2013, payable on the Amendment Date to the Administrative Agent for the account of each such Lender.

(c)Each of the representations and warranties in Section 4 of this Amendment shall be true and correct.

Section 3. Borrowing Capacity of Sole Borrower.

(a)The parties agree that, subject to the satisfaction of the conditions precedent set forth in Section 3(b) below, in addition to those in Section 2 above, in connection with a Sole Borrower Transaction, the Borrower Sublimit applicable to such Sole Borrower shall be increased to an amount equal to the total amount of the Commitments as in effect from time to time.

(b)The increase in the Borrower Sublimit for the Sole Borrower shall be effective as of the date (such date being the “Borrower Sublimit Increase Date”) when and if (i) the Sole Borrower Transaction is consummated in accordance with the final sentence of Section 5.03(c) of the Credit Agreement and (ii) the Administrative Agent shall have received the following, each dated as of the Borrower Sublimit Increase Date, in form and substance satisfactory to the Administrative Agent and with one copy for each Lender:

(i)Certified copies of (A) the resolutions of the Board of Directors of the Sole Borrower approving the increase in the Borrower Sublimit and (B) all documents evidencing any other necessary corporate action with respect to the increase in the Borrower Sublimit;

(ii)A certificate of the Secretary or an Assistant Secretary of the Sole Borrower certifying that attached thereto are true and correct copies of all governmental and regulatory authorizations and approvals (including the Approval, as applicable) required for the increase in the Borrower Sublimit;

(iii)Each of the other instruments, agreements, certificates, legal opinions and other documents specified in the final sentence of Section 5.03(c); and

(iv)Such other certifications, opinions, financial or other information, approvals and documents as the Administrative Agent or any other Lender may reasonably request, all in form and substance satisfactory to the Administrative Agent or such other Lender (as the case may be).

Section 4. Representations and Warranties. Each Borrower represents and warrants that (i) the representations and warranties of such Borrower contained in Section 4.01 of the Amended Credit Agreement (with each reference therein to “this Agreement”, “hereunder” and words of like import referring to the Credit Agreement being deemed to be a reference to the Amended Credit Agreement and each reference therein to “Loan Document” and words of like import being deemed to be a reference that includes this Amendment and the Amended Credit Agreement) are true and correct on and as of the Amendment Date as though made on and as of the Amendment Date (other than, as to any such representation or warranty that by its terms refers to a specific date other than

6

the Amendment Date, in which case, such representation and warranty shall be true and correct as of such specific date); and (ii) no event has occurred and is continuing, or would result from the execution, delivery or performance by such Borrower of this Amendment or the performance by such Borrower of the Amended Credit Agreement that constitutes an Event of Default or an Unmatured Default with respect to such Borrower.

Section 5. Effect on the Loan Documents. The execution, delivery and effectiveness of this Amendment shall not, except as expressly set forth herein, operate as a waiver of any right, power or remedy of any Lender, Swing Line Lender or Fronting Bank or the Administrative Agent under the Credit Agreement or any other Loan Document, or constitute a waiver of any provision of the Credit Agreement or any other Loan Document. Except as expressly set forth herein, each of the Credit Agreement and the other Loan Documents is and shall continue to be in full force and effect and is hereby in all respects ratified and confirmed. This Amendment shall constitute a Loan Document and shall be binding on the parties hereto and their respective successors and permitted assigns under the Amended Credit Agreement. Upon and after the execution of this Amendment by each of the parties hereto, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Amended Credit Agreement.

Section 6. Costs, Expenses and Taxes. Each Borrower agrees to pay on demand all reasonable out-of-pocket costs and expenses incurred by the Administrative Agent in connection with the preparation, execution, delivery and syndication administration of this Amendment and the other documents to be delivered hereunder, including, without limitation, the reasonable fees and out‑of‑pocket expenses of counsel for the Administrative Agent with respect thereto and with respect to advising the Administrative Agent as to its rights and responsibilities under this Amendment. Each Borrower further agrees to pay on demand all reasonable out-of-pocket costs and expenses, if any (including, without limitation, reasonable counsel fees and expenses of counsel), incurred by the Administrative Agent and the Lenders in connection with the enforcement (whether through negotiations, legal proceedings or otherwise) of this Amendment, the Amended Credit Agreement and the other documents to be delivered hereunder, including, without limitation, counsel fees and expenses in connection with the enforcement of rights under this Section.

Section 7. Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which when so executed shall be deemed to be an original and all of which taken together shall constitute one and the same agreement.

Section 8. Governing Law. This Amendment shall be governed by, and construed in accordance with, the laws of the State of New York.

If you agree to the foregoing, please evidence such agreement by (i) executing and returning one counterpart of this Amendment by facsimile or e-mail to Kai-Ting Yang (fax no. 212-556-2222; e-mail: kyang@kslaw.com) and (ii) executing and returning five original counterparts to this Amendment by overnight mail to King & Spalding LLP, 1185 Avenue of the Americas, New York, New York 10036, Attention: Kai-Ting Yang.

7

[Remainder of page intentionally left blank.]

Very truly yours,

FIRSTENERGY SOLUTIONS CORP.

By /s/Steven R. Staub            

Steven R. Staub

Vice President and Treasurer

ALLEGHENY ENERGY SUPPLY COMPANY, LLC

By /s/Steven R. Staub            

Steven R. Staub

Vice President and Treasurer

The undersigned hereby agree to the foregoing:

JPMORGAN CHASE BANK, N.A., as Administrative Agent and as a Lender

By /s/Peter Christensen        

Name: Peter Christensen

Title: Vice President

BANK OF AMERICA, N.A., as a Lender

By /s/Jerry Wells            

Name: Jerry Wells

Title: Vice President

THE ROYAL BANK OF SCOTLAND PLC, as a Lender

By /s/Andrew N. Taylor        

Name: Andrew N. Taylor

Title: Vice President

Barclays Bank PLC, as a Lender

By /s/Alicia Borys                     

Name: Alicia Borys

Title: Vice President

CITIBANK, N.A., as a Lender

By /s/D. Scott McMurty        

Name: D. Scott McMurty

Title: Vice President

KeyBank National Association, as a Lender

By /s/Sherrie I. Manson        

Name: Sherrie I. Manson

Title: Senior Vice President

The Bank of Tokyo-Mitsubishi UFJ, Ltd. as a Lender

By /s/Robert MacFarlane        

Name: Robert MacFarlane

Title: VP

UNION BANK, N.A., as a Lender

By /s/Y. Joanne Si            

Name: Y. Joanne Si

Title: Vice President

The Bank of Nova Scotia, as a Lender

By /s/Thane Rattew            

Name: Thane Rattew

Title: Managing Director

Goldman Sachs Bank USA, as a Lender

By /s/Michelle Latzoni        

Name: Michelle Latzoni

Title: Authorized Signatory

MORGAN STANLEY BANK, N.A., as a Lender

By /s/John Durland            

Name: John Durland

Title: Authorized Signatory

CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH, as a Lender

By /s/Vipul Dhadda             

Name: Vipul Dhadda

Title: Authorized Signatory

By /s/Philipp Horst            

Name: Philipp Horst

Title: Authorized Signatory

BNP Paribas, as a Lender

By /s/Dennis O’Meara        

Name: Dennis O’Meara

Title: Managing Director

By /s/Pasquale Perraglia        

Name: Pasquale Perraglia

Title: Director

Royal Bank of Canada, as a Lender

By /s/Frank Lambrinos        

Name: Frank Lambrinos

Title: Authorized Signatory

MIZUHO BANK, LTD., as a Lender

By /s/Raymond Ventura        

Name: Raymond Ventura

Title: Deputy General Manager

SUMITOMO MITSUI BANKING CORPORATION, as a Lender

By /s/James D. Weinstein        

Name: James D. Weinstein

Title: Managing Director

WELLS FARGO BANK, N.A., as a Lender

By /s/Fredrick W. Price        

Name: Fredrick W. Price

Title: Managing Director

U.S. Bank National Association, as a Lender

By /s/Eric J. Cosgrove            

Name: Eric J. Cosgrove

Title: Vice President

PNC Bank, N.A., as a Lender

By /s/Christian S. Brown        

Name: Christian S. Brown

Title: Senior Vice President

The Bank of New York Mellon, as a Lender

By /s/Richard K. Fronapfel, Jr.    

Name: Richard K. Fronapfel, Jr.

Title: Vice President

Canadian Imperial Bank of Commerce, New York Branch, as a Lender

By /s/Gordon R. Eadon         

Name: Gordon R. Eadon

Title: Authorized Signatory

By /s/Robert W. Casey Jr.         

Name: Robert W. Casey Jr.

Title: Authorized Signatory

CREDIT AGRICOLE CORPORATE AND INVESTMENT BANK, as a Lender

By /s/Darrell Stanley            

Name: Darrell Stanley

Title: Managing Director

By /s/David Gurghigian        

Name: David Gurghigian

Title: Managing Director

SOVEREIGN BANK, N.A., as a Lender

By /s/William Maag            

Name: William Maag

Title: Senior Vice President

COBANK, ACB, as a Lender

By /s/Josh Batchelder            

Name: Josh Batchelder

Title: Vice President

BANCO BILBAO VIZCAYA ARGENTINA, S.A. NEW YORK BRANCH, as a Lender

By /s/Luca Sacchi            

Name: Luca Sacchi

Title: Executive Director

By /s/Veronica Incera            

Name: Veronica Incera

Title: Executive Director

THE HUNTINGTON NATIONAL BANK, as a Lender

By /s/Brian H. Gallagher            

Name: Brian H. Gallagher

Title: Senior Vice President

EX-10.2

GUARANTEE

This Guarantee (this “Guarantee”), effective as of September 16th, 2013, is made by FirstEnergy Corp., an Ohio corporation (“FirstEnergy”), in favor of the current and future participants of the FirstEnergy Corp. Executive Deferred Compensation Plan (each, a “Participant” and collectively, the “Participants”).

WHEREAS, FirstEnergy maintains the FirstEnergy Corp. Executive Deferred Compensation Plan (the “Plan”), which provides deferred compensation benefits to certain employees of FirstEnergy and its subsidiaries (each, a “Subsidiary” and collectively, the “Subsidiaries”);

WHEREAS, each Subsidiary is obligated to pay any benefits under the Plan to any Participant who was employed by such Subsidiary to the extent such benefits were accrued while the Participant was employed by such Subsidiary; and

WHEREAS, FirstEnergy desires to guarantee the payment obligations of each Subsidiary under the Plan.

NOW, THEREFORE, FirstEnergy agrees as follows:

1. FirstEnergy does hereby guarantee payment, as provided under the terms of the Plan, of all current and future liabilities of each Subsidiary with respect to any benefit a Participant employed (or formerly employed) by such Subsidiary has accrued or will accrue under the Plan while employed by such Subsidiary.

2. This Guarantee is in addition to the obligations each Subsidiary has under the terms of the Plan and nothing in this Guarantee shall modify any of the terms and conditions of the Plan, including, without limitation, the terms related to the time and form of payment of the benefits payable thereunder.

3. This Guarantee shall be interpreted and the rights and liabilities of the parties hereto determined in accordance with the laws (other than conflicts of law provisions) of the State of Ohio.

GUARANTOR

FIRSTENERGY CORP.

/s/ James F. Pearson

_________________________

James F. Pearson

Senior Vice President and

Chief Financial Officer

EX-12

EXHIBIT 12

FIRSTENERGY CORP.

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Nine Months Ended September 30
	2013		2012
	(Dollars in millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Net income from continuing operations	$	233	$	908
Interest and other charges, before reduction for amounts capitalized and deferred	771		750
Provision for income taxes	129		650
Interest element of rentals charged to income (1)	72		105
Earnings as defined	$	1,205	$	2,413
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	771	$	750
Interest element of rentals charged to income (1)	72		105
Fixed charges as defined	$	843	$	855
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES	1.43		2.82

⁽¹⁾  Includes the interest element of rentals where determinable plus 1/3 of rental expense where no readily defined interest element can be determined.

125

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: November 5, 2013

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

126

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: November 5, 2013

/s/ Donald R. Schneider

Donald R. Schneider

Chief Executive Officer

127

EX-31.2

EXHIBIT 31.2

Certification

I, James F. Pearson, 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: November 5, 2013

/s/ James F. Pearson

James F. Pearson

Chief Financial Officer

128

EXHIBIT 31.2

Certification

I, James F. Pearson, 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: November 5, 2013

/s/ James F. Pearson

James F. Pearson

Chief Financial Officer

129

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 September 30, 2013 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/ James F. Pearson

James F. Pearson

Chief Financial Officer

Date: November 5, 2013

130

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 September 30, 2013 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/ James F. Pearson

James F. Pearson

Chief Financial Officer

Date: November 5, 2013

131

XML

Discontinued Operations and Assets Held for Sale (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets Held-for-sale, Long Lived	$ 234		$ 234		$ 0
Disposal Group, Including Discontinued Operation, Goodwill	29		29
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	12	5	26	19
Disposal Group, Including Discontinued Operation, Revenue	11	6	24	24
FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Assets Held-for-sale, Long Lived	121		121		0
Disposal Group, Including Discontinued Operation, Goodwill	1		1
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax	12	8	22	17
Disposal Group, Including Discontinued Operation, Revenue	$ 10	$ 8	$ 22	$ 18

XML

Pension and Other Postemployment Benefits

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended September 30,	2013			2012			2013			2012
	(In millions)
Service costs	$	49		$	40		$	3		$	3
Interest costs	93			97			9			12
Expected return on plan assets	(125		)	(121		)	(8		)	(9		)
Amortization of prior service costs (credits)	3			3			(50		)	(50		)
Net periodic costs (credits)	$	20		$	19		$	(46	)	$	(44	)

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Nine Months Ended September 30,	2013			2012			2013			2012
	(In millions)
Service costs	$	147		$	120		$	9		$	9
Interest costs	279			291			27			36
Expected return on plan assets	(375		)	(363		)	(24		)	(27		)
Amortization of prior service costs (credits)	9			9			(157		)	(152		)
Net periodic costs (credits)	$	60		$	57		$	(145	)	$	(134	)

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 FES were as follows:

Net Periodic Benefit Expense (Credit)	Pensions				OPEB
For the Three Months Ended September 30,	2013		2012		2013			2012
	(In millions)
FirstEnergy	$	16	$	14	$	(31	)	$	(30	)
FES	5		5		(4		)	(4		)

Net Periodic Benefit Expense (Credit)	Pensions				OPEB
For the Nine Months Ended September 30,	2013		2012		2013			2012
	(In millions)
FirstEnergy	$	41	$	41	$	(95	)	$	(92	)
FES	13		13		(12		)	(12		)

XML

Fair Value Measurements (Details 1) (Level 3, USD $) In Millions, unless otherwise specified	9 Months Ended		12 Months Ended
	Sep. 30, 2013		Dec. 31, 2012
Non Utility Generation Contract
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	$ 36	[1]	$ 57	[1]
Beginning Balance, Derivative Liabilities	(290)	[1]	(349)	[1]
Beginning Balance, Net	(254)	[1]	(292)	[1]
Unrealized gain (loss), Derivative Assets	(6)	[1]	(20)	[1]
Unrealized gain (loss), Derivative Liabilities	(6)	[1]	(180)	[1]
Unrealized gain (loss), Net	(12)	[1]	(200)	[1]
Purchases, Derivative Assets	0	[1]	0	[1]
Purchases, Derivative Liabilities	0	[1]	0	[1]
Purchases, Net	0	[1]	0	[1]
Settlements, Derivative Assets	(7)	[1]	(1)	[1]
Settlements, Derivative Liabilities	63	[1]	239	[1]
Settlements, Net	56	[1]	238	[1]
Ending Balance, Derivative Assets	23	[1]	36	[1]
Ending Balance, Derivative Liabilities	(233)	[1]	(290)	[1]
Ending Balance, Net	(210)	[1]	(254)	[1]
LCAPP Contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	0	[1]	0	[1]
Beginning Balance, Derivative Liabilities	(144)	[1]	0	[1]
Beginning Balance, Net	(144)	[1]	0	[1]
Unrealized gain (loss), Derivative Assets	0	[1]	0	[1]
Unrealized gain (loss), Derivative Liabilities	(22)	[1]	1	[1]
Unrealized gain (loss), Net	(22)	[1]	1	[1]
Purchases, Derivative Assets	0	[1]	0	[1]
Purchases, Derivative Liabilities	0	[1]	(145)	[1]
Purchases, Net	0	[1]	(145)	[1]
Settlements, Derivative Assets	0	[1]	0	[1]
Settlements, Derivative Liabilities	0	[1]	0	[1]
Settlements, Net	0	[1]	0	[1]
Ending Balance, Derivative Assets	0	[1]	0	[1]
Ending Balance, Derivative Liabilities	(166)	[1]	(144)	[1]
Ending Balance, Net	(166)	[1]	(144)	[1]
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	8		1
Beginning Balance, Derivative Liabilities	(9)		(23)
Beginning Balance, Net	(1)		(22)
Unrealized gain (loss), Derivative Assets	1		6
Unrealized gain (loss), Derivative Liabilities	2		(6)
Unrealized gain (loss), Net	3		0
Purchases, Derivative Assets	5		13
Purchases, Derivative Liabilities	(15)		(10)
Purchases, Net	(10)		3
Settlements, Derivative Assets	(11)		(12)
Settlements, Derivative Liabilities	8		30
Settlements, Net	(3)		18
Ending Balance, Derivative Assets	3		8
Ending Balance, Derivative Liabilities	(14)		(9)
Ending Balance, Net	(11)		(1)
FTRs | FES
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	6		1
Beginning Balance, Derivative Liabilities	(6)		(7)
Beginning Balance, Net	0		(6)
Unrealized gain (loss), Derivative Assets	(1)		4
Unrealized gain (loss), Derivative Liabilities	(1)		(4)
Unrealized gain (loss), Net	(2)		0
Purchases, Derivative Assets	4		9
Purchases, Derivative Liabilities	(12)		(7)
Purchases, Net	(8)		2
Settlements, Derivative Assets	(7)		(8)
Settlements, Derivative Liabilities	6		12
Settlements, Net	(1)		4
Ending Balance, Derivative Assets	2		6
Ending Balance, Derivative Liabilities	(13)		(6)
Ending Balance, Net	$ (11)		$ 0

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

XML

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Statement of Other Comprehensive Income [Abstract]
NET INCOME	$ 218	$ 425	$ 250	$ 919
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(47)	(47)	(148)	(148)
Amortized losses on derivative hedges	2	0	4	1
Change in unrealized gain on available-for-sale securities	6	1	3	13
Other comprehensive income (loss)	(39)	(46)	(141)	(134)
Income tax benefits on other comprehensive loss	(15)	(24)	(55)	(75)
Net other comprehensive income (loss)	(24)	(22)	(86)	(59)
COMPREHENSIVE INCOME (LOSS)	194	403	164	860
Comprehensive income attributable to noncontrolling interest	0	0	0	1
COMPREHENSIVE INCOME AVAILABLE TO FIRSTENERGY CORP.	$ 194	$ 403	$ 164	$ 859

XML

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 222	$ 172
Receivables-
Customers, net of allowance for uncollectible accounts of $14 in 2013 and $16 in 2012	1,579	1,614
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012	231	315
Materials and supplies	731	861
Derivatives	140	160
Prepayments and other	262	208
Total current assets	3,559	3,768
PROPERTY, PLANT AND EQUIPMENT:
In service	44,089	43,210
Less - Accumulated provision for depreciation	13,167	12,600
Property, plant and equipment in service net of accumulated provision for depreciation	30,922	30,610
Construction work in progress	2,301	2,293
Total net property, plant and equipment	33,223	32,903
INVESTMENTS:
Nuclear plant decommissioning trusts	2,183	2,204
Other	876	936
Total other property and investments	3,105	3,194
ASSETS HELD FOR SALE (NOTE 16)	234	0
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,447
Other	1,698	1,719
Total deferred charges and other assets	10,262	10,541
Total assets	50,383	50,406
CURRENT LIABILITIES:
Currently payable long-term debt	1,889	1,999
Short-term borrowings	3,404	1,969
Accounts payable-
Accrued taxes	401	543
Derivatives	105	126
Other	872	1,038
Total current liabilities	7,955	7,605
Common stockholders' equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding	42	42
Accumulated other comprehensive income	299	385
Retained earnings	2,448	2,888
Total common stockholders' equity	12,544	13,084
Long-term debt and other long-term obligations	15,291	15,179
Total capitalization	27,838	28,272
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	866	892
Accumulated deferred income taxes	6,603	6,616
Asset retirement obligations	1,834	1,599
Retirement benefits	3,104	3,080
Other	1,716	1,836
Total noncurrent liabilities	14,590	14,529
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
Total liabilities and capitalization	50,383	50,406
FES
CURRENT ASSETS:
Cash and cash equivalents	2	3
Receivables-
Customers, net of allowance for uncollectible accounts of $14 in 2013 and $16 in 2012	524	483
Affiliated companies	519	379
Other, net of allowance for uncollectible accounts of $3 in 2013 and $2 in 2012	123	91
Notes receivable from affiliated companies	254	276
Materials and supplies	439	505
Derivatives	139	158
Prepayments and other	105	87
Total current assets	2,105	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	12,508	11,997
Less - Accumulated provision for depreciation	4,649	4,408
Property, plant and equipment in service net of accumulated provision for depreciation	7,859	7,589
Construction work in progress	1,116	1,141
Total net property, plant and equipment	8,975	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	1,270	1,283
Other	11	12
Total other property and investments	1,281	1,295
ASSETS HELD FOR SALE (NOTE 16)	121	0
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	99	110
Goodwill	23	24
Property taxes	36	36
Unamortized sale and leaseback costs	161	119
Derivatives	65	99
Other	268	253
Total deferred charges and other assets	652	641
Total assets	13,134	12,648
CURRENT LIABILITIES:
Currently payable long-term debt	859	1,102
Short-term borrowings	4	4
Accounts payable-
Affiliated companies	776	726
Other	213	159
Accrued taxes	42	171
Derivatives	103	124
Other	176	280
Total current liabilities	2,173	2,566
Common stockholders' equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding	3,078	1,573
Accumulated other comprehensive income	62	72
Retained earnings	2,089	2,118
Total common stockholders' equity	5,229	3,763
Long-term debt and other long-term obligations	2,178	3,118
Total capitalization	7,407	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	866	892
Accumulated deferred income taxes	699	515
Asset retirement obligations	1,159	965
Retirement benefits	255	241
Derivatives	22	37
Other	553	551
Total noncurrent liabilities	3,554	3,201
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
Total liabilities and capitalization	$ 13,134	$ 12,648

XML

Regulatory Matters

9 Months Ended

Sep. 30, 2013

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.

As competitive retail electric suppliers serving retail customers primarily in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland, FES and AE Supply are subject to state laws applicable to competitive electric suppliers in those states, including affiliate codes of conduct that apply to FES, AE Supply and their public utility affiliates.In addition, if FES, AE Supply or any of their subsidiaries were to engage in the construction of significant new generation facilities in any of those states, they would also be subject to state siting authority.

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 that are overseen by the MDPSC and a third party monitor.Although settlements with respect to residential SOS for PE customers expired on December 31, 2012, by statute, service continues in the same manner unless changed by order of the MDPSC.The settlement provisions relating to non-residential SOS have also expired, however, 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.PE's initial plan submitted in compliance with the statute was approved in 2009 and covered 2009-2011, the first three years of the statutory period.Expenditures were originally estimated to be approximately$101 millionfor the PE programs for the entire period of 2009-2015.Meanwhile, after extensive meetings with the MDPSC Staff and other stakeholders, on August 31, 2011, PE filed a new comprehensive plan for the second three year period, 2012-2014, that includes additional and improved programs.The 2012-2014 plan is expected to cost approximately$66 millionout of the original$101 millionestimate for the entire EmPOWER program.On December 22, 2011, the MDPSC issued an order approving PE's second plan with various modifications and follow-up assignments.PE continues to recover program costs subject to afive-year amortization.Maryland law only allows for the utility to recover lost distribution revenue attributable to 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.

Pursuant to a bill passed by the Maryland legislature in 2011, the MDPSC adopted rules, effective May 28, 2012, 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 MDPSC will be required to assess each utility's compliance with the new rules, and may assess penalties of up to$25,000per day, per violation.The new rules set utility-specific SAIDI and SAIFI targets for 2012-2015; prescribe detailed tree-trimming requirements, outage restoration and downed wire response deadlines; and impose other reliability and customer satisfaction requirements.PE has advised the MDPSC that compliance with the new rules is expected to increase costs by approximately$106 millionover the period 2012-2015.On April 1, 2013, the Maryland electric utilities, including PE, filed their first annual reports on compliance with the new rules.The MDPSC conducted a hearing on August 20, 2013 to discuss the reports, after which an order was issued on September 3, 2013, which accepted PE's filing and the operational changes proposed therein.

Following a "derecho" storm through the region on June 29, 2012, the MDPSC convened a new proceeding to consider matters relating to the electric utilities' performance in responding to the storm.Hearings on the matter were conducted in September 2012.Concurrently, Maryland's governor convened a special panel to examine possible ways to improve the resilience of the electric distribution system.On October 3, 2012, that panel issued a report calling for various measures including: acceleration and expansion of some of the requirements contained in the reliability standards which had become final on May 28, 2012; for selective increased investment in system hardening; for creation of separate recovery mechanisms for the costs of those changes and investments; and penalties or bonuses on returns earned by the utilities based on their reliability performance.On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the utilities to submit several reports over a series of months, relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations.The order further requires the Staff of the MDPSC to report on possible performance-based rate structures and to propose additional rules relating to feeder performance standards, outage communication and reporting, and sharing of special needs customer information.PE has responded to the requirements in the order consistent with the schedule set forth therein.PE's final filing on September 3, 2013, discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 27 Order, and projected that it would expect to make approximately$2.7 billionin infrastructure investments over15years to attempt to achieve the quickest level of response for the largest storm projected in the February 27 Order.The MDPSC has ordered that certain reports of its Staff relating to these matters be provided by May 1, 2014, and otherwise, has not issued a schedule for further proceedings in this matter.

NEW JERSEY

JCP&L currently provides BGS for retail customers who do not choose a third party EGS and for customers of third party EGSs that fail to provide the contracted service.The supply for BGS, which is comprised oftwocomponents, is provided through contracts procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU.OneBGS 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.

On September 7, 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, the NJBPU found that a base rate proceeding "will assure that JCP&L's rates are just and reasonable and that JCP&L 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.The rate case petition was filed on November 30, 2012.In the filing, JCP&L requested approval to increase its revenues by approximately$31.5 millionand reserved the right to update the filing to include costs associated with the impact of Hurricane Sandy.The NJBPU has transmitted the case to the New Jersey Office of Administrative Law for further proceedings and an ALJ has been assigned.On February 22, 2013, JCP&L updated its filing to request recovery of$603 millionof distribution-related Hurricane Sandy restoration costs, resulting in increasing the total revenues requested to approximately$112 million.On June 14, 2013, JCP&L further updated its filing to: 1) include the impact of a depreciation study which had been directed by the NJBPU; 2) remove costs associated with 2012 major storms, consistent with the NJBPU orders establishing a generic proceeding to review 2011 and 2012 major storm costs (discussed below); and 3) reflect other revisions to JCP&L's filing.That filing represented an increase of approximately$20.6 millionover the revenues produced by existing base rates.Testimony has also been filed in the matter by the Division of Rate Counsel and several other intervening parties in opposition to the base rate increase JCP&L requested. Specifically, the testimony of the Division of Rate Counsel's witnesses recommended that revenues produced by JCP&L's base rates for electric service be reduced by approximately$202.8 million(such amount did not address the revenue requirements associated with major storm events of 2011 and 2012, which are subject to review in the generic proceeding).JCP&L filed rebuttal testimony in response to the testimony of other parties on August 7, 2013. Hearings in the rate case have commenced and are scheduled to continue through mid-November.

On March 20, 2013, the NJBPU ordered that a generic proceeding be established to investigate the prudence of costs incurred by all New Jersey utilities for service restoration efforts associated with the major storm events of 2011 and 2012.The Order provided that if any utility had already filed a proceeding for recovery of such storm costs, to the extent the amount of approved recovery had not yet been determined, the prudence of such costs would be reviewed in the generic proceeding.On May 31, 2013, the NJBPU clarified its earlier order to indicate that the 2011 major storm costs would be reviewed expeditiously in the generic proceeding with the goal of maintaining the base rate case schedule established by the ALJ where recovery of such costs would be addressed.The NJBPU further indicated in the May 31 clarification that it would review the 2012 major storm costs in the generic proceeding and the recovery of such costs would be considered through a Phase II in the existing base rate case or through another appropriate method to be determined at the conclusion of the generic proceeding.On June 21, 2013, consistent with NJBPU's orders, JCP&L filed the detailed report in support of recovery of major storm costs with the NJBPU.On October 23, 2013, a prehearing order was issued and established that evidentiary hearings in this proceeding will be held in January 2014. JCP&L intends to vigorously pursue its position in the base rate case and full recovery of the costs associated with the major storm events of 2011 and 2012 but we cannot predict the outcome of these proceedings.

Pursuant to a formal Notice issued by the NJBPU on September 14, 2011, public hearings were held in September 2011 to solicit comments regarding the state of preparedness and responsiveness of New Jersey's EDCs prior to, during, and after Hurricane Irene, with additional hearings held in October 2011.Additionally, the NJBPU accepted written comments through October 28, 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 consultant's report was submitted to and subsequently accepted by the NJBPU on September 12, 2012.JCP&L submitted written comments on the report.On January 24, 2013, based upon recommendations in its consultant's report, the NJBPU ordered the New Jersey EDCs to take a number of specific actions to improve their preparedness and responses to major storms.The order includes specific deadlines for implementation of measures with respect to preparedness efforts, communications, restoration and response, post event and underlying infrastructure issues.On May 31, 2013, the NJBPU ordered that the New Jersey EDCs implement a series of new communications enhancements intended to develop more effective communications among EDCs, municipal officials, customers and the NJBPU during extreme weather events and other expected periods of extended service interruptions.The new requirements include making information regarding estimated times of restoration available on the EDC's web sites and through other technological expedients.JCP&L is implementing the required measures consistent with the schedule set out in the above NJBPU's orders.

OHIO

The Ohio Companies primarily operate under an ESP, which expires on May 31, 2014. The material terms of the ESP include:

• Generation supplied through a CBP;

• 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 thefive-year period from June 1, 2011 through May 31, 2016 or when the amount of costs avoided by customers for certain types of products totals$360 million, subject to the outcome of certain PJM proceedings.The Ohio Companies have also agreed to establish a$12 millionfund 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 fortwoyears.The ESP 3 Application was approved by the PUCO on July 18, 2012.Several parties timely filed applications for rehearing.The PUCO issued an Entry on Rehearing on January 30, 2013 denying all applications for rehearing.Notices of appeal to the Supreme Court of Ohio were filed bytwoparties in the case, Northeast Ohio Public Energy Council and the ELPC.The matter has not yet been scheduled for oral argument.

As approved, the ESP 3 plan continues certain provisions from the current ESP including:

• Continuing the current base distribution rate freeze through May 31, 2016;

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

• A6%generation rate 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);

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

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

As approved, the ESP 3 plan will provide additional provisions, including:

• Securing generation supply for a longer period of time by conducting an auction for athree-year period rather than aone-year period, in each of October 2012 and January 2013, to mitigate any potential price spikes for the Ohio Companies' utility customers who do not switch to a competitive generation supplier; and

• Extending the recovery period for costs associated with purchasing RECs mandated by SB221 through the end of the new ESP 3 period. This is expected to initially reduce the monthly renewable energy charge for all non-shopping utility customers of the Ohio Companies by spreading out the costs over the entire ESP period.

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.The Ohio Companies were also required to reduce peak demand in 2009 by1%, with an additional0.75%reduction each year thereafter through 2018.On May 15, 2013, the Ohio Companies filed their 2012 Status Update Report in which they indicated compliance with 2012 statutory energy efficiency and peak demand reduction benchmarks.

In accordance with PUCO Rules and a PUCO directive, the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015 on July 31, 2012.Estimated costs for thethreeOhio Companies' plans total approximately$250 millionover the three-year period, which is expected to be recovered in rates to the extent approved by the PUCO.Hearings were held with the PUCO in October 2012.On March 20, 2013, the PUCO approved the three-year portfolio plan for 2013-2015.Applications for rehearing were filed by the Ohio Companies and several other parties on April 19, 2013.The Ohio Companies filed their request for rehearing primarily to challenge the PUCO's decision to mandate that they offer planned energy efficiency resources into PJM's base residual auction.On May 15, 2013, the PUCO granted the applications for rehearing for the sole purpose of further consideration of the matter.On July 17, 2013, the PUCO issued an entry on rehearing denying the Ohio Companies' application for rehearing, in part, but authorizing the Ohio Companies' to receive20%of any revenues obtained from bidding energy efficiency and demand response reserves into the PJM auction.The PUCO also confirmed that the Ohio Companies can recover PJM costs and applicable penalties associated with PJM auctions, including the costs of purchasing replacement capacity from PJM incremental auctions, to the extent that such costs or penalties are prudently incurred.On August 16, 2013, ELPC and OCC filed applications for rehearing under the basis that the PUCO's authorization for the Ohio Companies to share in the PJM revenues was unlawful.The PUCO granted rehearing on September 11, 2013 for the sole purpose of further consideration of the issue.

On September 16, 2013, the Ohio Companies filed with the Supreme Court of Ohio a notice of appeal of the PUCO's July 17, 2013 Entry on Rehearing related to energy efficiency, alternative energy, and long-term forecast rules stating that the rules issued by the PUCO are inconsistent with and are not supported by statutory authority. On October 23, 2013, the PUCO filed a motion to dismiss the appeal. The Ohio Companies' response was filed on November 4, 2013.

Additionally, under SB221, electric utilities and electric service companies in Ohio are required to serve part of their load from renewable energy resources measured by an annually increasing percentage amount.In August and October 2009 and in August 2010, the Ohio Companies conducted RFPs to secure RECs.The RECs acquired through thesethreeRFPs were used to help meet the renewable energy requirements established under SB221 for 2009, 2010 and 2011. In August 2011, the Ohio Companies conductedtwoRFP processes to obtain RECs to meet the statutory benchmarks for 2011 and contribute toward meeting the benchmark for future years.On September 20, 2011 the PUCO opened a new docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies will recover the costs of acquiring these RECs.The PUCO selected auditors to perform a financial and management audit, and final audit reports were filed with the PUCO on August 15, 2012.While generally supportive of the Ohio Companies' approach to procurement of RECs, the management/performance auditor recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state all renewable obligations that the auditor characterized as excessive.A hearing for this matter commenced on February 19, 2013, and concluded on February 25, 2013.The PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of renewable energy credits to meet statutory mandates in all instances except for part of the purchases arising from one auction and directing the Ohio Companies to credit non-shopping customers in the amount of$43.3 million, plus interest, with such crediting to commence within60days following the issuance of a final appealable order on the basis that the Ohio Companies did not prove such purchases were prudent.The Ohio Companies, along with other parties, timely filed applications for rehearing on September 6, 2013. On September 18, 2013, the PUCO issued an entry on rehearing granting rehearing solely for the purpose of further consideration of the matters specified therein.

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 achieved their in-state solar compliance requirements for 2012.The Ohio Companies also held a short-term RFP process to obtain all state SRECs and both in-state and all state non-solar RECs to help meet the statutory benchmarks for 2012.The Companies recently reported that all of the Ohio Companies met their annual renewable energy resource requirements for reporting year 2012.The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.

The PUCO instituted a statewide investigation on December 12, 2012 to evaluate the vitality of the competitive retail electric service market in Ohio.The PUCO provided interested stakeholders the opportunity to provide comments ontwenty-twoquestions.The questions posed are categorized as market design and corporate separation.The Ohio Companies timely filed their comments on March 1, 2013, and filed reply comments on April 5, 2013.The PUCO has scheduled a series of workshops for the remainder of 2013, the first of which commenced on July 9, 2013.The Ohio Companies cannot predict the outcome of this investigation.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expired on May 31, 2013, and provide for the competitive procurement of generation supply for customers that do not choose an alternative EGS or for customers of alternative EGSs 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 DSPs 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.The PPUC entered an opinion and order on August 16, 2012, which primarily resolved those issues related to procurement and rate design, but required the submission of revised proposals regarding the retail market enhancement programs.The Pennsylvania Companies filed revised proposals on the retail market enhancements on November 14, 2012.A final order was entered on February 15, 2013, which addressed minor changes to the Pennsylvania Companies' revised enhancement proposals and ordered two choices for cost recovery of those programs.On February 28, 2013, the Pennsylvania Companies filed a petition to amend the August 16, 2012, order related to the description of how the hourly industrial product is to be priced.On April 4, 2013, the PPUC entered a Final Order postponing the implementation ofoneof the retail market enhancements.On March 20, 2013, answers supporting and opposing the Pennsylvania Companies' February 28 petition were filed by several parties.On July 16, 2013, the PPUC entered an order granting the Pennsylvania Companies' February 28, 2013 petition, thereby amending its August 16, 2012 order and clarifying the description of the hourly industrial product pricing. The Pennsylvania Companies are actively implementing their DSPs as of June 1, 2013. On November 4, 2013, the Pennsylvania Companies filed a default service plan that will provide the method by which they will procure the supply for their default service obligations for the period of June 1, 2015 through May 31, 2017. The Pennsylvania Companies proposed programs call for quarterly descending clock auctions to procure 3, 12, 24, and 48-month energy contracts, as well as, one RFP seeking 2-year contracts to secure solar renewable energy credits for ME, PN, and Penn. The Pennsylvania Companies expect a decision from the PPUC within nine months.

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 refunded those amounts to customers over a29-month period that began in January of 2011.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's and PN's TSC riders.The Pennsylvania Supreme Court denied ME's and PN's Petition for Allowance of Appeal on February 28, 2012, and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari on October 9, 2012.On July 13, 2011, ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania for the purpose of obtaining an order that would enjoin enforcement of the PPUC and Pennsylvania court orders under a theory of federal preemption on the question of retail rate recovery of the marginal transmission loss charges.Proceedings in the U.S. District Court effectively were suspended until conclusion of the proceedings before the United States Supreme Court.Pursuant to procedural orders issued by U.S. District Court Judge Gardner, on December 21, 2012, the PPUC submitted its motion to dismiss the U.S. District Court proceedings.ME and PN submitted their answers on January 9, 2013, and subsequent pleadings were submitted by the PPUC, ME and PN.Oral arguments on the PPUC motion to dismiss took place on May 20, 2013.On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss. On October 29, 2013, ME and PN filed a notice of appeal in the U.S. Court of Appeals for the Third Circuit with respect to the U.S. District Court's decision.As a result of the U.S. District Court's September 30, 2013 decision, FirstEnergy recorded a regulatory asset impairment charge of approximately$254 million(pre-tax) in the quarter ended September 30, 2013 included in Amortization of regulatory assets, net within the Consolidated Statement of Income. FirstEnergy continues to believe in the merits of its case.

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.

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 on utilities that fail to achieve the required reductions in consumption and peak demand.The Pennsylvania Companies submitted an interim 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 did not.WP could be subject to a statutory penalty of up to$20 millionand is unable to predict the outcome of this matter.On July 15, 2013, the Pennsylvania Companies filed their preliminary energy efficiency and demand reduction results for the period ending May 31, 2013, indicating that all Pennsylvania Companies are expected to meet their statutory obligations.The Pennsylvania Companies are expected to report their final energy efficiency and demand reduction results for the period ending May 31, 2013, by November 15, 2013.

Pursuant to Act 129, the PPUC was charged with reviewing the cost effectiveness of energy efficiency and peak demand reduction programs.The PPUC found the energy efficiency programs to be cost effective and in an Order entered on August 3, 2012, the PPUC directed all of the electric utilities in Pennsylvania to submit by November 15, 2012, a Phase II EE&C Plan that would be in effect for the period June 1, 2013 through May 31, 2016.The PPUC has deferred ruling on the need to create peak demand reduction targets until it receives more information from the EE&C statewide evaluator.The Pennsylvania Companies filed their Phase II plans and supporting testimony in November 2012.On January 16, 2013, the Pennsylvania Companies reached a settlement with all but one party on all but one issue.The settlement provides for the Pennsylvania Companies to meet with interested parties to discuss ways to expand upon the EE&C programs and incorporate any such enhancements after the plans are approved, provided that these enhancements will not jeopardize the Pennsylvania Companies' compliance with their required targets or exceed the statutory spending caps.On February 6, 2013, the Pennsylvania Companies filed revised Phase II EE&C Plans to conform the plans to the terms of the settlement.Total costs of these plans are expected to be approximately$234 million.All such costs are expected to be recoverable through the Pennsylvania Companies reconcilable Phase II EE&C Plan C riders.The remaining issue, raised by a natural gas company, involved the recommendation that the Pennsylvania Companies include in their plans incentives for natural gas space and water heating appliances.On March 14, 2013 the PPUC approved the 2013-2016 EE&C plans of the Pennsylvania Companies, adopting the settlement, and rejecting the natural gas companies recommendations.

In addition, Act 129 required utilities to file a SMIP with the PPUC.On December 31, 2012, the Pennsylvania Companies filed their Smart Meter Deployment Plan.The Deployment Plan requests deployment of approximately98.5%of the smart meters to be installed over the period 2013 to 2019, and the remaining meters in difficult to reach locations to be installed by 2022, with an estimated life cycle cost of about$1.25 billion.Such costs are expected to be recovered through the Pennsylvania Companies' PPUC-approved Riders SMT-C.Evidentiary hearings have been held and briefs were submitted by the Pennsylvania Companies and the Office of Consumer Advocate.

In the PPUC Order approving the FirstEnergy and Allegheny merger, the PPUC announced that a separate statewide investigation into Pennsylvania's retail electricity market would 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 onelevendirected 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.A final order was issued on February 15, 2013 providing recommendations on the entities to provide default service, the products to be offered, billing options, customer education, and licensing fees and assessments, among other items.Subsequently, the PPUC establishedfiveworkgroups andonecomment proceeding in order to seek resolution of certain matters and to clarify certain obligations that arose from that order.

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 electricity 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 the Pennsylvania Companies and FES on March 27, 2012.If implemented these rules could require a significant change in the ways FES and the Pennsylvania Companies 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 the proposed rulemaking on April 26, 2012, 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.The House Consumer Affairs Committee of the Pennsylvania General Assembly also sent a letter to the Independent Regulatory Review Commission on July 12, 2012, noting its opposition to the proposed regulations as modified.

WEST VIRGINIA

MP and PE currently operate under a Joint Stipulation and Agreement of Settlement reached with the other parties and approved by the WVPSC in June 2010 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.

In February 2011, MP and PE filed a petition with the WVPSC seeking an order declaring that MP owns all RECs associated with the 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, opposed the petition.On November 22, 2011, the WVPSC granted ownership of all RECs produced by the facilities to MP, and held that an electric utility that purchases electric energy and capacity under an electric power purchase agreement with a Qualifying Facility under PURPA owns the RECs associated with that purchase.The West Virginia Supreme Court upheld the WVPSC's decision.The City of New Martinsville and Morgantown Energy Associates filed petitions at FERC alleging the WVPSC order violated PURPA and requested that FERC initiate an enforcement action.On April 24, 2012, FERC issued an order declining to act on the petitions and instead noted that the City of New Martinsville and Morgantown Energy Associates could file complaints in the U.S. District Court.MP and PE filed for rehearing of FERC's order, which was denied on September 20, 2012.The City of New Martinsville filed a complaint in the U.S. District Court for the Southern District of West Virginia on June 1, 2012, alleging that the WVPSC order violates PURPA.Morgantown Energy Associates has joined in filing a similar complaint and requesting damages in the same U.S. District Court.MP and PE filed for judgment on the pleadings in both cases on January 25, 2013.The WVPSC filed a motion to dismiss on June 28, 2013.On September 30, 2013, the District Court ruled in favor of MP and PE and the WVPSC and dismissed the proceedings with prejudice.

The WVPSC opened a general investigation into the June 29, 2012, derecho windstorm with data requests for all utilities.A public meeting for presentations on utility responses and restoration efforts was held on October 22, 2012 and two public input hearings have been held.The WVPSC issued an Order in this matter on January 23, 2013 closing the proceeding and directing electric utilities to file a vegetation management plan withinsix monthsand to propose a cost recovery mechanism.This Order also requires MP and PE to file a status report regarding improvements to their storm response procedures by the same date.On July 23, 2013, MP and PE filed their vegetation management plans, which provided for recovery of costs through a surcharge mechanism.On October 3, 2013, the WVPSC issued a procedural schedule for the vegetation management plan proceeding and scheduled a hearing for December 3, 2013.

MP and PE filed their Resource Plan with the WVPSC in August 2012 detailing both supply and demand forecasts and noting a substantial capacity deficiency.MP and PE have filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposes a net ownership transfer of1,476MW of coal-fired generation capacity to MP.The proposed transfer would involve MP's acquisition of the remaining ownership of the Harrison Power Station from AE Supply and the sale of MP's minority interest in the Pleasants Power Station to AE Supply.The proposed transfer would implement a cost-effective plan to assist MP in meeting its energy and capacity obligations with its own generation resources, eliminating the need to make unhedged electricity and capacity purchases from the spot market, which is expected to result in greater rate stability for MP's customers.The plan is expected to remedy MP's capacity and energy shortfalls, which are projected to worsen due to a projected increase in annual load growth of approximately1.4%.MP and PE will file a base rate case no later thansix monthsfrom the completion of the transaction.On February 11, 2013, the WVPSC issued an order adopting a procedural schedule for this matter and testimony and briefing has followed.MP and PE also filed with FERC for authorization to effect these transfers and on April 23, 2013, FERC issued an order authorizing the transfers.MP's application for FERC authorization to effect the financing was approved on May 13, 2013.Hearings were held at the WVPSC in late May and briefs and reply briefs have been submitted.A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013.On October 7, 2013, WVPSC issued an order authorizing the transaction, with certain conditions and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately$330 millionin the fourth quarter of 2013 to reduce the net book value of the Harrison Power Station to the amount that was permitted to be included in jurisdictional rate base.Additionally, MP recognized a regulatory liability of approximately$23 millionin the fourth quarter of 2013 representing refunds to customers associated with the excess purchase price received by MP above the net book value of MP's minority interest in the Pleasants Power Station. The transaction resulted in AE Supply receiving net consideration of $1.1 billion and MP's assumption of a $73.5 million pollution control note. Currently, the $1.1 billion net consideration was financed by MP through an equity infusion from FE of approximately $527 million and a note payable to AE Supply of approximately $573 million.

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, FG, FENOC, ATSI and TrAIL.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 toeightregional 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.Any 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.

FERC MATTERS

PJM Transmission Rate

PJM and its stakeholders have been debating the proper method to allocate costs for new transmission facilities.While FirstEnergy and other parties advocated for a traditional "beneficiary pays" (or usage based) 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.On August 6, 2009, 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 LSEs in PJM bearing the majority of the costs.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 (or socialized) 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 and on March 22, 2013, FERC denied rehearing.On March 29, 2013, FirstEnergy filed its Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated for briefing and disposition before that court. Briefing commenced on September 11, 2013, and is expected to continue into early 2014.Thereafter, the case will be scheduled for oral argument, with a decision currently expected in 2014.

Order No. 1000, issued by FERC on July 21, 2011, required the submission of a compliance filing by PJM or the PJM transmission owners demonstrating that the cost allocation methodology for new transmission projects directed by the PJM Board of Managers satisfied the principles set forth in the order.To demonstrate compliance with the regional cost allocation principles of the order, the PJM transmission owners, including FirstEnergy, submitted a filing to FERC on October 11, 2012, proposing a hybrid method of50%beneficiary pays and50%postage stamp to be effective for RTEP projects approved by the PJM Board of Managers on, and after, the effective date of the compliance filing.On January 31, 2013, FERC conditionally accepted the hybrid method to be effective on February 1, 2013, subject to refund and to a future order on PJM's separate Order No. 1000 compliance filing.On March 22, 2013, FERC granted final acceptance of the hybrid method.Certain parties have sought rehearing of parts of FERC's March 22, 2013 order.These requests for rehearing are pending before FERC.On July 10, 2013, the PJM transmission owners, including FirstEnergy, submitted filings to FERC setting forth the cost allocation method for projects that cross the borders between: (1) the PJM region and the New York Independent System Operator region and; (2) the PJM region and the FERC-jurisdictional members of the Southeastern Regional Transmission Planning region.These filings propose to allocate the cost of these interregional transmission projects based on the costs of projects that otherwise would have been constructed separately in each region.On the same date, also in response to Order No. 1000, the PJM transmission owners, including FirstEnergy, also submitted to FERC a filing stating that the cost allocation provisions for interregional transmission projects provided in the Joint Operating Agreement between PJM and MISO comply with the requirements of Order No. 1000.The July 10, 2013 filings are pending before FERC.

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 the dispute are discussed below under "MISO Multi-Value Project Rule Proposal."In addition, FERC denied recovery of certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation issues by means of ATSI's transmission rate totaling approximately$78.8 millionuntil 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.On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve certain of the exit fee and transmission cost allocation issues that are outstanding with regard to ATSI's transmission rate revisions related to ATSI's move into PJM.On September 19, 2013, FERC rejected that settlement stating ATSI had not shown why its tariff changes are just and reasonable. FERC further stated, consistent with its initial May 31, 2011 ruling on this issue that its September 19, 2013 order is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the costs that are sought to be recovered in ATSI's transmission rates.On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

In the May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM could be charged to transmission customers in the ATSI zone.ATSI sought rehearing of the question of whether the ATSI zone should pay these legacy RTEP charges and, on September 20, 2012, FERC denied ATSI's request for rehearing.On November 19, 2012, ATSI filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit of FERC's ruling on the "legacy RTEP" issue, and ATSI's initial brief was filed with that court on April 11, 2013.FERC filed its brief on June 25, 2013, and FirstEnergy filed its reply brief on August 9, 2013, and final reply brief on August 28, 2013.FERC filed its final brief on August 30, 2013. The court has scheduled oral argument for December 11, 2013, and a decision is expected in the second quarter of 2014.

The 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 project that was approved by MISO's Board prior to the June 1, 2011 effective date of FirstEnergy's integration into PJM would be allocated to and charged to ATSI.MISO estimated that approximately$16 millionin annual revenue requirements associated with the Michigan Thumb Project would be allocated to the ATSI zone upon completion of project construction.In addition, the MISO's MVP tariffs could assess costs on PJM loads that purchase energy that has flowed over the transmission systems into the MISO.

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.FirstEnergy asserts legal, factual and policy arguments.To date, FERC has responded in a series of orders that may require ATSI to absorb the charges for the Michigan Thumb Project pending the outcome of further regulatory proceedings and appeals.These further proceedings can be divided into two tracks: litigation related to MISO's generic MVP cost allocation proposal; and litigation related to MISO's "Schedule 39" tariff that purports to charge the MVP costs to ATSI.

Regarding the first litigation track, in 2010 and 2011 FERC issued orders that approved the MISO proposal.On October 31, 2011, FirstEnergy filed a Petition of Review of those 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 appeals were consolidated for briefing and disposition in the U.S. Court of Appeals for the Seventh Circuit.Briefs were filed in late 2012 and early 2013, and the court heard oral arguments on April 10, 2013.On June 7, 2013, the Seventh Circuit issued an order that ratified FERC's acceptance of the MISO's proposed MVP tariff.On October 7, 2013, several parties, including FirstEnergy, filed appeals of the Seventh Circuit's decision with the U.S. Supreme Court.FirstEnergy continues to evaluate the Seventh Circuit's order and its substantive and procedural options on other holdings in the opinion.

Regarding the second litigation track, in February 2012, FERC accepted the MISO's proposed Schedule 39 tariff, subject to hearings and potential refund of MVP charges to ATSI.FERC 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.The hearings took place in April 2013, and on July 16, 2013 the ALJ issued an Initial Decision ruling that ATSI must pay the "Schedule 39" MVP costs.FirstEnergy and other parties submitted Briefs on Exceptions on August 15, 2013.The MISO and other parties filed Briefs Opposing Exceptions on September 4, 2013.The matter is pending before FERC for final decision.

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

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 U.S. Court of Appeals for the Ninth Circuit in several 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 had previously remandedoneof those proceedings to FERC, which dismissed the claims of the California Parties in May 2011, and affirmed the dismissal in June 2012.On June 20, 2012, the California Parties appealed FERC's decision back to the Ninth Circuit.Briefing was completed before the Ninth Circuit on October 23, 2013.The timing of further action by the Ninth Circuit is unknown.

In another proceeding, in June 2009, the California Attorney General, on behalf of certain California parties, filed another complaint with FERC against various sellers, including AE Supply, again seeking refunds for transactions in the California energy markets during 2000 and 2001.The above-noted transactions with CDWR are the basis for including AE Supply in this complaint.AE Supply filed a motion to dismiss, which was granted by FERC in May 2011, and affirmed by FERC in June 2012.The California Attorney General has appealed FERC's dismissal of its complaint to the Ninth Circuit, which has consolidated the case with other pending appeals related to California refund claims, and stayed the proceedings pending further order.

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 was proposed to be comprised of a765kV transmission line 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.On August 24, 2012, the PJM Board of Managers canceled the PATH project, which it had suspended in February 2011.As a result, approximately$62 millionand approximately$59 millionin costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery.On September 28, 2012, those companies requested authorization from FERC to recover the costs with a proposed return on equity of10.9%(10.4%base plus0.5%RTO membership) from PJM customers over the nextfiveyears.Several parties protested the request.On November 30, 2012, FERC issued an order denying the0.5%return on equity adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012 subject to settlement judge procedures and hearing if the parties do not agree to a settlement.The issues subject to settlement include the prudence of the costs, the base return on equity and the period of recovery.PATH-Allegheny and PATH-WV are currently engaged in settlement discussions with the other parties.Depending on the outcome of a possible settlement or hearing, if settlement is not achieved, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

PATH-Allegheny and PATH-WV have requested rehearing of FERC's denial of the0.5%return on equity adder for RTO membership; that request for rehearing remains pending before FERC.In addition, FERC has consolidated for settlement judge procedures and hearing purposes three formal challenges to the PATH formula rate annual updates submitted to FERC in June 2010, June 2011 and June 2012, with the September 28, 2012 filing for recovery of costs associated with the cancellation of the PATH project.FirstEnergy cannot predict the outcome of these matters or estimate the possible loss or range of loss.

Seneca

The Seneca Pumped Storage Project is a451MW hydroelectric project located in Warren County, Pennsylvania owned and operated by FG.FG 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, FG initiated the ILP relicensing process by filing its notice of intent to relicense and related documents in the license docket.

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.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.FG believes it is entitled to a statutory “incumbent preference” under Section 15 and that it ultimately should prevail in these proceedings.Nevertheless, the Seneca Nation's pleadings reflect the Nation's apparent intent to obtain the license for the facility, and to assume ownership and operation of the facility as contemplated by the statute.

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 January 7, 2013, FirstEnergy and the Seneca Nation submitted their respective reports for the 2012 study season.On January 31 and February 1, 2013, respectively, the Seneca Nation and FirstEnergy each submitted their respective proposed study plans for the 2013 study season.On March 4, 2013, the Seneca Nation and other parties submitted comments regarding FirstEnergy's proposed study plans.In its comments, the Seneca Nation alleges that FirstEnergy does not hold the real estate rights necessary to operate a hydroelectric project in circumstances where there is flowage over the Seneca Nation's lands.On April 3, 2013, FirstEnergy filed its response to these and other assertions by the Seneca Nation and its allied parties.On May 3, 2013, FERC's Director of the Office of Energy Projects issued FERC Staff's study plan determinations for the 2013 study year.The Director determined that water level fluctuations in the lower reservoir due to hydroelectric project operations have no discernible effect on reservoir lands or environmental resources.This finding is expected to strengthen FirstEnergy's position that the project boundary should be defined to exclude the U.S. Army Corps of Engineers dam and reservoir facilities.FERC Staff's determinations also largely adopted FirstEnergy's position and arguments as to the proper scope of environmental studies for the 2013 study season.The study processes will extend through approximately November 2013.

On July 3, 2013, FirstEnergy and the Seneca Nation each submitted "Preliminary License Proposals" in the relicensing dockets.These submissions are intended to be non-binding indications of types of project upgrades that may be proposed in the parties' respective final licensing applications, as well as an indication of the scope and direction of the parties' plans for the upcoming final licensing applications.On October 1, 2013, FERC staff provided comments on FirstEnergy's and the Seneca Nation's Preliminary Licensing Proposals, including identifying deficiencies for the applicants to address in their applications. FirstEnergy and the Seneca Nation each are required to submit their application for the project license by December 2, 2013.

Hydroelectric Asset Sale

On September 4, 2013, certain of FirstEnergy’s subsidiaries submitted filings with FERC for authorization to sellelevenhydroelectric power plant projects to subsidiaries of Harbor Hydro Holdings, LLC (Harbor Hydro), a subsidiary of LS Power Equity Partners II, LP (LS Power) for approximately$400 million.Theelevenhydroelectric projects are: the Seneca Pumped Storage Project, Allegheny Lock & Dam No. 5, Allegheny Lock & Dam No. 6, the Lake Lynn Project, the Millville Hydro Project, the Dam No. 4 Project, the Dam No. 5 Project, and four additional projects located in Shenandoah, Front Royal and Luray, Virginia.Theelevenprojects have a combined generating capacity of approximately527MW.Resolution of the potential competing hydro license application of the Seneca Nation for the Seneca Pumped Storage Project and other claims and matters is a condition to closing of the proposed asset sale.FirstEnergy’s submittals for regulatory authorization include a request for authorization to transfer the hydroelectric licenses under Part I of the FPA, and a request for authorization to transfer the FERC-jurisdictional facilities associated with the hydroelectric projects under Part II of the FPA.On September 25, 2013, the Seneca Nation submitted a pleading in the Part II regulatory proceeding wherein the Seneca Nation reiterated the real estate and other claims that the Seneca Nation has advanced in the Seneca Pumped Storage Project relicensing proceeding. On October 18, 2013, the Seneca Nation reiterated its real estate claims in comments on the Part I application to transfer the license for the Seneca Pumped Storage Project.However, the Seneca Nation noted in both sets of comments that it does not oppose the proposed sale or license transfer “at this time.” On November 1, 2013, FERC issued an order granting the FPA Part II authorization to transfer the hydro assets (the license transfer application remains pending before FERC).Additional filings have been submitted to FERC for the purpose of implementing the transaction once regulatory approval is obtained. The VSCC also must approve the sale for the assets that are located in Virginia, and the application for such approval was submitted on September 19, 2013.Once the regulatory authorizations are granted and the other closing conditions are satisfied, FirstEnergy expects to close this asset sale transaction in the fourth quarter of 2013. See Note 16, Discontinued Operations and Assets Held for Sale for additional information regarding the potential asset sales.

MISO Capacity Portability

On June 11, 2012, 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 and the 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.FirstEnergy submitted comments and reply comments in August 2012.In the fall of 2012, FirstEnergy participated in certain stakeholder meetings to review various proposals advanced by MISO.Although none of MISO's proposals attracted significant stakeholder support, on January 3, 2013, MISO filed a pleading with FERC that renewed many of the arguments advanced in prior MISO filings and asked FERC to take expedited action to address MISO's allegations.FirstEnergy and other parties subsequently submitted filings arguing that MISO's concerns largely are without foundation and suggesting that FERC order that the remaining concerns be addressed in the existing stakeholder process that is described in the PJM/MISO Joint Operating Agreement.On April 2, 2013, FERC issued an order directing MISO and PJM to make presentations to FERC regarding ongoing regional efforts to address whether barriers to transfer capability exist between the MISO and PJM regions and the actions the FERC should take to address any such barriers.The RTOs presented their respective positions to FERC on June 20, 2013 and provided additional information regarding their stakeholder prioritization survey, in response to a FERC request on June 27, 2013.On September 26, 2013, the RTOs jointly submitted an informational filing providing a description of and schedule for their Joint and Common Market initiatives. FERC has not acted on the presentations, and the RTOs and affected parties are working to address the MISO's proposal in stakeholder proceedings.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 a negative impact on the prices at which those auctions would clear.

MOPR Reform

On December 7, 2012, PJM filed amendments to its tariff to revise the MOPR used in the RPM. PJM revised the MOPR to add two broad, categorical exemptions, eliminate an existing exemption, and to limit the applicability of the MOPR to certain capacity resources.The filing also included related and conforming changes to the RPM posting requirements and to those provisions describing the role of the Independent Market Monitor for the PJM Region.On May 2, 2013, FERC issued an order in large part accepting PJM's proposed reform of the MOPR, including the proposed exemptions and applicability but also requiring PJM to commit to future review and, if necessary, additional revisions to the MOPR to accommodate changing market conditions.On June 3, 2013, FirstEnergy submitted a request for rehearing of FERC's May 2, 2013 order.In its rehearing request, FirstEnergy referenced the results of the May 2013 PJM RPM capacity auction, and the data that is available in the public domain about the reasons for the unexpectedly low "rest-of-RTO" clearing price of $59 per MW-day, as supporting its contention that the MOPR reform depressed prices as predicted in FirstEnergy's December 28, 2012 and January 25, 2013 comments.FirstEnergy's request for rehearing is pending before FERC.

Synchronous Condensers

On December 20, 2012, FERC approved the transfer by FG to ATSI of certain deactivated generation assets associated with Eastlake Units 1 through 5 and Lakeshore Unit 18 to facilitate their conversion to synchronous condensers to provide voltage support on the ATSI transmission system.The transfer price of the assets was approximately$21.5 millionand the estimated conversion cost was approximately$60 million.The transfer of Eastlake Units 4 and 5 was completed on January 31, 2013 andATSI completed the conversion of Eastlake Unit 5 in July 2013 and is expected to complete Eastlake Unit 4 by June 1, 2014.The transfer of each of the remaining units and conversion to synchronous condensers will occur when the use of the unit for RMR purposes is no longer required.On January 22, 2013, ATSI requested clarification or, in the alternative, rehearing with respect to a statement in the FERC order authorizing the transfer that ATSI's current formula rate does not include the accounts and components necessary to allow for recovery of the costs associated with acquisition of the transferred assets and that ATSI must make a filing under Section 205 of the FPA in order to recover those costs.ATSI requested clarification from FERC noting its formula rate currently includes the necessary accounts and components to allow for such recovery and that a Section 205 filing is not required.On August 5, 2013, FERC clarified that the issue of whether the cost of the transferred facilities and any conversion costs could be included in ATSI’s formula rates is more appropriately addressed during ATSI’s yearly formula rate update process.Based on this clarification by FERC, FE and FES recognized a pre-tax gain of approximately$17 millionin the third quarter of 2013 representing the sales price to ATSI over the net book value.

FTR Underfunding Complaint

In PJM, FTRs are a mechanism to hedge congestion and they operate as a financial replacement for physical firm transmission service.FTRs are financially-settled instruments that entitle the holder to a stream of revenues based on the hourly congestion price differences across a specific transmission path in the PJM Day-ahead Energy Market.FE also performs bilateral transactions for the purpose of hedging the price differences between the location of supply resources and retail load obligations. Due to certain language in the PJM tariff, the funds that are set aside to pay FTRs can be diverted to other uses, resulting in “underfunding” of FTR payments.Since June of 2010, FES and AE Supply have lost more than$63.5 millionin revenues that they otherwise would have received as FTR holders to hedge congestion costs.FES and AE Supply expect to continue to experience significant underfunding.

On December 28, 2011, FES and AE Supply filed a complaint with FERC for the purpose of modifying certain provisions in the PJM tariff to eliminate FTR underfunding.On March 2, 2012, FERC issued an order dismissing the complaint.In its order, FERC ruled that it was not appropriate to initiate action at that time because of the unknown root causes of FTR underfunding.FERC directed PJM to convene stakeholder proceedings for the purpose of determining the root causes of the FTR underfunding.FERC went on to note that its dismissal of the complaint was without prejudice to FES and AE Supply or any other affected entity filing a complaint if the stakeholder proceedings proved unavailing.FES and AE Supply sought rehearing of FERC's order and, on July 19, 2012, FERC denied rehearing.In April, 2012, PJM issued a report on FTR underfunding.However, the PJM stakeholder process proved unavailing as the stakeholders were not willing to change the tariff to eliminate FTR underfunding.Accordingly, on February 15, 2013, FES and AE Supply refiled their complaint with FERC for the purpose of changing the PJM tariff to eliminate FTR underfunding.Various parties filed responsive pleadings, including PJM.On June 5, 2013, FERC issued its order denying the new complaint.On July 5, 2013, FirstEnergy filed a request for rehearing of FERC's order.FirstEnergy's request for rehearing is pending before FERC.

XML

Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2013
Changes to the asset retirement obligations
Beginning Balance		$ 1,599
Liabilities settled		(13)
Accretion		85
Revisions in estimated cash flows		163
Ending Balance	1,834	1,834
FES
Changes to the asset retirement obligations
Beginning Balance		965
Liabilities settled		(14)
Accretion		52
Revisions in estimated cash flows	5	156
Ending Balance	1,159	1,159
TE
Changes to the asset retirement obligations
Revisions in estimated cash flows	$ 7

XML

Fair Value Measurements (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
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	$ 368	$ 1,751	$ 1,545	$ 2,133
Realized Gains	9	81	49	118
Realized Losses	(15)	(30)	(31)	(58)
OTTI	(21)	(2)	(74)	(9)
Interest and Dividend Income	26	18	74	51
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	164	1,059	650	1,167
Realized Gains	5	60	38	85
Realized Losses	(3)	(21)	(14)	(40)
OTTI	(21)	(2)	(66)	(8)
Interest and Dividend Income	$ 16	$ 10	$ 44	$ 27

XML

Accumulated Other Comprehensive Income

9 Months Ended

Sep. 30, 2013

Statement of Other Comprehensive Income [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, in the three and nine months ended September 30, 2013 and 2012, for FirstEnergy and FES are shown in the following tables:

FirstEnergy
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2013	$	(37	)	$	13		$	347		$	323
Other comprehensive income before reclassifications	—			5			—			5
Amounts reclassified from AOCI	1			(1		)	(29		)	(29		)
Net other comprehensive income (loss)	1			4			(29		)	(24		)
AOCI Balance as of September 30, 2013	$	(36	)	$	17		$	318		$	299
AOCI Balance as of July 1, 2012	$	(39	)	$	27		$	401		$	389
Other comprehensive income before reclassifications	—			25			—			25
Amounts reclassified from AOCI	—			(25		)	(22		)	(47		)
Net other comprehensive loss	—			—			(22		)	(22		)
AOCI Balance as of September 30, 2012	$	(39	)	$	27		$	379		$	367

FES
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2013	$	1		$	12		$	49		$	62
Other comprehensive income before reclassifications	—			4			—			4
Amounts reclassified from AOCI	—			(1		)	(3		)	(4		)
Net other comprehensive income (loss)	—			3			(3		)	—
AOCI Balance as of September 30, 2013	$	1		$	15		$	46		$	62
AOCI Balance as of July 1, 2012	$	6		$	25		$	53		$	84
Other comprehensive income (loss) before reclassifications	(1		)	24			—			23
Amounts reclassified from AOCI	(1		)	(25		)	(3		)	(29		)
Net other comprehensive loss	(2		)	(1		)	(3		)	(6		)
AOCI Balance as of September 30, 2012	$	4		$	24		$	50		$	78

FirstEnergy
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
Other comprehensive income before reclassifications	—			19			—			19
Amounts reclassified from AOCI	2			(17		)	(90		)	(105		)
Net other comprehensive income (loss)	2			2			(90		)	(86		)
AOCI Balance as of September 30, 2013	$	(36	)	$	17		$	318		$	299
AOCI Balance as of January 1, 2012	$	(39	)	$	19		$	446		$	426
Other comprehensive income before reclassifications	1			38			5			44
Amounts reclassified from AOCI	(1		)	(30		)	(72		)	(103		)
Net other comprehensive income (loss)	—			8			(67		)	(59		)
AOCI Balance as of September 30, 2012	$	(39	)	$	27		$	379		$	367

FES
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
Other comprehensive income before reclassifications	—			17			—			17
Amounts reclassified from AOCI	(2		)	(15		)	(10		)	(27		)
Net other comprehensive income (loss)	(2		)	2			(10		)	(10		)
AOCI Balance as of September 30, 2013	$	1		$	15		$	46		$	62
AOCI Balance as of January 1, 2012	$	8		$	16		$	52		$	76
Other comprehensive income before reclassifications	—			37			8			45
Amounts reclassified from AOCI	(4		)	(29		)	(10		)	(43		)
Net other comprehensive income (loss)	(4		)	8			(2		)	2
AOCI Balance as of September 30, 2012	$	4		$	24		$	50		$	78

The following amounts were reclassified from AOCI in the three months ended September 30, 2013 and 2012:

FE	Three Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
Long-term debt	3			2			Interest expense
	2			—			Total before taxes
	(1		)	—			Income taxes
	$	1		$	—		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(2	)	$	(40	)	Investment income
	1			15			Income taxes
	$	(1	)	$	(25	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(47	)	$	(47	)	(a)
	18			25			Income taxes
	$	(29	)	$	(22	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES	Three Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
	1			1			Income taxes (benefits)
	$	—		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(2	)	$	(40	)	Investment income (loss)
	1			15			Income taxes (benefits)
	$	(1	)	$	(25	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			2			Income taxes (benefits)
	$	(3	)	$	(3	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

The following amounts were reclassified from AOCI in the nine months ended September 30, 2013 and 2012:

FE	Nine Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(7	)	Other operating expenses
Long-term debt	9			6			Interest expense
	4			(1		)	Total before taxes
	(2		)	—			Income taxes
	$	2		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(27	)	$	(48	)	Investment income
	10			18			Income taxes
	$	(17	)	$	(30	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(148	)	$	(143	)	(a)
	58			71			Income taxes
	$	(90	)	$	(72	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES	Nine Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(6	)	Other operating expenses
Long-term debt	2			—			Interest expense
	(3		)	(6		)	Total before taxes
	1			2			Income taxes (benefits)
	$	(2	)	$	(4	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(24	)	$	(46	)	Investment income (loss)
	9			17			Income taxes (benefits)
	$	(15	)	$	(29	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(16	)	$	(15	)	(a)
	6			5			Income taxes (benefits)
	$	(10	)	$	(10	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

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Accumulated Other Comprehensive Income (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ 877		$ 861		$ 2,645		$ 2,597
Interest expense	257		230		771		750
Investment income (loss)	(5)		(39)		(8)		(63)
Total before taxes	(286)		(729)		(362)		(1,558)
Income taxes (benefits)	77		307		129		650
Net of tax	(218)		(425)		(250)		(919)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	339		342		1,105		1,028
Investment income (loss)	3		(38)		4		(50)
Total before taxes	(56)		(161)		62		(350)
Income taxes (benefits)	23		65		(19)		139
Net of tax	(40)		(101)		29		(222)
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes	2	[1]	0	[1]	4	[1]	(1)	[1]
Income taxes (benefits)	(1)	[1]	0	[1]	(2)	[1]	0	[1]
Net of tax	1	[1]	0	[1]	2	[1]	(1)	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes					(3)	[1]	(6)	[1]
Income taxes (benefits)	1	[1]	1	[1]	1	[1]	2	[1]
Net of tax	0	[1]	(1)	[1]	(2)	[1]	(4)	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(1)	[1]	(2)	[1]	(5)	[1]	(7)	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(1)	[1]	(2)	[1]	(5)	[1]	(6)	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	3	[1]	2	[1]	9	[1]	6	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense					2	[1]	0	[1]
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(2)	[1]	(40)	[1]	(27)	[1]	(48)	[1]
Income taxes (benefits)	1	[1]	15	[1]	10	[1]	18	[1]
Net of tax	(1)	[1]	(25)	[1]	(17)	[1]	(30)	[1]
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(2)	[1]	(40)	[1]	(24)	[1]	(46)	[1]
Income taxes (benefits)	1	[1]	15	[1]	9	[1]	17	[1]
Net of tax	(1)	[1]	(25)	[1]	(15)	[1]	(29)	[1]
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(47)	[1],[2]	(47)	[1],[2]	(148)	[1],[2]	(143)	[1],[2]
Income taxes (benefits)	18	[1]	25	[1]	58	[1]	71	[1]
Net of tax	(29)	[1]	(22)	[1]	(90)	[1]	(72)	[1]
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(5)	[1],[2]	(5)	[1],[2]	(16)	[1],[2]	(15)	[1],[2]
Income taxes (benefits)	2	[1]	2	[1]	6	[1]	5	[1]
Net of tax	$ (3)	[1]	$ (3)	[1]	$ (10)	[1]	$ (10)	[1]

[1] Parenthesis represent credits from AOCI to the Consolidated Statements of Income.

[2] These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.

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Fair Value Measurements (Details 5) (Debt Securities, USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Debt Securities
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 46	$ 54
Unrealized Gains	1	30
Fair Value	$ 47	$ 84

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Asset Retirement Obligations (Tables)

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligations (Tables) [Abstract]

Changes to the asset retirement obligations

The following table summarizes the changes to the ARO balances during 2013:

ARO Reconciliation	FirstEnergy			FES
	(In millions)
Balance, December 31, 2012	$	1,599		$	965
Liabilities settled	(13		)	(14		)
Accretion	85			52
Revisions in estimated cash flows	163			156
Balance, September 30, 2013	$	1,834		$	1,159

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Segment Information

9 Months Ended

Sep. 30, 2013

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. FES does 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, SSO 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. This business segment currently controls approximately 4,000 MWs of capacity, including the net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP). The segment's revenues are primarily derived from rates that recover costs and provide a return on transmission capital investment. Except for the recovery of the PATH abandoned project regulatory asset, these revenues are derived from transmission services provided pursuant to the PJM open access transmission tariff to LSEs. Its results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

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 currently controls approximately14,500MWs of capacity, including885MWs of capacity subject to RMR arrangements with PJM and excluding2,080MWs of capacity deactivated on October 9, 2013 and a net transfer to Regulated Distribution of 1,476 MWs of capacity associated with the Harrison and Pleasants asset swap which occurred on October 9, 2013. This segment 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 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)
September 30, 2013
External revenues	$	2,340	$	190	$	1,573		$	(31	)	$	(36	)	$	4,036
Internal revenues	—		—		196			—			(196		)	—
Total revenues	2,340		190		1,769			(31		)	(232		)	4,036
Depreciation, amortization and deferrals	460		31		125			12			—			628
Investment income (loss)	14		—		(5		)	3			(7		)	5
Interest expense	134		23		53			47			—			257
Income taxes (benefits)	50		32		47			(44		)	(8		)	77
Income from continuing operations	85		54		68			—			2			209
Discontinued operations, net of tax	—		—		9			—			—			9
Net income (loss)	85		54		77			(10		)	12			218
Total assets	27,030		4,953		17,809			591			—			50,383
Total goodwill	5,025		526		867			—			—			6,418
Property additions	261		105		162			20			—			548
September 30, 2012
External revenues	$	2,483	$	187	$	1,462		$	(31	)	$	(49	)	$	4,052
Internal revenues	—		—		209			—			(209		)	—
Total revenues	2,483		187		1,671			(31		)	(258		)	4,052
Depreciation, amortization and deferrals	193		28		102			9			1			333
Investment income	20		—		36			(2		)	(15		)	39
Interest expense	136		24		73			(3		)	—			230
Income taxes (benefits)	168		35		74			(8		)	38			307
Income from continuing operations	286		59		126			—			(49		)	422
Discontinued operations, net of tax	—		—		3			—			—			3
Net income (loss)	286		59		129			(13		)	(36		)	425
Total assets	26,122		4,519		16,846			1,251			—			48,738
Total goodwill	5,025		526		893			—			—			6,444
Property additions	308		47		412			8			—			775
Nine Months Ended
September 30, 2013
External revenues	$	6,593	$	546	$	4,350		$	(89	)	$	(130	)	$	11,270
Internal revenues	—		—		588			—			(588		)	—
Total revenues	6,593		546		4,938			(89		)	(718		)	11,270
Depreciation, amortization and deferrals	882		91		347			32			—			1,352
Investment income (loss)	41		—		(6		)	6			(33		)	8
Interest expense	404		68		187			112			—			771
Income taxes (benefits)	284		93		(189		)	(55		)	(4		)	129
Income (loss) from continuing operations	474		156		(317		)	—			(80		)	233
Discontinued operations, net of tax	—		—		17			—			—			17
Net income (loss)	474		156		(300		)	(92		)	12			250
Total assets	27,030		4,953		17,809			591			—			50,383
Total goodwill	5,025		526		867			—			—			6,418
Property additions	980		291		630			59			—			1,960
September 30, 2012
External revenues	$	6,976	$	557	$	4,465		$	(78	)	$	(142	)	$	11,778
Internal revenues	—		—		686			—			(684		)	2
Total revenues	6,976		557		5,151			(78		)	(826		)	11,780
Depreciation, amortization and deferrals	618		86		303			25			—			1,032
Investment income	62		1		48			(1		)	(47		)	63
Interest expense	405		70		209			66			—			750
Income taxes	355		101		165			(49		)	78			650
Income from continuing operations	603		171		284			—			(150		)	908
Discontinued operations, net of tax	—		—		11			—			—			11
Net income (loss)	603		171		295			(82		)	(68		)	919
Total assets	26,122		4,519		16,846			1,251			—			48,738
Total goodwill	5,025		526		893			—			—			6,444
Property additions	751		169		715			51			—			1,686

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Supplemental Guarantor Information

9 Months Ended

Sep. 30, 2013

Supplemental Guarantor Information [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

SUPPLEMENTAL GUARANTOR INFORMATION

In 2007, FG completed a sale and leaseback transaction for its undivided interest in Bruce Mansfield Unit 1. FES has fully and unconditionally and irrevocably guaranteed all of FG's obligations under each of the leases. The related lessor notes and pass through certificates are not guaranteed by FES or FG, 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 lease for FG.

The Consolidating Statements of Income and Comprehensive Income for the three months and nine months ended September 30, 2013 and 2012, Consolidating Balance Sheets as of September 30, 2013 and December 31, 2012, and Consolidating Statements of Cash Flows for the nine months ended September 30, 2013 and 2012, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. Investments in wholly owned subsidiaries are accounted for by FES using the equity method. Results of operations for FG and NG 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 September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,654		$	528		$	440		$	(943	)	$	1,679
OPERATING EXPENSES:
Fuel	—			249			55			—			304
Purchased power from affiliates	1,009			—			65			(942		)	132
Purchased power from non-affiliates	720			4			—			—			724
Other operating expenses	147			65			114			13			339
Provision for depreciation	1			33			46			—			80
General taxes	21			9			5			—			35
Total operating expenses	1,898			360			285			(929		)	1,614
OPERATING INCOME (LOSS)	(244		)	168			155			(14		)	65
OTHER INCOME (EXPENSE):
Loss on debt redemptions	—			—			—			—			—
Investment income (loss)	2			—			(1		)	(4		)	(3		)
Miscellaneous income, including net income from equity investees	180			19			—			(178		)	21
Interest expense — affiliates	(3		)	(2		)	(1		)	5			(1		)
Interest expense — other	(13		)	(24		)	(13		)	15			(35		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	166			(6		)	(7		)	(162		)	(9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(78		)	162			148			(176		)	56
INCOME TAXES (BENEFITS)	(118		)	111			28			2			23
NET INCOME FROM CONTINUING OPERATIONS	40			51			120			(178		)	33
Discontinued operations (net of income taxes of $5)	—			7			—			—			7
NET INCOME	$	40		$	58		$	120		$	(178	)	$	40
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	40		$	58		$	120		$	(178	)	$	40
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available-for-sale securities	5			—			5			(5		)	5
Other comprehensive income (loss)	(1		)	(5		)	5			—			(1		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(2		)	3			(1		)	(1		)
Other comprehensive income (loss), net of tax	—			(3		)	2			1			—
COMPREHENSIVE INCOME	$	40		$	55		$	122		$	(177	)	$	40

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

For the Nine Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	4,575		$	1,612		$	1,337		$	(2,869	)	$	4,655
OPERATING EXPENSES:
Fuel	—			782			154			—			936
Purchased power from affiliates	3,072			—			197			(2,868		)	401
Purchased power from non-affiliates	1,749			6			—			—			1,755
Other operating expenses	484			208			376			37			1,105
Provision for depreciation	4			96			134			(3		)	231
General taxes	60			28			18			—			106
Total operating expenses	5,369			1,120			879			(2,834		)	4,534
OPERATING INCOME (LOSS)	(794		)	492			458			(35		)	121
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(103		)	—			—			—			(103		)
Investment income	4			—			3			(11		)	(4		)
Miscellaneous income, including net income from equity investees	543			23			—			(537		)	29
Interest expense — affiliates	(10		)	(4		)	(5		)	12			(7		)
Interest expense — other	(50		)	(79		)	(42		)	45			(126		)
Capitalized interest	1			1			26			—			28
Total other income (expense)	385			(59		)	(18		)	(491		)	(183		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(409		)	433			440			(526		)	(62		)
INCOME TAXES (BENEFITS)	(380		)	215			138			8			(19		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(29		)	218			302			(534		)	(43		)
Discontinued operations (net of income taxes of $8)	—			14			—			—			14
NET INCOME (LOSS)	$	(29	)	$	232		$	302		$	(534	)	$	(29	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(29	)	$	232		$	302		$	(534	)	$	(29	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(16		)	(15		)	—			15			(16		)
Amortized gain on derivative hedges	(3		)	—			—			—			(3		)
Change in unrealized gain on available-for-sale securities	2			—			2			(2		)	2
Other comprehensive income (loss)	(17		)	(15		)	2			13			(17		)
Income taxes (benefits) on other comprehensive income (loss)	(7		)	(6		)	1			5			(7		)
Other comprehensive income (loss), net of tax	(10		)	(9		)	1			8			(10		)
COMPREHENSIVE INCOME (LOSS)	$	(39	)	$	223		$	303		$	(526	)	$	(39	)

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,523		$	610		$	395		$	(978	)	$	1,550
OPERATING EXPENSES:
Fuel	—			248			55			—			303
Purchased power from affiliates	1,042			—			67			(978		)	131
Purchased power from non-affiliates	499			3			—			—			502
Other operating expenses	130			78			122			12			342
Provision for depreciation	1			29			41			(1		)	70
General taxes	20			10			5			—			35
Total operating expenses	1,692			368			290			(967		)	1,383
OPERATING INCOME (LOSS)	(169		)	242			105			(11		)	167
OTHER INCOME (EXPENSE):
Investment income	1			5			37			(5		)	38
Miscellaneous income, including net income from equity investees	317			—			—			(316		)	1
Interest expense — affiliates	(5		)	(2		)	(1		)	5			(3		)
Interest expense — other	(25		)	(27		)	(15		)	16			(51		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	288			(23		)	29			(300		)	(6		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	119			219			134			(311		)	161
INCOME TAXES (BENEFITS)	18			(14		)	59			2			65
NET INCOME FROM CONTINUING OPERATIONS	101			233			75			(313		)	96
Discontinued operations (net of income taxes of $3)	—			5			—			—			5
NET INCOME	$	101		$	238		$	75		$	(313	)	$	101
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	101		$	238		$	75		$	(313	)	$	101
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available for sale securities	(2		)	—			(1		)	1			(2		)
Other comprehensive loss	(9		)	(4		)	(1		)	5			(9		)
Income tax benefits on other comprehensive loss	(3		)	(2		)	—			2			(3		)
Other comprehensive loss, net of tax	(6		)	(2		)	(1		)	3			(6		)
COMPREHENSIVE INCOME	$	95		$	236		$	74		$	(310	)	$	95

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Nine Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	4,443		$	1,777		$	1,262		$	(2,971	)	$	4,511
OPERATING EXPENSES:
Fuel	—			824			154			—			978
Purchased power from affiliates	3,163			—			189			(2,971		)	381
Purchased power from non-affiliates	1,420			5			—			—			1,425
Other operating expenses	313			268			410			37			1,028
Provision for depreciation	3			87			114			(4		)	200
General taxes	60			28			16			—			104
Total operating expenses	4,959			1,212			883			(2,938		)	4,116
OPERATING INCOME (LOSS)	(516		)	565			379			(33		)	395
OTHER INCOME (EXPENSE):
Investment income	2			14			49			(15		)	50
Miscellaneous income, including net income from equity investees	854			19			—			(848		)	25
Interest expense — affiliates	(14		)	(5		)	(3		)	15			(7		)
Interest expense — other	(72		)	(79		)	(36		)	47			(140		)
Capitalized interest	—			3			24			—			27
Total other income (expense)	770			(48		)	34			(801		)	(45		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	254			517			413			(834		)	350
INCOME TAXES (BENEFITS)	32			(25		)	124			8			139
NET INCOME FROM CONTINUING OPERATIONS	222			542			289			(842		)	211
Discontinued operations (net of income taxes of $6)	—			11			—			—			11
NET INCOME	$	222		$	553		$	289		$	(842	)	$	222
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	222		$	553		$	289		$	(842	)	$	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(2		)	(1		)	—			1			(2		)
Amortized gain on derivative hedges	(6		)	—			—			—			(6		)
Change in unrealized gain on available-for-sale securities	11			—			12			(12		)	11
Other comprehensive income (loss)	3			(1		)	12			(11		)	3
Income taxes (benefits) on other comprehensive income (loss)	1			(1		)	5			(4		)	1
Other comprehensive income, net of tax	2			—			7			(7		)	2
COMPREHENSIVE INCOME	$	224		$	553		$	296		$	(849	)	$	224

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of September 30, 2013	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	524		—		—		—			524
Affiliated companies	420		445		285		(631		)	519
Other	76		22		25		—			123
Notes receivable from affiliated companies	337		163		764		(1,010		)	254
Materials and supplies	64		161		214		—			439
Derivatives	139		—		—		—			139
Prepayments and other	61		37		6		1			105
	1,621		830		1,294		(1,640		)	2,105
PROPERTY, PLANT AND EQUIPMENT:
In service	104		6,068		6,719		(383		)	12,508
Less — Accumulated provision for depreciation	26		1,928		2,882		(187		)	4,649
	78		4,140		3,837		(196		)	7,859
Construction work in progress	21		115		980		—			1,116
	99		4,255		4,817		(196		)	8,975
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,270		—			1,270
Investment in affiliated companies	5,503		—		—		(5,503		)	—
Other	1		10		—		—			11
	5,504		10		1,270		(5,503		)	1,281
ASSETS HELD FOR SALE (NOTE 16)	—		121		—		—			121
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	16		169		—		(185		)	—
Customer intangibles	99		—		—		—			99
Goodwill	23		—		—		—			23
Property taxes	—		14		22		—			36
Unamortized sale and leaseback costs	—		—		—		161			161
Derivatives	65		—		—		—			65
Other	174		242		14		(162		)	268
	377		425		36		(186		)	652
	$	7,601	$	5,641	$	7,417	$	(7,525	)	$	13,134
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	366	$	514	$	(22	)	$	859
Short-term borrowings-
Affiliated companies	696		314		—		(1,010		)	—
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	643		386		378		(631		)	776
Other	88		125		—		—			213
Accrued taxes	7		17		37		(19		)	42
Derivatives	103		—		—		—			103
Other	46		72		22		36			176
	1,584		1,284		951		(1,646		)	2,173
CAPITALIZATION:
Total equity	5,229		2,010		3,469		(5,479		)	5,229
Long-term debt and other long-term obligations	712		1,873		789		(1,196		)	2,178
	5,941		3,883		4,258		(6,675		)	7,407
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		866			866
Accumulated deferred income taxes	—		—		770		(71		)	699
Asset retirement obligations	—		176		983		—			1,159
Retirement benefits	27		228		—		—			255
Derivatives	22		—		—		—			22
Other	27		70		455		1			553
	76		474		2,208		796			3,554
	$	7,601	$	5,641	$	7,417	$	(7,525	)	$	13,134

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2012	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	3	$	—	$	—		$	3
Receivables-
Customers	483		—		—		—			483
Affiliated companies	232		417		478		(748		)	379
Other	56		19		16		—			91
Notes receivable from affiliated companies	366		7		607		(704		)	276
Materials and supplies	66		231		208		—			505
Derivatives	158		—		—		—			158
Prepayments and other	38		39		10		—			87
	1,399		716		1,319		(1,452		)	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	91		5,899		6,391		(384		)	11,997
Less — Accumulated provision for depreciation	32		1,915		2,646		(185		)	4,408
	59		3,984		3,745		(199		)	7,589
Construction work in progress	34		230		877		—			1,141
	93		4,214		4,622		(199		)	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,283		—			1,283
Investment in affiliated companies	4,972		—		—		(4,972		)	—
Other	—		12		—		—			12
	4,972		12		1,283		(4,972		)	1,295
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		313		—		(313		)	—
Customer intangibles	110		—		—		—			110
Goodwill	24		—		—		—			24
Property taxes	—		14		22		—			36
Unamortized sale and leaseback costs	—		—		—		119			119
Derivatives	99		—		—		—			99
Other	160		194		5		(106		)	253
	393		521		27		(300		)	641
	$	6,857	$	5,463	$	7,251	$	(6,923	)	$	12,648
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	586	$	537	$	(22	)	$	1,102
Short-term borrowings-
Affiliated companies	358		346		—		(704		)	—
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	748		143		583		(748		)	726
Other	63		96		—		—			159
Accrued taxes	126		25		20		—			171
Derivatives	124		—		—		—			124
Other	71		148		15		46			280
	1,491		1,348		1,155		(1,428		)	2,566
CAPITALIZATION:
Total equity	3,763		1,787		3,165		(4,952		)	3,763
Long-term debt and other long-term obligations	1,482		2,009		834		(1,207		)	3,118
	5,245		3,796		3,999		(6,159		)	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		892			892
Accumulated deferred income taxes	28		—		714		(227		)	515
Asset retirement obligations	—		29		936		—			965
Retirement benefits	26		215		—		—			241
Derivatives	37		—		—		—			37
Other	30		75		447		(1		)	551
	121		319		2,097		664			3,201
	$	6,857	$	5,463	$	7,251	$	(6,923	)	$	12,648

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(1,018	)	$	712		$	705		$	(10	)	$	389
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	338			—			—			(338		)	—
Equity contribution from parent	1,500			—			—			—			1,500
Redemptions and Repayments-
Long-term debt	(769		)	(352		)	(68		)	10			(1,179		)
Short-term borrowings, net	—			(32		)	—			32			—
Tender premiums	(67		)	—			—			—			(67		)
Other	(3		)	(4		)	—			—			(7		)
Net cash provided from (used for) financing activities	999			(388		)	(68		)	(296		)	247
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(9		)	(192		)	(276		)	—			(477		)
Nuclear fuel	—			—			(159		)	—			(159		)
Proceeds from asset sales	—			21			—			—			21
Sales of investment securities held in trusts	—			—			650			—			650
Purchases of investment securities held in trusts	—			—			(694		)	—			(694		)
Loans to affiliated companies, net	28			(156		)	(156		)	306			22
Other	—			2			(2		)	—			—
Net cash provided from (used for) investing activities	19			(325		)	(637		)	306			(637		)
Net change in cash and cash equivalents	—			(1		)	—			—			(1		)
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(971	)	$	683		$	799		$	(10	)	$	501
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			317			243			—			560
Short-term borrowings, net	982			49			—			(1,028		)	3
Redemptions and Repayments-
Long-term debt	—			(169		)	(87		)	10			(246		)
Short-term borrowings, net	—			—			(32		)	32			—
Other	(1		)	(6		)	(2		)	—			(9		)
Net cash provided from financing activities	981			191			122			(986		)	308
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(10		)	(175		)	(350		)	—			(535		)
Nuclear fuel	—			—			(207		)	—			(207		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			1,167			—			1,167
Purchases of investment securities held in trusts	—			—			(1,194		)	—			(1,194		)
Loans to affiliated companies, net	1			(715		)	(337		)	996			(55		)
Other	(1		)	(5		)	—			—			(6		)
Net cash used for investing activities	(10		)	(878		)	(921		)	996			(813		)
Net change in cash and cash equivalents	—			(4		)	—			—			(4		)
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3

XML

Pension and Other Postemployment Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	$ 49	$ 40	$ 147	$ 120
Interest costs	93	97	279	291
Expected return on plan assets	(125)	(121)	(375)	(363)
Amortization of prior service cost (credit)	3	3	9	9
Net periodic cost (credits)	20	19	60	57
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	3	3	9	9
Interest costs	9	12	27	36
Expected return on plan assets	(8)	(9)	(24)	(27)
Amortization of prior service cost (credit)	(50)	(50)	(157)	(152)
Net periodic cost (credits)	(46)	(44)	(145)	(134)
FirstEnergy | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic cost (credits)	16	14	41	41
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic cost (credits)	(31)	(30)	(95)	(92)
FES | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic cost (credits)	5	5	13	13
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic cost (credits)	$ (4)	$ (4)	$ (12)	$ (12)

XML

Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2013

Statement of Other Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income

The changes in AOCI, net of tax, in the three and nine months ended September 30, 2013 and 2012, for FirstEnergy and FES are shown in the following tables:

FirstEnergy
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2013	$	(37	)	$	13		$	347		$	323
Other comprehensive income before reclassifications	—			5			—			5
Amounts reclassified from AOCI	1			(1		)	(29		)	(29		)
Net other comprehensive income (loss)	1			4			(29		)	(24		)
AOCI Balance as of September 30, 2013	$	(36	)	$	17		$	318		$	299
AOCI Balance as of July 1, 2012	$	(39	)	$	27		$	401		$	389
Other comprehensive income before reclassifications	—			25			—			25
Amounts reclassified from AOCI	—			(25		)	(22		)	(47		)
Net other comprehensive loss	—			—			(22		)	(22		)
AOCI Balance as of September 30, 2012	$	(39	)	$	27		$	379		$	367

FES
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of July 1, 2013	$	1		$	12		$	49		$	62
Other comprehensive income before reclassifications	—			4			—			4
Amounts reclassified from AOCI	—			(1		)	(3		)	(4		)
Net other comprehensive income (loss)	—			3			(3		)	—
AOCI Balance as of September 30, 2013	$	1		$	15		$	46		$	62
AOCI Balance as of July 1, 2012	$	6		$	25		$	53		$	84
Other comprehensive income (loss) before reclassifications	(1		)	24			—			23
Amounts reclassified from AOCI	(1		)	(25		)	(3		)	(29		)
Net other comprehensive loss	(2		)	(1		)	(3		)	(6		)
AOCI Balance as of September 30, 2012	$	4		$	24		$	50		$	78

FirstEnergy
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
Other comprehensive income before reclassifications	—			19			—			19
Amounts reclassified from AOCI	2			(17		)	(90		)	(105		)
Net other comprehensive income (loss)	2			2			(90		)	(86		)
AOCI Balance as of September 30, 2013	$	(36	)	$	17		$	318		$	299
AOCI Balance as of January 1, 2012	$	(39	)	$	19		$	446		$	426
Other comprehensive income before reclassifications	1			38			5			44
Amounts reclassified from AOCI	(1		)	(30		)	(72		)	(103		)
Net other comprehensive income (loss)	—			8			(67		)	(59		)
AOCI Balance as of September 30, 2012	$	(39	)	$	27		$	379		$	367

FES
	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
Other comprehensive income before reclassifications	—			17			—			17
Amounts reclassified from AOCI	(2		)	(15		)	(10		)	(27		)
Net other comprehensive income (loss)	(2		)	2			(10		)	(10		)
AOCI Balance as of September 30, 2013	$	1		$	15		$	46		$	62
AOCI Balance as of January 1, 2012	$	8		$	16		$	52		$	76
Other comprehensive income before reclassifications	—			37			8			45
Amounts reclassified from AOCI	(4		)	(29		)	(10		)	(43		)
Net other comprehensive income (loss)	(4		)	8			(2		)	2
AOCI Balance as of September 30, 2012	$	4		$	24		$	50		$	78

Reclassification out of Accumulated Other Comprehensive Income

The following amounts were reclassified from AOCI in the three months ended September 30, 2013 and 2012:

FE	Three Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
Long-term debt	3			2			Interest expense
	2			—			Total before taxes
	(1		)	—			Income taxes
	$	1		$	—		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(2	)	$	(40	)	Investment income
	1			15			Income taxes
	$	(1	)	$	(25	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(47	)	$	(47	)	(a)
	18			25			Income taxes
	$	(29	)	$	(22	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES	Three Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(1	)	$	(2	)	Other operating expenses
	1			1			Income taxes (benefits)
	$	—		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(2	)	$	(40	)	Investment income (loss)
	1			15			Income taxes (benefits)
	$	(1	)	$	(25	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			2			Income taxes (benefits)
	$	(3	)	$	(3	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

The following amounts were reclassified from AOCI in the nine months ended September 30, 2013 and 2012:

FE	Nine Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(7	)	Other operating expenses
Long-term debt	9			6			Interest expense
	4			(1		)	Total before taxes
	(2		)	—			Income taxes
	$	2		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(27	)	$	(48	)	Investment income
	10			18			Income taxes
	$	(17	)	$	(30	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(148	)	$	(143	)	(a)
	58			71			Income taxes
	$	(90	)	$	(72	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES	Nine Months Ended September 30						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2013			2012
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(5	)	$	(6	)	Other operating expenses
Long-term debt	2			—			Interest expense
	(3		)	(6		)	Total before taxes
	1			2			Income taxes (benefits)
	$	(2	)	$	(4	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(24	)	$	(46	)	Investment income (loss)
	9			17			Income taxes (benefits)
	$	(15	)	$	(29	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(16	)	$	(15	)	(a)
	6			5			Income taxes (benefits)
	$	(10	)	$	(10	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 5, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

XML

Supplemental Guarantor Information (Tables)

9 Months Ended

Sep. 30, 2013

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 September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,654		$	528		$	440		$	(943	)	$	1,679
OPERATING EXPENSES:
Fuel	—			249			55			—			304
Purchased power from affiliates	1,009			—			65			(942		)	132
Purchased power from non-affiliates	720			4			—			—			724
Other operating expenses	147			65			114			13			339
Provision for depreciation	1			33			46			—			80
General taxes	21			9			5			—			35
Total operating expenses	1,898			360			285			(929		)	1,614
OPERATING INCOME (LOSS)	(244		)	168			155			(14		)	65
OTHER INCOME (EXPENSE):
Loss on debt redemptions	—			—			—			—			—
Investment income (loss)	2			—			(1		)	(4		)	(3		)
Miscellaneous income, including net income from equity investees	180			19			—			(178		)	21
Interest expense — affiliates	(3		)	(2		)	(1		)	5			(1		)
Interest expense — other	(13		)	(24		)	(13		)	15			(35		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	166			(6		)	(7		)	(162		)	(9		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(78		)	162			148			(176		)	56
INCOME TAXES (BENEFITS)	(118		)	111			28			2			23
NET INCOME FROM CONTINUING OPERATIONS	40			51			120			(178		)	33
Discontinued operations (net of income taxes of $5)	—			7			—			—			7
NET INCOME	$	40		$	58		$	120		$	(178	)	$	40
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	40		$	58		$	120		$	(178	)	$	40
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(5		)	—			5			(5		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available-for-sale securities	5			—			5			(5		)	5
Other comprehensive income (loss)	(1		)	(5		)	5			—			(1		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(2		)	3			(1		)	(1		)
Other comprehensive income (loss), net of tax	—			(3		)	2			1			—
COMPREHENSIVE INCOME	$	40		$	55		$	122		$	(177	)	$	40

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)

(Unaudited)

For the Nine Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	4,575		$	1,612		$	1,337		$	(2,869	)	$	4,655
OPERATING EXPENSES:
Fuel	—			782			154			—			936
Purchased power from affiliates	3,072			—			197			(2,868		)	401
Purchased power from non-affiliates	1,749			6			—			—			1,755
Other operating expenses	484			208			376			37			1,105
Provision for depreciation	4			96			134			(3		)	231
General taxes	60			28			18			—			106
Total operating expenses	5,369			1,120			879			(2,834		)	4,534
OPERATING INCOME (LOSS)	(794		)	492			458			(35		)	121
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(103		)	—			—			—			(103		)
Investment income	4			—			3			(11		)	(4		)
Miscellaneous income, including net income from equity investees	543			23			—			(537		)	29
Interest expense — affiliates	(10		)	(4		)	(5		)	12			(7		)
Interest expense — other	(50		)	(79		)	(42		)	45			(126		)
Capitalized interest	1			1			26			—			28
Total other income (expense)	385			(59		)	(18		)	(491		)	(183		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(409		)	433			440			(526		)	(62		)
INCOME TAXES (BENEFITS)	(380		)	215			138			8			(19		)
NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(29		)	218			302			(534		)	(43		)
Discontinued operations (net of income taxes of $8)	—			14			—			—			14
NET INCOME (LOSS)	$	(29	)	$	232		$	302		$	(534	)	$	(29	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(29	)	$	232		$	302		$	(534	)	$	(29	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(16		)	(15		)	—			15			(16		)
Amortized gain on derivative hedges	(3		)	—			—			—			(3		)
Change in unrealized gain on available-for-sale securities	2			—			2			(2		)	2
Other comprehensive income (loss)	(17		)	(15		)	2			13			(17		)
Income taxes (benefits) on other comprehensive income (loss)	(7		)	(6		)	1			5			(7		)
Other comprehensive income (loss), net of tax	(10		)	(9		)	1			8			(10		)
COMPREHENSIVE INCOME (LOSS)	$	(39	)	$	223		$	303		$	(526	)	$	(39	)

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,523		$	610		$	395		$	(978	)	$	1,550
OPERATING EXPENSES:
Fuel	—			248			55			—			303
Purchased power from affiliates	1,042			—			67			(978		)	131
Purchased power from non-affiliates	499			3			—			—			502
Other operating expenses	130			78			122			12			342
Provision for depreciation	1			29			41			(1		)	70
General taxes	20			10			5			—			35
Total operating expenses	1,692			368			290			(967		)	1,383
OPERATING INCOME (LOSS)	(169		)	242			105			(11		)	167
OTHER INCOME (EXPENSE):
Investment income	1			5			37			(5		)	38
Miscellaneous income, including net income from equity investees	317			—			—			(316		)	1
Interest expense — affiliates	(5		)	(2		)	(1		)	5			(3		)
Interest expense — other	(25		)	(27		)	(15		)	16			(51		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	288			(23		)	29			(300		)	(6		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	119			219			134			(311		)	161
INCOME TAXES (BENEFITS)	18			(14		)	59			2			65
NET INCOME FROM CONTINUING OPERATIONS	101			233			75			(313		)	96
Discontinued operations (net of income taxes of $3)	—			5			—			—			5
NET INCOME	$	101		$	238		$	75		$	(313	)	$	101
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	101		$	238		$	75		$	(313	)	$	101
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(4		)	—			4			(5		)
Amortized gain on derivative hedges	(2		)	—			—			—			(2		)
Change in unrealized gain on available for sale securities	(2		)	—			(1		)	1			(2		)
Other comprehensive loss	(9		)	(4		)	(1		)	5			(9		)
Income tax benefits on other comprehensive loss	(3		)	(2		)	—			2			(3		)
Other comprehensive loss, net of tax	(6		)	(2		)	(1		)	3			(6		)
COMPREHENSIVE INCOME	$	95		$	236		$	74		$	(310	)	$	95

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Nine Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	4,443		$	1,777		$	1,262		$	(2,971	)	$	4,511
OPERATING EXPENSES:
Fuel	—			824			154			—			978
Purchased power from affiliates	3,163			—			189			(2,971		)	381
Purchased power from non-affiliates	1,420			5			—			—			1,425
Other operating expenses	313			268			410			37			1,028
Provision for depreciation	3			87			114			(4		)	200
General taxes	60			28			16			—			104
Total operating expenses	4,959			1,212			883			(2,938		)	4,116
OPERATING INCOME (LOSS)	(516		)	565			379			(33		)	395
OTHER INCOME (EXPENSE):
Investment income	2			14			49			(15		)	50
Miscellaneous income, including net income from equity investees	854			19			—			(848		)	25
Interest expense — affiliates	(14		)	(5		)	(3		)	15			(7		)
Interest expense — other	(72		)	(79		)	(36		)	47			(140		)
Capitalized interest	—			3			24			—			27
Total other income (expense)	770			(48		)	34			(801		)	(45		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	254			517			413			(834		)	350
INCOME TAXES (BENEFITS)	32			(25		)	124			8			139
NET INCOME FROM CONTINUING OPERATIONS	222			542			289			(842		)	211
Discontinued operations (net of income taxes of $6)	—			11			—			—			11
NET INCOME	$	222		$	553		$	289		$	(842	)	$	222
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	222		$	553		$	289		$	(842	)	$	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(2		)	(1		)	—			1			(2		)
Amortized gain on derivative hedges	(6		)	—			—			—			(6		)
Change in unrealized gain on available-for-sale securities	11			—			12			(12		)	11
Other comprehensive income (loss)	3			(1		)	12			(11		)	3
Income taxes (benefits) on other comprehensive income (loss)	1			(1		)	5			(4		)	1
Other comprehensive income, net of tax	2			—			7			(7		)	2
COMPREHENSIVE INCOME	$	224		$	553		$	296		$	(849	)	$	224

Condensed Consolidating Balance Sheets

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of September 30, 2013	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	524		—		—		—			524
Affiliated companies	420		445		285		(631		)	519
Other	76		22		25		—			123
Notes receivable from affiliated companies	337		163		764		(1,010		)	254
Materials and supplies	64		161		214		—			439
Derivatives	139		—		—		—			139
Prepayments and other	61		37		6		1			105
	1,621		830		1,294		(1,640		)	2,105
PROPERTY, PLANT AND EQUIPMENT:
In service	104		6,068		6,719		(383		)	12,508
Less — Accumulated provision for depreciation	26		1,928		2,882		(187		)	4,649
	78		4,140		3,837		(196		)	7,859
Construction work in progress	21		115		980		—			1,116
	99		4,255		4,817		(196		)	8,975
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,270		—			1,270
Investment in affiliated companies	5,503		—		—		(5,503		)	—
Other	1		10		—		—			11
	5,504		10		1,270		(5,503		)	1,281
ASSETS HELD FOR SALE (NOTE 16)	—		121		—		—			121
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	16		169		—		(185		)	—
Customer intangibles	99		—		—		—			99
Goodwill	23		—		—		—			23
Property taxes	—		14		22		—			36
Unamortized sale and leaseback costs	—		—		—		161			161
Derivatives	65		—		—		—			65
Other	174		242		14		(162		)	268
	377		425		36		(186		)	652
	$	7,601	$	5,641	$	7,417	$	(7,525	)	$	13,134
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	366	$	514	$	(22	)	$	859
Short-term borrowings-
Affiliated companies	696		314		—		(1,010		)	—
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	643		386		378		(631		)	776
Other	88		125		—		—			213
Accrued taxes	7		17		37		(19		)	42
Derivatives	103		—		—		—			103
Other	46		72		22		36			176
	1,584		1,284		951		(1,646		)	2,173
CAPITALIZATION:
Total equity	5,229		2,010		3,469		(5,479		)	5,229
Long-term debt and other long-term obligations	712		1,873		789		(1,196		)	2,178
	5,941		3,883		4,258		(6,675		)	7,407
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		866			866
Accumulated deferred income taxes	—		—		770		(71		)	699
Asset retirement obligations	—		176		983		—			1,159
Retirement benefits	27		228		—		—			255
Derivatives	22		—		—		—			22
Other	27		70		455		1			553
	76		474		2,208		796			3,554
	$	7,601	$	5,641	$	7,417	$	(7,525	)	$	13,134

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2012	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	3	$	—	$	—		$	3
Receivables-
Customers	483		—		—		—			483
Affiliated companies	232		417		478		(748		)	379
Other	56		19		16		—			91
Notes receivable from affiliated companies	366		7		607		(704		)	276
Materials and supplies	66		231		208		—			505
Derivatives	158		—		—		—			158
Prepayments and other	38		39		10		—			87
	1,399		716		1,319		(1,452		)	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	91		5,899		6,391		(384		)	11,997
Less — Accumulated provision for depreciation	32		1,915		2,646		(185		)	4,408
	59		3,984		3,745		(199		)	7,589
Construction work in progress	34		230		877		—			1,141
	93		4,214		4,622		(199		)	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,283		—			1,283
Investment in affiliated companies	4,972		—		—		(4,972		)	—
Other	—		12		—		—			12
	4,972		12		1,283		(4,972		)	1,295
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		313		—		(313		)	—
Customer intangibles	110		—		—		—			110
Goodwill	24		—		—		—			24
Property taxes	—		14		22		—			36
Unamortized sale and leaseback costs	—		—		—		119			119
Derivatives	99		—		—		—			99
Other	160		194		5		(106		)	253
	393		521		27		(300		)	641
	$	6,857	$	5,463	$	7,251	$	(6,923	)	$	12,648
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	586	$	537	$	(22	)	$	1,102
Short-term borrowings-
Affiliated companies	358		346		—		(704		)	—
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	748		143		583		(748		)	726
Other	63		96		—		—			159
Accrued taxes	126		25		20		—			171
Derivatives	124		—		—		—			124
Other	71		148		15		46			280
	1,491		1,348		1,155		(1,428		)	2,566
CAPITALIZATION:
Total equity	3,763		1,787		3,165		(4,952		)	3,763
Long-term debt and other long-term obligations	1,482		2,009		834		(1,207		)	3,118
	5,245		3,796		3,999		(6,159		)	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		892			892
Accumulated deferred income taxes	28		—		714		(227		)	515
Asset retirement obligations	—		29		936		—			965
Retirement benefits	26		215		—		—			241
Derivatives	37		—		—		—			37
Other	30		75		447		(1		)	551
	121		319		2,097		664			3,201
	$	6,857	$	5,463	$	7,251	$	(6,923	)	$	12,648

Condensed Consolidating Statements of Cash Flows

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(1,018	)	$	712		$	705		$	(10	)	$	389
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	338			—			—			(338		)	—
Equity contribution from parent	1,500			—			—			—			1,500
Redemptions and Repayments-
Long-term debt	(769		)	(352		)	(68		)	10			(1,179		)
Short-term borrowings, net	—			(32		)	—			32			—
Tender premiums	(67		)	—			—			—			(67		)
Other	(3		)	(4		)	—			—			(7		)
Net cash provided from (used for) financing activities	999			(388		)	(68		)	(296		)	247
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(9		)	(192		)	(276		)	—			(477		)
Nuclear fuel	—			—			(159		)	—			(159		)
Proceeds from asset sales	—			21			—			—			21
Sales of investment securities held in trusts	—			—			650			—			650
Purchases of investment securities held in trusts	—			—			(694		)	—			(694		)
Loans to affiliated companies, net	28			(156		)	(156		)	306			22
Other	—			2			(2		)	—			—
Net cash provided from (used for) investing activities	19			(325		)	(637		)	306			(637		)
Net change in cash and cash equivalents	—			(1		)	—			—			(1		)
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Nine Months Ended September 30, 2012	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(971	)	$	683		$	799		$	(10	)	$	501
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			317			243			—			560
Short-term borrowings, net	982			49			—			(1,028		)	3
Redemptions and Repayments-
Long-term debt	—			(169		)	(87		)	10			(246		)
Short-term borrowings, net	—			—			(32		)	32			—
Other	(1		)	(6		)	(2		)	—			(9		)
Net cash provided from financing activities	981			191			122			(986		)	308
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(10		)	(175		)	(350		)	—			(535		)
Nuclear fuel	—			—			(207		)	—			(207		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			1,167			—			1,167
Purchases of investment securities held in trusts	—			—			(1,194		)	—			(1,194		)
Loans to affiliated companies, net	1			(715		)	(337		)	996			(55		)
Other	(1		)	(5		)	—			—			(6		)
Net cash used for investing activities	(10		)	(878		)	(921		)	996			(813		)
Net change in cash and cash equivalents	—			(4		)	—			—			(4		)
Cash and cash equivalents at beginning of period	—			7			—			—			7
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3

XML

Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended				3 Months Ended		9 Months Ended			3 Months Ended	9 Months Ended			0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Jul. 08, 2013 FirstEnergy and AE Supply plant	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Sep. 30, 2013 FirstEnergy and FES	Sep. 30, 2013 Operating Loss Carryforward [Member] FirstEnergy and AE Supply	Sep. 30, 2013 Operating Loss Carryforward [Member] FES	Dec. 31, 2012 Federal	Dec. 31, 2012 State and local	Jul. 09, 2013 State and local PENNSYLVANIA After December 31, 2013	Jul. 09, 2013 State and local PENNSYLVANIA After December 31, 2014
Income Taxes (Textuals) [Abstract]
Increase in unrecognized tax benefits	$ 5
Unrecognized tax benefits	4		4
Accrued interest	10		10		9
Deferred tax assets, current														319
Deferred tax assets, long-term														466	389
Deferred tax assets, portion not expected to be recognized in next fiscal year														319
Deferred tax asset, current, net operating loss carryforward	290		290
Impairment of Long-lived Assets, Number of Plants to be Deactivated						2
Valuation Allowance, Deferred Tax Asset, Change in Amount												20	4
Operating Loss Carryforward, Limitations on Use, Percent of Taxable Income																25.00%	30.00%
Operating Loss Carryforward, Limitations on Use, Amount																4	5
Valuation Allowance, Deferred Tax Asset, Change in Amount, Next Fiscal Quarter	8
Deferred Tax Liabilities, Decreases Resulting from Changes to State Apportionment Factors	9
Deferred Tax Liabilities, Decreases Resulting from Changes in Assessment of Business Operations	22
Effective tax rate	26.90%	42.10%	35.60%	41.70%			41.10%	40.50%	30.60%	39.70%	37.00%
Loss on debt redemptions	$ (9)	$ 0	$ 132	$ 0			$ 0	$ 0	$ 103	$ 0

XML

Impairment of Long-lived Assets (Tables)

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Schedule of Generating Plant Retirements

On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013:

Generating Units	MW Capacity	Location
Hatfield's Ferry, Units 1-3	1,710	Masontown, Pennsylvania
Mitchell, Units 2-3	370	Courtney, Pennsylvania

XML

Derivative Instruments (Details 4) (Not Designated as Hedging Instrument, Subject to Regulatory Accounting, Excluded from Earnings, USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	$ 0	$ (47)	$ (34)	$ (325)
Realized Gain (Loss) on Derivative Instrument	13	60	56	201
NUGs
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	7	(50)	(13)	(183)
Realized Gain (Loss) on Derivative Instrument	14	61	57	194
LCAPP
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	(8)	3	(22)	(142)
Realized Gain (Loss) on Derivative Instrument	0	0	0	0
Regulated FTRs
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	1	0	1	0
Realized Gain (Loss) on Derivative Instrument	$ (1)	$ (1)	$ (1)	$ 7

XML

Supplemental Guarantor Information (Details 1) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2012	Dec. 31, 2011
CURRENT ASSETS:
Cash and cash equivalents	$ 222	$ 172	$ 150	$ 202
Receivables-
Customers	1,579	1,614
Other Receivables	231	315
Materials and supplies, at average cost	731	861
Derivatives	140	160
Prepayments and other	262	208
Total current assets	3,559	3,768
PROPERTY, PLANT AND EQUIPMENT:
In service	44,089	43,210
Less - Accumulated provision for depreciation	13,167	12,600
Property, plant and equipment in service net of accumulated provision for depreciation	30,922	30,610
Construction work in progress	2,301	2,293
Total net property, plant and equipment	33,223	32,903
INVESTMENTS:
Nuclear plant decommissioning trusts	2,183	2,204
Other	876	936
Total other property and investments	3,105	3,194
ASSETS HELD FOR SALE, NET (NOTE 16):	234	0
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,447	6,444
Other	1,698	1,719
Total deferred charges and other assets	10,262	10,541
Total assets	50,383	50,406	48,738
CURRENT LIABILITIES:
Currently payable long-term debt	1,889	1,999
Accounts payable-
Accrued taxes	401	543
Derivatives	105	126
Other	872	1,038
Total current liabilities	7,955	7,605
CAPITALIZATION:
Total equity	12,544	13,084
Long-term debt and other long-term obligations	15,291	15,179
Total capitalization	27,838	28,272
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	866	892
Accumulated deferred income taxes	6,603	6,616
Asset retirement obligations	1,834	1,599
Retirement benefits	3,104	3,080
Other	1,716	1,836
Total noncurrent liabilities	14,590	14,529
Total liabilities and capitalization	50,383	50,406
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	524	483
Affiliated companies	420	232
Other Receivables	76	56
Notes receivable from affiliated companies	337	366
Materials and supplies, at average cost	64	66
Derivatives	139	158
Prepayments and other	61	38
Total current assets	1,621	1,399
PROPERTY, PLANT AND EQUIPMENT:
In service	104	91
Less - Accumulated provision for depreciation	26	32
Property, plant and equipment in service net of accumulated provision for depreciation	78	59
Construction work in progress	21	34
Total net property, plant and equipment	99	93
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	5,503	4,972
Other	1	0
Total other property and investments	5,504	4,972
ASSETS HELD FOR SALE, NET (NOTE 16):	0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	16	0
Customer intangibles	99	110
Goodwill	23	24
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	65	99
Other	174	160
Total deferred charges and other assets	377	393
Total assets	7,601	6,857
CURRENT LIABILITIES:
Currently payable long-term debt	1	1
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	643	748
Other	88	63
Accrued taxes	7	126
Derivatives	103	124
Other	46	71
Total current liabilities	1,584	1,491
CAPITALIZATION:
Total equity	5,229	3,763
Long-term debt and other long-term obligations	712	1,482
Total capitalization	5,941	5,245
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	28
Asset retirement obligations	0	0
Retirement benefits	27	26
Derivatives	22	37
Other	27	30
Total noncurrent liabilities	76	121
Total liabilities and capitalization	7,601	6,857
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	696	358
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	3	3	7
Receivables-
Customers	0	0
Affiliated companies	445	417
Other Receivables	22	19
Notes receivable from affiliated companies	163	7
Materials and supplies, at average cost	161	231
Derivatives	0	0
Prepayments and other	37	39
Total current assets	830	716
PROPERTY, PLANT AND EQUIPMENT:
In service	6,068	5,899
Less - Accumulated provision for depreciation	1,928	1,915
Property, plant and equipment in service net of accumulated provision for depreciation	4,140	3,984
Construction work in progress	115	230
Total net property, plant and equipment	4,255	4,214
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	10	12
Total other property and investments	10	12
ASSETS HELD FOR SALE, NET (NOTE 16):	121
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	169	313
Customer intangibles	0	0
Goodwill	0	0
Property taxes	14	14
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	242	194
Total deferred charges and other assets	425	521
Total assets	5,641	5,463
CURRENT LIABILITIES:
Currently payable long-term debt	366	586
Short-term borrowings	4	4
Accounts payable-
Affiliated companies	386	143
Other	125	96
Accrued taxes	17	25
Derivatives	0	0
Other	72	148
Total current liabilities	1,284	1,348
CAPITALIZATION:
Total equity	2,010	1,787
Long-term debt and other long-term obligations	1,873	2,009
Total capitalization	3,883	3,796
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	176	29
Retirement benefits	228	215
Derivatives	0	0
Other	70	75
Total noncurrent liabilities	474	319
Total liabilities and capitalization	5,641	5,463
FGCO | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	314	346
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	285	478
Other Receivables	25	16
Notes receivable from affiliated companies	764	607
Materials and supplies, at average cost	214	208
Derivatives	0	0
Prepayments and other	6	10
Total current assets	1,294	1,319
PROPERTY, PLANT AND EQUIPMENT:
In service	6,719	6,391
Less - Accumulated provision for depreciation	2,882	2,646
Property, plant and equipment in service net of accumulated provision for depreciation	3,837	3,745
Construction work in progress	980	877
Total net property, plant and equipment	4,817	4,622
INVESTMENTS:
Nuclear plant decommissioning trusts	1,270	1,283
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,270	1,283
ASSETS HELD FOR SALE, NET (NOTE 16):	0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	22	22
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	14	5
Total deferred charges and other assets	36	27
Total assets	7,417	7,251
CURRENT LIABILITIES:
Currently payable long-term debt	514	537
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	378	583
Other	0	0
Accrued taxes	37	20
Derivatives	0	0
Other	22	15
Total current liabilities	951	1,155
CAPITALIZATION:
Total equity	3,469	3,165
Long-term debt and other long-term obligations	789	834
Total capitalization	4,258	3,999
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	770	714
Asset retirement obligations	983	936
Retirement benefits	0	0
Derivatives	0	0
Other	455	447
Total noncurrent liabilities	2,208	2,097
Total liabilities and capitalization	7,417	7,251
Nuclear Generation Corp | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	0	0
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(631)	(748)
Other Receivables	0	0
Notes receivable from affiliated companies	(1,010)	(704)
Materials and supplies, at average cost	0	0
Derivatives	0	0
Prepayments and other	1	0
Total current assets	(1,640)	(1,452)
PROPERTY, PLANT AND EQUIPMENT:
In service	(383)	(384)
Less - Accumulated provision for depreciation	(187)	(185)
Property, plant and equipment in service net of accumulated provision for depreciation	(196)	(199)
Construction work in progress	0	0
Total net property, plant and equipment	(196)	(199)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(5,503)	(4,972)
Other	0	0
Total other property and investments	(5,503)	(4,972)
ASSETS HELD FOR SALE, NET (NOTE 16):	0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(185)	(313)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	161	119
Derivatives	0	0
Other	(162)	(106)
Total deferred charges and other assets	(186)	(300)
Total assets	(7,525)	(6,923)
CURRENT LIABILITIES:
Currently payable long-term debt	(22)	(22)
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	(631)	(748)
Other	0	0
Accrued taxes	(19)	0
Derivatives	0	0
Other	36	46
Total current liabilities	(1,646)	(1,428)
CAPITALIZATION:
Total equity	(5,479)	(4,952)
Long-term debt and other long-term obligations	(1,196)	(1,207)
Total capitalization	(6,675)	(6,159)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	866	892
Accumulated deferred income taxes	(71)	(227)
Asset retirement obligations	0	0
Retirement benefits	0	0
Derivatives	0	0
Other	1	(1)
Total noncurrent liabilities	796	664
Total liabilities and capitalization	(7,525)	(6,923)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	(1,010)	(704)
FES
CURRENT ASSETS:
Cash and cash equivalents	2	3	3	7
Receivables-
Customers	524	483
Affiliated companies	519	379
Other Receivables	123	91
Notes receivable from affiliated companies	254	276
Materials and supplies, at average cost	439	505
Derivatives	139	158
Prepayments and other	105	87
Total current assets	2,105	1,982
PROPERTY, PLANT AND EQUIPMENT:
In service	12,508	11,997
Less - Accumulated provision for depreciation	4,649	4,408
Property, plant and equipment in service net of accumulated provision for depreciation	7,859	7,589
Construction work in progress	1,116	1,141
Total net property, plant and equipment	8,975	8,730
INVESTMENTS:
Nuclear plant decommissioning trusts	1,270	1,283
Investment in affiliated companies	0	0
Other	11	12
Total other property and investments	1,281	1,295
ASSETS HELD FOR SALE, NET (NOTE 16):	121	0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	99	110
Goodwill	23	24
Property taxes	36	36
Unamortized sale and leaseback costs	161	119
Derivatives	65	99
Other	268	253
Total deferred charges and other assets	652	641
Total assets	13,134	12,648
CURRENT LIABILITIES:
Currently payable long-term debt	859	1,102
Short-term borrowings	4	4
Accounts payable-
Affiliated companies	776	726
Other	213	159
Accrued taxes	42	171
Derivatives	103	124
Other	176	280
Total current liabilities	2,173	2,566
CAPITALIZATION:
Total equity	5,229	3,763
Long-term debt and other long-term obligations	2,178	3,118
Total capitalization	7,407	6,881
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	866	892
Accumulated deferred income taxes	699	515
Asset retirement obligations	1,159	965
Retirement benefits	255	241
Derivatives	22	37
Other	553	551
Total noncurrent liabilities	3,554	3,201
Total liabilities and capitalization	13,134	12,648
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$ 0	$ 0

XML

Derivative Instruments (Details 3) (Not Designated as Hedging Instrument, USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
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
Realized Gain (Loss) Reclassified	$ 20	$ 52	$ 48	$ 278
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
Realized Gain (Loss) Reclassified	(17)	(27)	(30)	(248)
Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	3	2	(15)	84
Realized Gain (Loss) Reclassified	(10)	(10)	(28)	(51)
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
Realized Gain (Loss) Reclassified	(2)	3		2
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
Unrealized Gain (Loss) Recognized		20
Realized Gain (Loss) Reclassified		6		6
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
Realized Gain (Loss) Reclassified	14	46	29	260
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
Realized Gain (Loss) Reclassified	(17)	(27)	(30)	(248)
Power Contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	11	7	(5)	72
Realized Gain (Loss) Reclassified	0	0	0	0
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
Realized Gain (Loss) Reclassified	(2)	3		2
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
Unrealized Gain (Loss) Recognized		0
Realized Gain (Loss) Reclassified		0		0
FTRs | Revenue
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	6	6	19	18
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
Realized Gain (Loss) Reclassified	0	0	0	0
FTRs | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized	(8)	(5)	(10)	12
Realized Gain (Loss) Reclassified	(10)	(10)	(28)	(51)
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
Realized Gain (Loss) Reclassified	0	0		0
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
Unrealized Gain (Loss) Recognized		0
Realized Gain (Loss) Reclassified		0		0
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
Realized Gain (Loss) Reclassified	0	0	0	0
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
Realized Gain (Loss) Reclassified	0	0	0	0
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
Unrealized Gain (Loss) Recognized	0	0	0	0
Realized Gain (Loss) Reclassified	0	0	0	0
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
Realized Gain (Loss) Reclassified	0	0		0
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
Unrealized Gain (Loss) Recognized		20
Realized Gain (Loss) Reclassified		$ 6		$ 6

XML

Goodwill (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended			1 Months Ended	9 Months Ended		9 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012	Oct. 31, 2013 Subsequent Event	Sep. 30, 2013 Regulated Distribution	Sep. 30, 2012 Regulated Distribution	Sep. 30, 2013 Regulated Independent Transmission	Sep. 30, 2013 Competitive Energy Services		Sep. 30, 2012 Competitive Energy Services	Sep. 30, 2013 Corporate and Other
Goodwill [Line Items]
Goodwill, Other Changes				$ 67
Goodwill [Roll Forward]
Goodwill	6,447		6,444		5,025	5,025	526	896		893	0
Classification to Assets Held for Sale	(29)	[1]			0		0	(29)	[1]		0
Goodwill	$ 6,418		$ 6,444		$ 5,025	$ 5,025	$ 526	$ 867		$ 893	$ 0

[1] See Note 16, Discontinued Operations and Assets Held for Sale.

XML

Commitments, Guarantees and Contingencies (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 903
Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	501
BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	545
FES
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	755
FES | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	440
FES | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	484
AE Supply
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	58
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	90
Utilities | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	55
Utilities | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 55

XML

Commitments, Guarantees and Contingencies

9 Months Ended

Sep. 30, 2013

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 September 30, 2013, outstanding guarantees and other assurances aggregated approximately $4.4 billion, consisting of parental guarantees ($1,403 million), subsidiaries' guarantees ($2,232 million) and other guarantees ($747 million).

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

COLLATERAL AND CONTINGENT-RELATED FEATURES

In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel, and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE'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 FE and its subsidiaries have margining provisions that require posting of collateral.Based on FES' power portfolio exposure as ofSeptember 30, 2013, FES has posted collateral of$150 million and AE supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of$16 million.

These credit-risk-related contingent features stipulate that if the subsidiary 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, or a “material adverse event,” the immediate posting of collateral or accelerated payments may be required of FE or its subsidiaries.The following table discloses the additional credit contingent contractual obligations as ofSeptember 30, 2013:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	440	$	6	$	55	$	501
BB+/Ba1 Credit Ratings	$	484	$	6	$	55	$	545
Full impact of credit contingent contractual obligations	$	755	$	58	$	90	$	903

Excluded from the preceding chart is the potential collateral obligations due to affiliate transactions between the Regulated Distribution Segment and Competitive Energy Services Segment.As ofSeptember 30, 2013, neither FES nor AE Supply had any collateral posted with their affiliates. In the event of a senior unsecured credit rating downgrade to below S&P's BB- or Moody's Ba3, FES and AE Supply would be required to post$77 millionand$2 million, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FirstEnergy is a guarantor under a syndicated three-year senior secured term loan facility due October 18, 2015, under which Global Holding borrowed $350 million. Proceeds from the loan were used to repay Signal Peak's and Global Rail's maturing$350 millionsyndicated two-year senior secured term loan facility. In addition to FirstEnergy, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, have also provided their joint and several guaranties of the obligations of Global Holding under the new facility.

In connection with the new facility,69.99%of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective33-1/3%membership interests in Global Holding, are pledged to the lenders under the new facility as collateral.

FirstEnergy, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed to use their best efforts to refinance the new facility no later than July 20, 2015, which reflects the terms of an amendment dated August 14, 2013, on a non-recourse basis so that FirstEnergy's guaranty can be terminated and/or released.If that refinancing does not occur, FirstEnergy may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the new facility in full.In lieu of providing such funding, the co-owners, at FirstEnergy's option, may provide their several guaranties of Global Holding's obligations under the facility.FirstEnergy receives a fee for providing its guaranty, payable semiannually, which accrued at a rate of4%through December 31, 2012, and accrues at a rate of5%from January 1, 2013 through October 18, 2015, which amends the rate in the prior agreement, in each case based upon the average daily outstanding aggregate commitments under the facility for such semiannual period.

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, utilizing 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 FG 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.FG believes the claims are without merit and intends to vigorously 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 possible loss or range of loss.

In January 2009, the EPA issued an 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, as a former owner of the facilities, is 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 during 1991 to 1994 without pre-construction 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 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. DOJ 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 which affirmed the dismissal on August 21, 2013.PN believes the claims are without merit and intends to vigorously defend itself against the allegations made in these complaints.The parties dispute the scope of NYSEG's and PN's indemnity obligation to and from Edison International.PN is unable to predict the outcome of this matter or estimate the loss or possible range of loss.

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.FG intends to comply with the CAA and Ohio regulations, 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 an 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, January 31, 2013, and March 27, 2013, EPA issued additional CAA section 114 requests for the Harrison coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2007.AE 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 June 2005, the PA DEP and the Attorneys General of New York, New Jersey, Connecticut and Maryland filed suit against AE, AE Supply and the Allegheny Utilities 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 December 30, 2011, CSAPR was stayed by the U.S. Court of Appeals for the District of Columbia Circuit and was ultimately vacated by the Court on August 21, 2012.The Court has ordered EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR.On January 24, 2013, EPA and intervenors' petitions seeking rehearing or rehearing en banc were denied by the U.S. Court of Appeals for the District of Columbia Circuit.On June 24, 2013, the Supreme Court of the United States agreed to review the decision vacating CSAPR.Oral argument is scheduled for December 10, 2013.Depending on the outcome of these proceedings and how any final rules are ultimately implemented, the future cost of compliance may be substantial and changes to FirstEnergy's and FES' 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.On December 28, 2012, the WVDEP granted a conditional extension through April 16, 2016 for MATS compliance at the Fort Martin, Harrison and Pleasants stations.On March 20, 2013, the PA DEP granted an extension through April 16, 2016 for MATS compliance at the Hatfield's Ferry and Mansfield stations.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.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. Oral argument is scheduled for December 10, 2013.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 currently estimated to be approximately$465 million.

As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated.FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated.As of October 9, 2013, the Hatfield's Ferry and Mitchell stations were also deactivated.

FirstEnergy and FES have various long-term coal transportation agreements, some of which run through 2025 and certain of which are related to the plants described above.We have asserted force majeure defenses for delivery shortfalls under certain agreements, and we are in discussion with the applicable counterparties.Under one agreement, we have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately$45 million, and agreed to pay liquidated damages for delivery shortfalls, if any, for 2013 and 2014.As to another agreement, based on the state of current negotiations, penalties of approximately$25 millionfor delivery shortfalls for 2012 were recorded in the third quarter of 2013, and we could incur additional penalties for any delivery shortfalls in 2013 and 2014.If we fail to reach a resolution with applicable counterparties for the unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to our belief, the force majeure provisions or other defenses do not excuse delivery shortfalls, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.

Climate Change

There are a number of initiatives to reduce GHG emissions under consideration at the state, federal and international level.Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs to control emissions of certain GHGs.In his 2013 State of the Union address, President Obama called for Congressional action on GHG emissions indicating his administration will take action in the event Congress fails to act.In June 2013, the President's Climate Action Plan outlined Executive action to: (1) cut carbon pollution in America, including EPA carbon pollution standards for both new and existing power plants by17%by 2020 (from 2005 levels), (2) prepare the United States for the impacts of climate change, and (3) lead international efforts to combat global climate change and prepare for its impacts.

In September 2009, the EPA finalized a national GHG emissions collection and reporting rule that required the measurement and reporting of 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 pre-construction permits would be required including an emissions applicability threshold of75,000tons per year of CO₂equivalents for existing facilities under the CAA's PSD program. On April 13, 2012, the EPA proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units that are larger than25MW, which were ultimately withdrawn.On June 25, 2013, a Presidential memorandum directed EPA to complete, in a timely fashion, proposed new source performance standards for GHG emissions from newly constructed fossil fuel generating units, starting with re-proposal by September 20, 2013, and propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units.On September 20, 2013, EPA proposed a new source performance standard of 1,000 lbs. CO₂/MWH for large natural gas fired units (> 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for other natural gas fired units (≤ 850 mmBTU/hr), and 1,100 lbs. CO₂/MWH for fossil fuel fired units which would require partial carbon capture and storage.On October 15, 2013, the U.S. Supreme Court agreed to review a June 2012 D.C. Circuit Court of Appeals decision upholding EPA's May 2010 regulations to decide a single narrow question: "Whether EPA permissibly determined that its regulation of greenhouse gas emissions from new motor vehicles triggered permitting requirements under the CAA for stationary sources that emit greenhouse gases?" Depending on the outcome of these proceedings and how any final rules are ultimately implemented, future cost of compliance may be substantial and changes to FirstEnergy's and FES' operations may result.

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 by 2020, while developing countries, including Brazil, China and India, would agree to take mitigation actions, subject to their domestic measurement, reporting and verification.In December 2010, the U.N. Climate Change Conference in Cancun, Mexico resulted in an acknowledgment to reduce emissions from industrialized countries by 25 to 40 percent from 1990 emissions by 2020 and support enhanced action on climate change in the developing world.In December 2011 the 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.In December 2012, the U.N. Climate Change Conference in Doha, Qatar, resulted in countries agreeing to a new commitment period under the Kyoto Protocol beginning in 2020.The new Doha Amendment to establish a second commitment period requires the ratification of three-quarters of the parties to the Kyoto Protocol before it becomes effective.

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 operate 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.The period for finalizing the Section 316(b) regulation has been extended to November 20, 2013 under a Settlement Agreement between EPA and certain NGOs.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.

On April 19, 2013, the EPA proposed regulatory changes to the waste water effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423).The EPA proposedeighttreatment options for waste water discharges from electric power plants, of which four are "preferred" by the Agency.The preferred options range from more stringent chemical and biological treatment requirements to zero discharge requirements.The EPA is required to finalize this rulemaking by May 22, 2014, under a consent decree entered by a U.S. District Court and the treatment obligations are proposed to phase-in as waste water discharge permits are renewed on a5-year cycle from 2017 to 2022.Depending on the content of the EPA's final rule, the future costs of compliance with these standards may require material capital expenditures.

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 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$150 millionin 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 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 which requires the development of a TMDL limit for the river, a process that will take PA DEP approximately five years.However, the Hatfield's Ferry and Mitchell Plants in Pennsylvania that discharge into the Monongahela River were deactivated on October 9, 2013.

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 RCRA 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 April 19, 2013, the EPA stated it would "align" its proposed coal combustion residuals regulations with revised waste water discharge effluent limitations guidelines and standards for the Steam Electric Power Generating category (40 CFR Part 423) that were proposed on that date.On July 25, 2013, the House of Representatives passed H.R. 221 that would require CCRs to be regulated under Subtitle D of RCRA, as non-hazardous.Depending on the content of the EPA's final effluent limitations rule and the specifics of any "alignment", the future costs of compliance with such standards may require material capital expenditures.

On July 27, 2012, the PA DEP filed a complaint against FG in the U.S. District Court for the Western District of Pennsylvania with claims under the RCRA and Pennsylvania's Solid Waste Management Act regarding the LBR CCB Impoundment and simultaneously proposed a Consent Decree between PA DEP and FG to resolve those claims.On December 14, 2012, a modified Consent Decree that addresses public comments received by PA DEP was entered by the court, requiring FG 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 modified Consent Decree also requires payment of civil penalties of$800,000to resolve claims under the Solid Waste Management Act.On February 1, 2013, FG submitted a Feasibility Study analyzing various technical issues relevant to the closure of LBR.On March 28, 2013, FG submitted to the PA DEP a Closure Plan Major Permit Modification Application which provides for placing a final cap over LBR that would require15years to fully implement following the closure of LBR.The estimated cost for the proposed closure plan is$234 million, including environmental and other post closure costs.On October 3, 2013, the PA DEP issued a technical deficiency letter citing four main deficiencies with the Closure Plan: (1) seeking to accelerate the 15 year period proposed by FG for closure activities to complete closure in 9 years by commencing closure activities prior to 2017 as proposed by FG; (2) seeking to extend bond closure and post closure activities beyond the 45 years proposed by FG; (3) seeking active dewatering of the CCBs in areas where there are seeps impacted by the Impoundment; and (4) seeking an abatement plan for groundwater impacted by arsenic.The Bruce Mansfield Plant is pursuing several options for its CCBs following December 31, 2016, and on January 23, 2013, announced a plan for beneficial use of its CCBs for mine reclamation in LaBelle, Pennsylvania.In June 2013, a complaint filed in the U.S. District Court for the Western District of Pennsylvania, alleges the LaBelle site is in violation of RCRA and state laws.On December 20, 2012, the Environmental Integrity Project and others served FG with a citizen suit notice alleging CWA and PA Clean Streams Law Violations at LBR.

On October 10, 2013, a complaint was filed on behalf of approximately50individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment.The complaint states claims for private nuisance, negligence, negligence per se, reckless conduct and trespass related to alleged groundwater contamination and odors emanating from the Impoundment.FE, FG and FES believe the claims are without merit and intend to vigorously defend themselves against the allegations made in this complaint, but, at this time, are unable to predict the outcome of the above matter or estimate the possible loss or range of loss.

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 FirstEnergy's 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 ofSeptember 30, 2013based 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$124 millionhave been accrued throughSeptember 30, 2013. Included in the total are accrued liabilities of approximately$82 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 ofSeptember 30, 2013, FirstEnergy had approximately$2.2 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 guaranty, 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.FE maintains a$125 millionparental guaranty relating to a potential shortfall in nuclear decommissioning funding for Beaver Valley Unit 1 and Perry.FE also maintains an$11 millionparental guaranty in support of the decommissioning of the spent fuel storage facilities located at its Davis-Besse and Perry nuclear facilities.

On October 4, 2013, during a refueling outage for Beaver Valley Unit 1, FENOC conducted a planned visual examination of the interior containment liner and coatings. The containment design for Beaver Valley includes an interior steel liner that is surrounded by reinforced concrete. A penetration through the containment steel liner plate of approximately 0.4 inches by 0.28 inches was discovered. A detailed investigation was initiated, including laboratory analysis that has indicated that the degraded area was initiated by foreign material inadvertently left in the concrete during construction. An assessment has been performed which concluded that any postulated leakage through the affected area was within overall allowable limits for the containment building. The structural integrity of the containment building is not affected. Repair of the containment liner has been completed and is not expected to impact the restart of the Unit.

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.An NRC ASLB granted a hearing on the Davis-Besse license renewal application to a group of petitioners.On July 9, 2012, the petitioners' proposed a contention on the environmental impacts of spent fuel storage in the Davis-Besse license renewal proceeding.In an order dated August 7, 2012, the NRC stated that it will not issue final licensing decisions until it has appropriately addressed the challenges to the NRC Waste Confidence Decision and Temporary Storage Rule and all pending contentions on this topic should be held in abeyance.The ASLB has suspended further consideration of the petitioners' proposed contention on the environmental impacts of spent fuel storage at Davis-Besse.The NRC Staff issued Waste Confidence Draft Generic Environmental Impact Statement and published a proposed rule on this subject in September of 2013.

In May 2013, four petitioners requested a hearing on an NRC LAR submitted by FENOC to amend the Technical Specifications for the Davis-Besse plant to support plant operations following replacement of the steam generators, which is scheduled to be completed in April 2014.The petitioners also challenged FENOC's ability to replace the steam generators at the Davis-Besse plant under the NRC regulations, 10 CFR §50.59 without submitting a formal LAR.By an order dated August 12, 2013, the NRC denied the request for a hearing.

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station FENOC identified changes to the laminar cracking condition discovered in 2011. FENOC expanded its sample size to include all of the existing core bores in the shield building. These inspections are now complete. FENOC identified additional subsurface cracking that determined to be pre-existing, but not previously identified, due to improved inspection technology. In addition, these inspections revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirm that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

By a 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 conducted several supplemental inspections, including inspections using Inspection Procedure 95002 to determine if the root cause and contributing causes of risk significant performance issues were understood, the extent of condition was identified, whether safety culture contributed to the performance issues, and if FENOC's corrective actions are sufficient to address the causes and prevent recurrence.On August 12, 2013, the NRC issued an inspection report for the final 95002 Supplemental Inspection for Perry and returned Perry to the Licensee Response Column (Column 1) of the NRC's ROP Action Matrix.

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.

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 millionfor 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, the defendants posted bond and filed a Notice of Appeal with the Superior Court.On August 13, 2012, the Superior Court affirmed the$14 millionpast damages award but vacated the$90 millionfuture damages award.While the Superior Court found that the defendants still owed future damages, it remanded the calculation of those damages back to the trial court.The specific amount of those future damages is not known at this time, but they are expected to be calculated at a market price of coal that is significantly lower than the price used by the trial court.On August 27, 2012, AE Supply and MP filed an Application for Reargument En Banc with the Superior Court, which was denied on October 19, 2012.AE Supply and MP filed a Petition for Allowance of Appeal with the Pennsylvania Supreme Court on November 19, 2012.On July 2, 2013, the Petition for Allowance of Appeal was denied and in the second quarter of 2013 the now final past damage award of$15.5 million(including interest) was recognized.The case was sent back to the trial court to recalculate the future damages only and is currently in the discovery phase.

Other Legal Matters

In 2010, a lawsuit was filed in Allegheny County Court of Common Pleas by Michael Goretzka, for wrongful death and negligence after his wife was fatally electrocuted when she contacted a downed power line.The trial resulted in a verdict against WP and the parties settled this matter.WP's portion of the settlement was covered by insurance subject to the remainder of its deductible.On May 30, 2012, the PPUC's Bureau of Investigation and Enforcement (I&E) filed a Formal Complaint at the PPUC regarding this matter.On February 13, 2013, WP and I&E filed a Joint Petition for Full Settlement that includes, among other things, WP's agreement to conduct an infrared inspection of its primary distribution system, modify certain training programs, and pay an$86,000civil penalty, which settlement is subject to PPUC approval.On August 29, 2013, the PPUC entered an Order granting the Goretzka family limited party status for the sole purpose of submitting comments to the settlement and issuing the settlement for comment by the parties.On September 16, 2013, the Goretzka family filed Limited Objections to the settlement. Reply comments were filed by WP on September 30, 2013.

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 12, Regulatory Matters of the Combined Notes to 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 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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Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
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 (in dollars)	$ 41	$ 40
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 4

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Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
REVENUES:
Electric sales	$ 1,506		$ 1,382		$ 4,131		$ 4,247
Total revenues	4,036	[1]	4,052	[1]	11,270	[1]	11,780	[1]
OPERATING EXPENSES:
Fuel	657		636		1,915		1,833
Purchased power	1,120		1,063		2,932		3,367
Other operating expenses	877		861		2,645		2,597
Provision for depreciation	316		272		909		834
General taxes	242		257		747		760
Total operating expenses	3,524		3,150		10,064		9,589
OPERATING INCOME (LOSS)	512		902		1,206		2,191
OTHER INCOME (EXPENSE):
Loss on debt redemptions	9		0		(132)		0
Investment income (loss)	5		39		8		63
Interest expense	(257)		(230)		(771)		(750)
Capitalized interest	17		18		51		54
Total other income (expense)	(226)		(173)		(844)		(633)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	286		729		362		1,558
INCOME TAXES (BENEFITS)	77		307		129		650
NET INCOME FROM CONTINUING OPERATIONS	209		422		233		908
Discontinued operations (net of income taxes of $5, $3, $8 and $6, respectively) (Note 16)	9		3		17		11
NET INCOME (LOSS)	218		425		250		919
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	218		425		250		919
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(47)		(47)		(148)		(148)
Amortized loss (gain) on derivative hedges	2		0		4		1
Change in unrealized gain on available-for-sale securities	6		1		3		13
Other comprehensive income (loss)	(39)		(46)		(141)		(134)
Income taxes (benefits) on other comprehensive income (loss)	(15)		(24)		(55)		(75)
Net other comprehensive income (loss)	(24)		(22)		(86)		(59)
COMPREHENSIVE INCOME (LOSS)	194		403		164		860
FES
REVENUES:
Other	38		37		107		91
Total revenues	1,679		1,550		4,655		4,511
OPERATING EXPENSES:
Fuel	304		303		936		978
Other operating expenses	339		342		1,105		1,028
Provision for depreciation	80		70		231		200
General taxes	35		35		106		104
Total operating expenses	1,614		1,383		4,534		4,116
OPERATING INCOME (LOSS)	65		167		121		395
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		0		(103)		0
Investment income (loss)	(3)		38		(4)		50
Miscellaneous income	21		1		29		25
Capitalized interest	9		9		28		27
Total other income (expense)	(9)		(6)		(183)		(45)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	56		161		(62)		350
INCOME TAXES (BENEFITS)	23		65		(19)		139
NET INCOME FROM CONTINUING OPERATIONS	33		96		(43)		211
Discontinued operations (net of income taxes of $5, $3, $8 and $6, respectively) (Note 16)	7		5		14		11
NET INCOME (LOSS)	40		101		(29)		222
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	40		101		(29)		222
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5)		(5)		(16)		(2)
Amortized loss (gain) on derivative hedges	(1)		(2)		(3)		(6)
Change in unrealized gain on available-for-sale securities	5		(2)		2		11
Other comprehensive income (loss)	(1)		(9)		(17)		3
Income taxes (benefits) on other comprehensive income (loss)	(1)		(3)		(7)		1
Net other comprehensive income (loss)	0		(6)		(10)		2
COMPREHENSIVE INCOME (LOSS)	40		95		(39)		224
FES | Affiliates
REVENUES:
Electric sales	186		155		482		385
OPERATING EXPENSES:
Purchased power	132		131		401		381
OTHER INCOME (EXPENSE):
Interest expense	(1)		(3)		(7)		(7)
FES | Non-Affiliates
REVENUES:
Electric sales	1,455		1,358		4,066		4,035
OPERATING EXPENSES:
Purchased power	724		502		1,755		1,425
OTHER INCOME (EXPENSE):
Interest expense	$ (35)		$ (51)		$ (126)		$ (140)

[1] Includes excise tax collections of $117 million and $123 million in the three months ended September 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended September 30, 2013 and 2012, respectively.

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Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
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 (in dollars)	$ 41	$ 40
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	3	4
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 (in dollars)	14	16
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 2

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Supplemental Guarantor Information (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended										3 Months Ended	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Sep. 30, 2013 FGCO	Sep. 30, 2012 FGCO	Sep. 30, 2013 Nuclear Generation Corp	Sep. 30, 2012 Nuclear Generation Corp	Sep. 30, 2013 Eliminations	Sep. 30, 2012 Eliminations	Jun. 30, 2013 FES	Sep. 30, 2013 FES	Sep. 30, 2012 FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities			$ 1,671	$ 1,276	$ (1,018)	$ (971)	$ 712	$ 683	$ 705	$ 799	$ (10)	$ (10)		$ 389	$ 501
New Financing-
Long-term debt			2,745	660		0		317		243		0		0	560
Short-term borrowings, net			1,435	1,604	338	982	0	49	0	0	(338)	(1,028)		0	3
Equity contribution from parent					1,500		0		0		0		1,500	1,500	0
Redemptions and Repayments-
Long-term debt			(2,662)	(870)	(769)	0	(352)	(169)	(68)	(87)	10	10		(1,179)	(246)
Short-term borrowings, net					0	0	(32)	0	0	(32)	32	32		0	0
Tender premiums			(110)	0	(67)		0		0		0			(67)	0
Other			(64)	(42)	(3)	(1)	(4)	(6)		(2)		0		(7)	(9)
Net cash provided from (used for) financing activities			654	662	999	981	(388)	191	(68)	122	(296)	(986)		247	308
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(548)	(775)	(1,960)	(1,686)	(9)	(10)	(192)	(175)	(276)	(350)	0	0		(477)	(535)
Nuclear fuel			(159)	(207)	0	0	0	0	(159)	(207)	0	0		(159)	(207)
Proceeds from asset sales					0	0	21	17	0	0	0	0		21	17
Sales of investment securities held in trusts			1,545	2,133	0	0	0	0	650	1,167	0	0		650	1,167
Purchases of investment securities held in trusts			(1,567)	(2,188)	0	0	0	0	(694)	(1,194)	0	0		(694)	(1,194)
Loans to affiliated companies, net					28	1	(156)	(715)	(156)	(337)	306	996		22	(55)
Other			3	(23)	0	(1)	2	(5)	(2)	0	0	0		0	(6)
Net cash used for investing activities			(2,275)	(1,990)	19	(10)	(325)	(878)	(637)	(921)	306	996		(637)	(813)
Net change in cash and cash equivalents			50	(52)	0	0	(1)	(4)	0	0	0	0		(1)	(4)
Cash and cash equivalents at beginning of period			172	202	0	0	3	7	0	0	0	0		3	7
Cash and cash equivalents at end of period	$ 222	$ 150	$ 222	$ 150	$ 0	$ 0	$ 2	$ 3	$ 0	$ 0	$ 0	$ 0		$ 2	$ 3

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Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Tax effect of discontinued operations	$ 3	$ 2	$ 9	$ 8
FES
Tax effect of discontinued operations	$ 5	$ 3	$ 8	$ 6

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Segment Information (Tables)

9 Months Ended

Sep. 30, 2013

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)
September 30, 2013
External revenues	$	2,340	$	190	$	1,573		$	(31	)	$	(36	)	$	4,036
Internal revenues	—		—		196			—			(196		)	—
Total revenues	2,340		190		1,769			(31		)	(232		)	4,036
Depreciation, amortization and deferrals	460		31		125			12			—			628
Investment income (loss)	14		—		(5		)	3			(7		)	5
Interest expense	134		23		53			47			—			257
Income taxes (benefits)	50		32		47			(44		)	(8		)	77
Income from continuing operations	85		54		68			—			2			209
Discontinued operations, net of tax	—		—		9			—			—			9
Net income (loss)	85		54		77			(10		)	12			218
Total assets	27,030		4,953		17,809			591			—			50,383
Total goodwill	5,025		526		867			—			—			6,418
Property additions	261		105		162			20			—			548
September 30, 2012
External revenues	$	2,483	$	187	$	1,462		$	(31	)	$	(49	)	$	4,052
Internal revenues	—		—		209			—			(209		)	—
Total revenues	2,483		187		1,671			(31		)	(258		)	4,052
Depreciation, amortization and deferrals	193		28		102			9			1			333
Investment income	20		—		36			(2		)	(15		)	39
Interest expense	136		24		73			(3		)	—			230
Income taxes (benefits)	168		35		74			(8		)	38			307
Income from continuing operations	286		59		126			—			(49		)	422
Discontinued operations, net of tax	—		—		3			—			—			3
Net income (loss)	286		59		129			(13		)	(36		)	425
Total assets	26,122		4,519		16,846			1,251			—			48,738
Total goodwill	5,025		526		893			—			—			6,444
Property additions	308		47		412			8			—			775
Nine Months Ended
September 30, 2013
External revenues	$	6,593	$	546	$	4,350		$	(89	)	$	(130	)	$	11,270
Internal revenues	—		—		588			—			(588		)	—
Total revenues	6,593		546		4,938			(89		)	(718		)	11,270
Depreciation, amortization and deferrals	882		91		347			32			—			1,352
Investment income (loss)	41		—		(6		)	6			(33		)	8
Interest expense	404		68		187			112			—			771
Income taxes (benefits)	284		93		(189		)	(55		)	(4		)	129
Income (loss) from continuing operations	474		156		(317		)	—			(80		)	233
Discontinued operations, net of tax	—		—		17			—			—			17
Net income (loss)	474		156		(300		)	(92		)	12			250
Total assets	27,030		4,953		17,809			591			—			50,383
Total goodwill	5,025		526		867			—			—			6,418
Property additions	980		291		630			59			—			1,960
September 30, 2012
External revenues	$	6,976	$	557	$	4,465		$	(78	)	$	(142	)	$	11,778
Internal revenues	—		—		686			—			(684		)	2
Total revenues	6,976		557		5,151			(78		)	(826		)	11,780
Depreciation, amortization and deferrals	618		86		303			25			—			1,032
Investment income	62		1		48			(1		)	(47		)	63
Interest expense	405		70		209			66			—			750
Income taxes	355		101		165			(49		)	78			650
Income from continuing operations	603		171		284			—			(150		)	908
Discontinued operations, net of tax	—		—		11			—			—			11
Net income (loss)	603		171		295			(82		)	(68		)	919
Total assets	26,122		4,519		16,846			1,251			—			48,738
Total goodwill	5,025		526		893			—			—			6,444
Property additions	751		169		715			51			—			1,686

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Discontinued Operations and Assets Held for Sale

9 Months Ended

Sep. 30, 2013

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations and Assets Held for Sale

DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

On September 4, 2013, certain of FirstEnergy subsidiaries applied for authorization from the FERC to sell eleven hydroelectric power stations in Pennsylvania, Virginia and West Virginia to subsidiaries of Harbor Hydro, a subsidiary of LS Power, for approximately $400 million. The asset purchase agreement was entered into on August 23, 2013, as amended and restated as of September 4, 2013. The proposed transaction is expected to close in the fourth quarter of 2013. The asset purchase agreement is subject to customary and other closing conditions, including, without limitation, the resolution of a potential competing license application, and receipt of approvals by FERC and the VSCC, which is pending. On September 27, 2013, the Federal Trade Commission advised that the Hart-Scott-Rodino waiting period was terminated, meaning this item is complete. As of September 30, 2013, FirstEnergy classified the hydroelectric power stations, with a carrying value of $234 million (FES - $121 million) as Assets held for sale in the Consolidated Balance Sheets. Included in the carrying value of the assets held for sale is goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold. Net pre-tax results for the hydroelectric facilities of $12 million and $26 million (FES - $12 million and $22 million) for the three and nine months ended September 30, 2013, respectively, and $5 million and $19 million (FES - $8 million and $17 million) for three and nine months ended September 30, 2012, respectively, were reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Revenues for the hydroelectric facilities of $11 million and $24 million (FES - $10 million and $22 million) for the three and nine months ended September 30, 2013, respectively, and $6 million and $24 million (FES - $8 million and $18 million) for the three and nine months ended September 30, 2012 respectively, are reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations.

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Earnings Per Share of Common Stock (Tables)

9 Months Ended

Sep. 30, 2013

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 September 30				Nine Months Ended September 30
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2013		2012		2013		2012
	(In millions, except per share amounts)
Net income from continuing operations	$	209	$	422	$	233	$	908
Less: Income attributable to noncontrolling interest	—		—		—		1
Income from continuing operations available to common shareholders	209		422		233		907
Discontinued operations (Note 16)	9		3		17		11
Earnings available to FirstEnergy Corp.	$	218	$	425	$	250	$	918
Weighted average number of basic shares outstanding	418		417		418		418
Assumed exercise of dilutive stock options and awards(1)	1		2		1		1
Weighted average number of diluted shares outstanding	419		419		419		419
Earnings per share:
Basic earnings per share:
Net income from continuing operations	$	0.50	$	1.01	$	0.56	$	2.17
Discontinued operations (Note 16)	0.02		0.01		0.04		0.03
Net earnings per basic share	$	0.52	$	1.02	$	0.60	$	2.20
Diluted earnings per share:
Net income from continuing operations	$	0.50	$	1.00	$	0.56	$	2.16
Discontinued operations (Note 16)	0.02		0.01		0.04		0.03
Net earnings per diluted share	$	0.52	$	1.01	$	0.60	$	2.19

⁽¹⁾  For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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Supplemental Guarantor Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Consolidating Statements of Income
Revenues	$ 2,530	$ 2,670	$ 7,139	$ 7,533
OPERATING EXPENSES:
Fuel	657	636	1,915	1,833
Purchased power	1,120	1,063	2,932	3,367
Other operating expenses	877	861	2,645	2,597
Provision for depreciation	316	272	909	834
General taxes	242	257	747	760
Total operating expenses	3,524	3,150	10,064	9,589
OPERATING INCOME (LOSS)	512	902	1,206	2,191
OTHER INCOME (EXPENSE):
Loss on debt redemptions	9	0	(132)	0
Investment income	5	39	8	63
Interest expense	(257)	(230)	(771)	(750)
Capitalized interest	17	18	51	54
Total other income (expense)	(226)	(173)	(844)	(633)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	286	729	362	1,558
INCOME TAXES (BENEFITS)	77	307	129	650
NET INCOME FROM CONTINUING OPERATIONS	209	422	233	908
Discontinued operations (Note 16)	9	3	17	11
NET INCOME (LOSS)	218	425	250	919
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	218	425	250	919
Pension and OPEB prior service costs	(47)	(47)	(148)	(148)
Amortized loss (gain) on derivative hedges	2	0	4	1
Change in unrealized gain on available-for-sale securities	6	1	3	13
Other comprehensive income (loss)	(39)	(46)	(141)	(134)
Income taxes (benefits) on other comprehensive income (loss)	(15)	(24)	(55)	(75)
Net other comprehensive income (loss)	(24)	(22)	(86)	(59)
COMPREHENSIVE INCOME (LOSS)	194	403	164	860
FES
Consolidating Statements of Income
Revenues	1,654	1,523	4,575	4,443
OPERATING EXPENSES:
Fuel	0	0	0	0
Other operating expenses	147	130	484	313
Provision for depreciation	1	1	4	3
General taxes	21	20	60	60
Total operating expenses	1,898	1,692	5,369	4,959
OPERATING INCOME (LOSS)	(244)	(169)	(794)	(516)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		(103)
Investment income	2	1	4	2
Miscellaneous income, including net income from equity investees	180	317	543	854
Capitalized interest	0	0	1	0
Total other income (expense)	166	288	385	770
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(78)	119	(409)	254
INCOME TAXES (BENEFITS)	(118)	18	(380)	32
NET INCOME FROM CONTINUING OPERATIONS	40	101	(29)	222
Discontinued operations (Note 16)	0	0	0	0
NET INCOME (LOSS)	40	101	(29)	222
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	40	101	(29)	222
Pension and OPEB prior service costs	(5)	(5)	(16)	(2)
Amortized loss (gain) on derivative hedges	(1)	(2)	(3)	(6)
Change in unrealized gain on available-for-sale securities	5	(2)	2	11
Other comprehensive income (loss)	(1)	(9)	(17)	3
Income taxes (benefits) on other comprehensive income (loss)	(1)	(3)	(7)	1
Net other comprehensive income (loss)	0	(6)	(10)	2
COMPREHENSIVE INCOME (LOSS)	40	95	(39)	224
FES | Affiliates
OPERATING EXPENSES:
Purchased power	1,009	1,042	3,072	3,163
OTHER INCOME (EXPENSE):
Interest expense	(3)	(5)	(10)	(14)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	720	499	1,749	1,420
OTHER INCOME (EXPENSE):
Interest expense	(13)	(25)	(50)	(72)
FGCO
Consolidating Statements of Income
Revenues	528	610	1,612	1,777
OPERATING EXPENSES:
Fuel	249	248	782	824
Other operating expenses	65	78	208	268
Provision for depreciation	33	29	96	87
General taxes	9	10	28	28
Total operating expenses	360	368	1,120	1,212
OPERATING INCOME (LOSS)	168	242	492	565
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		0
Investment income	0	5	0	14
Miscellaneous income, including net income from equity investees	19	0	23	19
Capitalized interest	1	1	1	3
Total other income (expense)	(6)	(23)	(59)	(48)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	162	219	433	517
INCOME TAXES (BENEFITS)	111	(14)	215	(25)
NET INCOME FROM CONTINUING OPERATIONS	51	233	218	542
Discontinued operations (Note 16)	7	5	14	11
NET INCOME (LOSS)	58	238	232	553
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	58	238	232	553
Pension and OPEB prior service costs	(5)	(4)	(15)	(1)
Amortized loss (gain) on derivative hedges	0	0	0	0
Change in unrealized gain on available-for-sale securities	0	0	0	0
Other comprehensive income (loss)	(5)	(4)	(15)	(1)
Income taxes (benefits) on other comprehensive income (loss)	(2)	(2)	(6)	(1)
Net other comprehensive income (loss)	(3)	(2)	(9)	0
COMPREHENSIVE INCOME (LOSS)	55	236	223	553
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power	0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	(2)	(2)	(4)	(5)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power	4	3	6	5
OTHER INCOME (EXPENSE):
Interest expense	(24)	(27)	(79)	(79)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues	440	395	1,337	1,262
OPERATING EXPENSES:
Fuel	55	55	154	154
Other operating expenses	114	122	376	410
Provision for depreciation	46	41	134	114
General taxes	5	5	18	16
Total operating expenses	285	290	879	883
OPERATING INCOME (LOSS)	155	105	458	379
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		0
Investment income	(1)	37	3	49
Miscellaneous income, including net income from equity investees	0	0	0	0
Capitalized interest	8	8	26	24
Total other income (expense)	(7)	29	(18)	34
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	148	134	440	413
INCOME TAXES (BENEFITS)	28	59	138	124
NET INCOME FROM CONTINUING OPERATIONS	120	75	302	289
Discontinued operations (Note 16)	0	0	0	0
NET INCOME (LOSS)	120	75	302	289
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	120	75	302	289
Pension and OPEB prior service costs	0	0	0	0
Amortized loss (gain) on derivative hedges	0	0	0	0
Change in unrealized gain on available-for-sale securities	5	(1)	2	12
Other comprehensive income (loss)	5	(1)	2	12
Income taxes (benefits) on other comprehensive income (loss)	3	0	1	5
Net other comprehensive income (loss)	2	(1)	1	7
COMPREHENSIVE INCOME (LOSS)	122	74	303	296
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power	65	67	197	189
OTHER INCOME (EXPENSE):
Interest expense	(1)	(1)	(5)	(3)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	(13)	(15)	(42)	(36)
Eliminations
Consolidating Statements of Income
Revenues	(943)	(978)	(2,869)	(2,971)
OPERATING EXPENSES:
Fuel	0	0	0	0
Other operating expenses	13	12	37	37
Provision for depreciation	0	(1)	(3)	(4)
General taxes	0	0	0	0
Total operating expenses	(929)	(967)	(2,834)	(2,938)
OPERATING INCOME (LOSS)	(14)	(11)	(35)	(33)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0		0
Investment income	(4)	(5)	(11)	(15)
Miscellaneous income, including net income from equity investees	(178)	(316)	(537)	(848)
Capitalized interest	0	0	0	0
Total other income (expense)	(162)	(300)	(491)	(801)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(176)	(311)	(526)	(834)
INCOME TAXES (BENEFITS)	2	2	8	8
NET INCOME FROM CONTINUING OPERATIONS	(178)	(313)	(534)	(842)
Discontinued operations (Note 16)	0	0	0	0
NET INCOME (LOSS)	(178)	(313)	(534)	(842)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	(178)	(313)	(534)	(842)
Pension and OPEB prior service costs	5	4	15	1
Amortized loss (gain) on derivative hedges	0	0	0	0
Change in unrealized gain on available-for-sale securities	(5)	1	(2)	(12)
Other comprehensive income (loss)	0	5	13	(11)
Income taxes (benefits) on other comprehensive income (loss)	(1)	2	5	(4)
Net other comprehensive income (loss)	1	3	8	(7)
COMPREHENSIVE INCOME (LOSS)	(177)	(310)	(526)	(849)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power	(942)	(978)	(2,868)	(2,971)
OTHER INCOME (EXPENSE):
Interest expense	5	5	12	15
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	0	0	0
OTHER INCOME (EXPENSE):
Interest expense	15	16	45	47
FES
Consolidating Statements of Income
Revenues	1,679	1,550	4,655	4,511
OPERATING EXPENSES:
Fuel	304	303	936	978
Other operating expenses	339	342	1,105	1,028
Provision for depreciation	80	70	231	200
General taxes	35	35	106	104
Total operating expenses	1,614	1,383	4,534	4,116
OPERATING INCOME (LOSS)	65	167	121	395
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0	0	(103)	0
Investment income	(3)	38	(4)	50
Miscellaneous income, including net income from equity investees	21	1	29	25
Capitalized interest	9	9	28	27
Total other income (expense)	(9)	(6)	(183)	(45)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	56	161	(62)	350
INCOME TAXES (BENEFITS)	23	65	(19)	139
NET INCOME FROM CONTINUING OPERATIONS	33	96	(43)	211
Discontinued operations (Note 16)	7	5	14	11
NET INCOME (LOSS)	40	101	(29)	222
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	40	101	(29)	222
Pension and OPEB prior service costs	(5)	(5)	(16)	(2)
Amortized loss (gain) on derivative hedges	(1)	(2)	(3)	(6)
Change in unrealized gain on available-for-sale securities	5	(2)	2	11
Other comprehensive income (loss)	(1)	(9)	(17)	3
Income taxes (benefits) on other comprehensive income (loss)	(1)	(3)	(7)	1
Net other comprehensive income (loss)	0	(6)	(10)	2
COMPREHENSIVE INCOME (LOSS)	40	95	(39)	224
FES | Affiliates
OPERATING EXPENSES:
Purchased power	132	131	401	381
OTHER INCOME (EXPENSE):
Interest expense	(1)	(3)	(7)	(7)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	724	502	1,755	1,425
OTHER INCOME (EXPENSE):
Interest expense	$ (35)	$ (51)	$ (126)	$ (140)

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Fair value of derivatives instruments

The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:

Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	September 30, 2013		December 31, 2012			September 30, 2013			December 31, 2012
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	137	$	153	Commodity Contracts	$	(94	)	$	(119	)
FTRs	3		7		FTRs	(11		)	(7		)
	140		160			(105		)	(126		)
					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs	(233		)	(290		)
Deferred Charges and Other Assets - Other					LCAAP	(166		)	(144		)
Commodity Contracts	64		99		Noncurrent Liabilities - Other
FTRs	—		1		Commodity Contracts	(18		)	(36		)
NUGs	23		36		FTRs	(3		)	(2		)
	87		136			(420		)	(472		)
Derivative Assets	$	227	$	296	Derivative Liabilities	$	(525	)	$	(598	)

Offsetting assets and liabilities

The following tables summarize the fair value of derivative instruments on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position:

				Amounts Not Offset in Consolidated Balance Sheet
September 30, 2013	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	201		$	(104	)	$	(11	)	$	86
FTRs	3			(3		)	—			—
NUG contracts	23			—			—			23
	$	227		$	(107	)	$	(11	)	$	109
Derivative Liabilities
Commodity contracts	$	(112	)	$	104		$	5		$	(3	)
FTRs	(14		)	3			6			(5		)
NUG contracts	(233		)	—			—			(233		)
LCAPP contracts	(166		)	—			—			(166		)
	$	(525	)	$	107		$	11		$	(407	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2012	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	252		$	(142	)	$	(5	)	$	105
FTRs	8			(8		)	—			—
NUG contracts	36			—			—			36
	$	296		$	(150	)	$	(5	)	$	141
Derivative Liabilities
Commodity contracts	$	(155	)	$	142		$	12		$	(1	)
FTRs	(9		)	8			1			—
NUG contracts	(290		)	—			—			(290		)
LCAPP contracts	(144		)	—			—			(144		)
	$	(598	)	$	150		$	13		$	(435	)

Volume of First Energy's outstanding derivative transactions

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2013:

	Purchases	Sales	Net		Units
	(In millions, except for LCAPP)
Power Contracts	32	37	(5	)	MWH
FTRs	59	—	59		MWH
NUGs	11	—	11		MWH
LCAPP	408	—	408		MW
Natural Gas	64	—	64		mmBTU

Effect of derivative instruments on statements of income and comprehensive income

The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months and nine months ended September 30, 2013 and 2012, are summarized in the following tables:

	Three Months Ended September 30
	Commodity Contracts			FTRs			Interest Rate Swaps		Total
	(In millions)
2013
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	11		$	(8	)	$	—	$	3
Realized Gain (Loss) Reclassified to:
Revenues	$	14		$	6		$	—	$	20
Purchased Power Expense	(17		)	—			—		(17		)
Other Operating Expense	—			(10		)	—		(10		)
Fuel Expense	(2		)	—			—		(2		)
2012
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	7		$	(5	)	$	—	$	2
Interest Expense	—			—			20		20
Realized Gain (Loss) Reclassified to:
Revenues	$	46		$	6		$	—	$	52
Purchased Power Expense	(27		)	—			—		(27		)
Other Operating Expense	—			(10		)	—		(10		)
Fuel Expense	3			—			—		3
Interest Expense	—			—			6		6

	Nine Months Ended September 30
	Commodity Contracts			FTRs			Interest Rate Swaps		Total
	(In millions)
2013
Unrealized Loss Recognized in:
Other Operating Expense	$	(5	)	$	(10	)	$	—	$	(15	)
Realized Gain (Loss) Reclassified to:
Revenues	$	29		$	19		$	—	$	48
Purchased Power Expense	(30		)	—			—		(30		)
Other Operating Expense	—			(28		)	—		(28		)
2012
Unrealized Gain Recognized in:
Other Operating Expense	$	72		$	12		$	—	$	84
Realized Gain (Loss) Reclassified to:
Revenues	$	260		$	18		$	—	$	278
Purchased Power Expense	(248		)	—			—		(248		)
Other Operating Expense	—			(51		)	—		(51		)
Fuel Expense	2			—			—		2
Interest Expense	—			—			6		6

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 nine months ended September 30, 2013 and 2012, are summarized in the following tables:

	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	7		$	(8	)	$	1		$	—
Realized Gain (Loss) on Derivative Instrument	14			—			(1		)	13
2012
Unrealized Gain (Loss) on Derivative Instrument	$	(50	)	$	3		$	—		$	(47	)
Realized Gain (Loss) on Derivative Instrument	61			—			(1		)	60

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	(13	)	$	(22	)	$	1		$	(34	)
Realized Gain (Loss) on Derivative Instrument	57			—			(1		)	56
2012
Unrealized Loss on Derivative Instrument	$	(183	)	$	(142	)	$	—		$	(325	)
Realized Gain on Derivative Instrument	194			—			7			201

Reconciliation of changes in the fair value of certain contracts that are deferred

The following tables provide 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 nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of July 1, 2013	$	(231	)	$	(158	)	$	—		$	(389	)
Additions/Change in value of existing contracts	7			(8		)	1			—
Settled contracts	14			—			(1		)	13
Outstanding net liability as of September 30, 2013	$	(210	)	$	(166	)	$	—		$	(376	)
Outstanding net liability as of July 1, 2012	$	(293	)	$	(145	)	$	—		$	(438	)
Additions/Change in value of existing contracts	(50		)	3			—			(47		)
Settled contracts	61			—			(1		)	60
Outstanding net liability as of September 30, 2012	$	(282	)	$	(142	)	$	(1	)	$	(425	)

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of January 1, 2013	$	(254	)	$	(144	)	$	—		$	(398	)
Additions/Change in value of existing contracts	(13		)	(22		)	1			(34		)
Settled contracts	57			—			(1		)	56
Outstanding net liability as of September 30, 2013	$	(210	)	$	(166	)	$	—		$	(376	)
Outstanding net liability as of January 1, 2012	$	(293	)	$	—		$	(8	)	$	(301	)
Additions/Change in value of existing contracts	(183		)	(142		)	—			(325		)
Settled contracts	194			—			7			201
Outstanding net liability as of September 30, 2012	$	(282	)	$	(142	)	$	(1	)	$	(425	)

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Commitments, Guarantees and Contingencies (Details Textuals) (USD $)	3 Months Ended	9 Months Ended			3 Months Ended	9 Months Ended		0 Months Ended	9 Months Ended	0 Months Ended		1 Months Ended	9 Months Ended						9 Months Ended			9 Months Ended				9 Months Ended				9 Months Ended	3 Months Ended			3 Months Ended	9 Months Ended			9 Months Ended			9 Months Ended					0 Months Ended				3 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	Jun. 30, 2013 ICG Litigation	Sep. 30, 2013 Clean Water Act	Apr. 30, 2009 Clean Water Act aspect_of_opinion	Mar. 28, 2013 Regulation of Waste Disposal	Sep. 30, 2013 Regulation of Waste Disposal options	Oct. 10, 2013 Regulation of Waste Disposal Subsequent Event IndividualsInAComplaint	Oct. 03, 2013 Regulation of Waste Disposal Subsequent Event deficiency	May 31, 2013 Nuclear Plant Matters petitioners	Sep. 30, 2013 Nuclear Plant Matters	Sep. 30, 2013 Caa Compliance CoalFiredPlants ElectricGenerationUnits	Sep. 30, 2013 National Ambient Air Quality Standards T	Sep. 30, 2013 National Ambient Air Quality Standards CAIR phases	Sep. 30, 2013 National Ambient Air Quality Standards CSAPR phases	Sep. 30, 2013 Hazardous Air Pollutant Emissions	Sep. 30, 2013 Climate Change celsius	Apr. 13, 2012 Climate Change lb	Jan. 02, 2011 Climate Change T	Sep. 30, 2013 Climate Change Year 2020 Increase in funding	Sep. 30, 2013 Senior Secured Term Loan Senior Loans	Dec. 31, 2012 Senior Secured Term Loan Senior Loans	Sep. 30, 2013 Regulated Distribution	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Dec. 31, 2012 FES	Sep. 30, 2013 AE Supply	Sep. 30, 2013 AE Supply ICG Litigation	Sep. 30, 2013 Global Holding	Sep. 30, 2013 Global Holding Senior Secured Term Loan Senior Loans	Sep. 30, 2013 Global Holding Senior Secured Term Loan Senior Loans Signal Peak, Global Rail and Affiliates	Sep. 30, 2013 Signal Peak and Global Rail	Sep. 30, 2013 Signal Peak and Global Rail Senior Secured Term Loan Senior Loans	Sep. 30, 2013 FEV Senior Secured Term Loan Senior Loans Signal Peak Global Holding	Sep. 30, 2013 WMB Marketing Ventures, LLC Senior Secured Term Loan Senior Loans Signal Peak Global Holding	Sep. 30, 2013 FGCO	Sep. 30, 2012 FGCO	Dec. 31, 2012 FGCO	Sep. 30, 2013 FGCO Caa Compliance Complaints	Sep. 30, 2013 FGCO Caa Compliance Claim One IndividualsInAComplaint Complaints	Sep. 30, 2013 FGCO Caa Compliance Claim Two plaintiff	Aug. 13, 2012 AE Supply and MP ICG Litigation	May 02, 2011 AE Supply and MP ICG Litigation	Feb. 13, 2012 Wp	Sep. 30, 2013 Parental Guarantees	Sep. 30, 2013 Subsidiaries' Guarantees	Sep. 30, 2013 Other Guarantees	Sep. 30, 2013 State and Local Agencies Hazardous Air Pollutant Emissions	Sep. 30, 2013 Environmental Protection Agency Hazardous Air Pollutant Emissions	Apr. 13, 2012 Minimum Climate Change	Apr. 13, 2012 Maximum Climate Change	Sep. 30, 2013 Transportation Commitment [Member] Hazardous Air Pollutant Emissions	Dec. 31, 2012 Transportation Commitment [Member] Hazardous Air Pollutant Emissions
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	$ 4,400,000,000	$ 4,400,000,000																																													$ 1,403,000,000	$ 2,232,000,000	$ 747,000,000
Company posted collateral related to net liability positions																									16,000,000	150,000,000			8,000,000
Potential collateral posted related to net liability positions																										77,000,000			2,000,000
Senior secured term loan facility, term																															3 years			2 years
New syndicated senior secured term loan facility																																350,000,000
Repayments of senior secured term loan facility		2,662,000,000	870,000,000																							1,179,000,000	246,000,000								350,000,000			352,000,000	169,000,000
Investment ownership percentage																																	69.99%			33.33%	33.33%
Guarantor obligations, guarantee fee receivable, percentage, remainder of fiscal year																								4.00%
Guarantor obligations, guarantee fee receivable, percentage, next twelve months																							5.00%
Number of complaints filed against FGCO																																									3
Number of complaints seek enjoin plant																																									2	1
Number of individuals behalf of which complaint filed										50																																21
Number of named plaintiffs as class representatives																																											8
Reduction in air emissions and compliance																																																				25.00%	40.00%
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
Potential cost of compliance, MATS									234,000,000									465,000,000
Loss Contingency, Settlement Agreement, Consideration																																																							45,000,000
Loss Contingency, Range of Possible Loss, Maximum																																																						25,000,000
Pre-tax severance expense related to closures	2,000,000		14,000,000																								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
Commitment Period by Developed Countries to Provide Funds, Years																			3 years
Commitment, Proposed Emissions Standard																				1,000
Aspects of opinion reversed							1
Annual percentage that fish impingement should be reduced to, per CWA						12.00%
Maximum capital investment required to install technology to meet TDS and Sulfate limits						150,000,000
TMDL Limit Development Period						5 years
Number of Deficiencies Identified in Plan											4
Options proposed by EPA for additional regulation of coal combustion residuals									2
Claims Resolution, Civil Penalties									800,000																																					86,000
Period of time to implement plan								15 years			9 years
Bond Closure and Post Closure Period											45 years
Accrual for Environmental Loss Contingencies									124,000,000
Environmental Liabilities Former Gas Facilities									82,000,000
Decommissioning Fund Investments	2,183,000,000	2,183,000,000		2,204,000,000									2,200,000,000													1,270,000,000		1,283,000,000										0		0
Parental guarantee associated with the funding of decommissioning costs													125,000,000
Parental Guarantee Associated With Funding Of Decommissioning Costs, Additions													11,000,000
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
Gain contingency, unrecorded amount																																												14,000,000
Gain Contingency, Damages Denied, Value																																												90,000,000
Potential MATS Extension Period																																																		1 year	1 year
Gain contingency, damages denied					$ 16,000,000
Number of Petitioners												4

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Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	$ 1,825	[1]	$ 1,827	[2]
Unrealized Gains	21	[1]	34	[2]
Fair Value	1,846	[1]	1,861	[2]
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	433	[1]	293	[2]
Unrealized Gains	28	[1]	16	[2]
Fair Value	461	[1]	309	[2]
FES | Debt Securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	868	[1]	778	[2]
Unrealized Gains	9	[1]	14	[2]
Fair Value	877	[1]	792	[2]
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	317	[1]	281	[2]
Unrealized Gains	21	[1]	13	[2]
Fair Value	$ 338	[1]	$ 294	[2]

[1] Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million

[2] Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,288
Discounted Lease Payments, net	1,079	[1]
Net Exposure	209
Other FE subsidiaries
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	762
Discounted Lease Payments, net	329	[1]
Net Exposure	$ 433

[1] The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion.

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Earnings Per Share of Common Stock (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Income from continuing operations	$ 209		$ 422		$ 233		$ 908
Less: Income attributable to noncontrolling interest	0		0		0		1
Income (Loss) from Continuing Operations Attributable to Parent	209		422		233		907
Discontinued operations (Note 16)	9		3		17		11
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$ 218		$ 425		$ 250		$ 918
Weighted average number of basic shares outstanding	418		417		418		418
Assumed exercise of dilutive stock options and awards	1	[1]	2	[1]	1	[1]	1	[1]
Weighted average number of diluted shares outstanding	419		419		419		419
Basic earnings per share:
Income from continuing operations, in dollars per share	$ 0.50		$ 1.01		$ 0.56		$ 2.17
Discontinued operations (Note 16), in dollars per share	$ 0.02		$ 0.01		$ 0.04		$ 0.03
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.52		$ 1.02		$ 0.60		$ 2.20
Diluted earnings per share:
Income from continuing operations, in dollars per share	$ 0.50		$ 1.00		$ 0.56		$ 2.16
Discontinued operations (Note 16), in dollars per share	$ 0.02		$ 0.01		$ 0.04		$ 0.03
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.52		$ 1.01		$ 0.60		$ 2.19
Shares excluded from the calculation of diluted shares outstanding, in shares	2				2
Maximum
Diluted earnings per share:
Shares excluded from the calculation of diluted shares outstanding, in shares			1				1

[1] For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Income Statement [Abstract]
Tax effect of discontinued operations	$ 3	$ 2	$ 9	$ 8
Excise tax collections included in Revenue	$ 117	$ 123	$ 346	$ 351

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Goodwill

9 Months Ended

Sep. 30, 2013

Goodwill [Abstract]

Goodwill

GOODWILL

In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy first assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50 percent) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value, then the two-step goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.

FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution, Regulated Transmission, Competitive Energy Services and Other/Corporate. Goodwill is allocated to these reportable segments based on the original purchase price allocation of acquisitions. Total goodwill recognized by segment in FirstEnergy's Consolidated Balance Sheet is as follows:

Goodwill	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate		Consolidated
	(In millions)
Balance as of December 31, 2012	$	5,025	$	526	$	896		$	—	$	6,447
Classification to Assets Held for Sale(1)	—		—		(29		)	—		(29		)
Balance as of September 30, 2013	$	5,025	$	526	$	867		$	—	$	6,418

⁽¹⁾ See Note 16, Discontinued Operations and Assets Held for Sale.

FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission segments as of July 31, 2013. FirstEnergy assessed economic, industry and market considerations in addition to overall financial performance of its Regulated Distribution and Regulated Transmission segments. It was determined that the fair values of these segments were, more likely than not, greater than their carrying values. Due to excess generation supply in the region, which has caused a period of protracted low power and capacity prices impacting Competitive operations, FirstEnergy performed a quantitative assessment of the Competitive Energy Services segment as of July 31, 2013. The fair value of the Competitive Energy Services segment was calculated using a discounted cash flow analysis which included the effects of the potential sale of certain hydroelectric power stations and transfer of the Harrison plant to the Regulated Distribution Segment and the Pleasants plant to the Competitive Energy Services Segment as discussed in Note 12, Regulatory Matters. Assumptions used in the analysis include discount rates, market performance, projected operating and capital cash flows and the fair value of debt. The estimated fair value of the Competitive Energy Services segment exceeded its carrying amount (including goodwill) as of July 31, 2013. Continued weak economic conditions, lower than forecasted power and capacity prices, and revised environmental requirements could have a negative impact on future goodwill assessments.

In October of 2013, in connection with the closing of the West Virginia asset transfer, as discussed in Note 12, Regulatory Matters, FirstEnergy transferred approximately $67 million of goodwill from the Competitive Energy Services segment to the Regulated Distribution segment based on the relative fair value of the generating plants to the fair value of the respective segment.

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Consolidated Balance Sheets (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 222	$ 172
Receivables-
Customers, net of allowance for uncollectible accounts of $41 in 2013 and $40 in 2012	1,579	1,614
Other, net of allowance for uncollectible accounts of $3 in 2013 and $4 in 2012	231	315
Materials and supplies, at average cost	731	861
Prepaid taxes	104	119
Derivatives	140	160
Accumulated deferred income taxes	290	319
Other	262	208
Total current assets	3,559	3,768
PROPERTY, PLANT AND EQUIPMENT:
In service	44,089	43,210
Less - Accumulated provision for depreciation	13,167	12,600
Property, plant and equipment in service net of accumulated provision for depreciation	30,922	30,610
Construction work in progress	2,301	2,293
Total net property, plant and equipment	33,223	32,903
INVESTMENTS:
Nuclear plant decommissioning trusts	2,183	2,204
Investments in lease obligation bonds	46	54
Other	876	936
Total other property and investments	3,105	3,194
ASSETS HELD FOR SALE, NET (NOTE 16):	234	0
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,447
Regulatory assets	2,146	2,375
Other	1,698	1,719
Total deferred charges and other assets	10,262	10,541
Total assets	50,383	50,406
CURRENT LIABILITIES:
Currently payable long-term debt	1,889	1,999
Short-term borrowings	3,404	1,969
Accounts payable	995	1,599
Accrued taxes	401	543
Accrued compensation and benefits	289	331
Derivatives	105	126
Other	872	1,038
Total current liabilities	7,955	7,605
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	9,755	9,769
Accumulated other comprehensive income	299	385
Retained earnings	2,448	2,888
Total common stockholders' equity	12,544	13,084
Noncontrolling interest	3	9
Total equity	12,547	13,093
Long-term debt and other long-term obligations	15,291	15,179
Total capitalization	27,838	28,272
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,603	6,616
Retirement benefits	3,104	3,080
Asset retirement obligations	1,834	1,599
Deferred gain on sale and leaseback transaction	866	892
Adverse power contract liability	467	506
Other	1,716	1,836
Total noncurrent liabilities	14,590	14,529
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
Total liabilities and capitalization	$ 50,383	$ 50,406

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Fair Value Measurements (Details 6) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 17,007	$ 16,957
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	17,721	19,460
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	3,015	4,194
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	$ 3,082	$ 4,524

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Consolidated Statements of Income (FirstEnergy Corp.) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012
REVENUES:
Electric utilities	$ 2,530		$ 2,670		$ 7,139		$ 7,533
Unregulated businesses	1,506		1,382		4,131		4,247
Total revenues	4,036	[1]	4,052	[1]	11,270	[1]	11,780	[1]
OPERATING EXPENSES:
Fuel	657		636		1,915		1,833
Purchased power	1,120		1,063		2,932		3,367
Other operating expenses	877		861		2,645		2,597
Provision for depreciation	316		272		909		834
Amortization of regulatory assets, net	312		61		443		198
General taxes	242		257		747		760
Impairment of long-lived assets	0		0		473		0
Total operating expenses	3,524		3,150		10,064		9,589
OPERATING INCOME (LOSS)	512		902		1,206		2,191
OTHER INCOME (EXPENSE):
Gain (loss) on debt redemptions	9		0		(132)		0
Investment income	5		39		8		63
Interest expense	(257)		(230)		(771)		(750)
Capitalized interest	17		18		51		54
Total other income (expense)	(226)		(173)		(844)		(633)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	286		729		362		1,558
INCOME TAXES	77		307		129		650
NET INCOME FROM CONTINUING OPERATIONS	209		422		233		908
Discontinued operations (net of income taxes of $3, $2, $9 and $8, respectively) (Note 16)	9		3		17		11
NET INCOME (LOSS)	218		425		250		919
Income attributable to noncontrolling interest	0		0		0		1
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$ 218		$ 425		$ 250		$ 918
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations, in dollars per share	$ 0.50		$ 1.01		$ 0.56		$ 2.17
Basic - Discontinued Operations (Note 16), in dollars per share	$ 0.02		$ 0.01		$ 0.04		$ 0.03
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.52		$ 1.02		$ 0.60		$ 2.20
Diluted - Continuing Operations, in dollars per share	$ 0.50		$ 1.00		$ 0.56		$ 2.16
Diluted - Discontinued Operations (Note 16), in dollars per share	$ 0.02		$ 0.01		$ 0.04		$ 0.03
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.52		$ 1.01		$ 0.60		$ 2.19
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares	418		417		418		418
Diluted, in shares	419		419		419		419
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share	$ 1.10		$ 1.10		$ 1.65		$ 1.65

[1] Includes excise tax collections of $117 million and $123 million in the three months ended September 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended September 30, 2013 and 2012, respectively.

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Variable Interest Entities (Details Textuals) (USD $)	1 Months Ended	3 Months Ended		9 Months Ended					3 Months Ended		9 Months Ended		12 Months Ended		1 Months Ended
	Mar. 31, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013 entities	Sep. 30, 2012	Sep. 30, 2013 Power Purchase Agreements agreements	Sep. 30, 2013 OE	Sep. 30, 2013 Other FE subsidiaries	Sep. 30, 2013 Other FE subsidiaries Power Purchase Agreements	Sep. 30, 2012 Other FE subsidiaries Power Purchase Agreements	Sep. 30, 2013 Other FE subsidiaries Power Purchase Agreements	Sep. 30, 2012 Other FE subsidiaries Power Purchase Agreements	Dec. 31, 2012 Nuclear Generation Corp Beaver Valley Unit 2	Dec. 31, 2012 FGCO Bruce Mansfield Plant	Aug. 31, 2013 Ohio Funding Companies	Jun. 30, 2013 Ohio Funding Companies	Jun. 30, 2013 Ohio Funding Companies Existing Taxable Bonds	Jun. 30, 2013 Ohio Funding Companies Existing Taxable Bonds Year 2013	Jun. 30, 2013 Ohio Funding Companies Existing Taxable Bonds Year 2015	Jun. 30, 2013 Ohio Funding Companies Existing Taxable Bonds Year 2020	Jun. 30, 2013 Ohio Funding Companies Phase In Recovery Bonds	Sep. 30, 2013 Signal Peak FEV Global Holding	Sep. 30, 2013 Path-WV
Variable Interest Entities (Textuals) [Abstract]
Debt Instrument, Face Amount																	$ 410,000,000	$ 225,000,000	$ 150,000,000	$ 35,000,000	$ 445,000,000
Weighted average interest rate on debt																	5.71%				2.48%
Make-whole premiums paid on debt redemptions				181,000,000	0										120,000,000	30,000,000
Distributions to owners				6,000,000
Equity interest by unaffiliated third party in PNBV				3.00%
Equity interest by OES Ventures in PNBV							3.00%
Ownership interest								0.00%														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%
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities						21
Number of contracts that may contain variable interest				2
Purchased power		1,120,000,000	1,063,000,000	2,932,000,000	3,367,000,000				48,000,000	65,000,000	139,000,000	184,000,000
Purchase of lessor equity interests in sale and leaseback, value	221,000,000												129,000,000	262,000,000
Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments		$ 1,200,000,000		$ 1,200,000,000

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Segment Information (Details Textuals)	9 Months Ended
	Sep. 30, 2013 Regulated Distribution Customers Companies sqmi	Sep. 30, 2013 Competitive Energy Services MW	Sep. 30, 2013 Competitive Energy Services Unregulated Plants Expected to be Closed by 9/1/2012 MW	Oct. 09, 2013 Subsequent Event Regulated Distribution MW	Oct. 09, 2013 Subsequent Event Regulated Distribution Harrison and Pleasants MW
Segment Reporting Information [Line Items]
Number of existing utility operating companies	10
Number of customers served by utility operating companies	6,000,000
Number of square miles in service area	65,000
Megawatts of net demonstrated capacity of competitive segment		15,000		4,000	1,476
Megawatt capacity of plants expected to be closed			885
Plant Capacity Planned for Deactivation		2,080

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Organization and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2013

Organization, Consolidation and Presentation of Financial Statements [Abstract]

NEW ACCOUNTING PRONOUNCEMENTS

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.

EARNINGS PER SHARE OF COMMON STOCK

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.

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. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.

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Asset Retirement Obligations

9 Months Ended

Sep. 30, 2013

Asset Retirement Obligation [Abstract]

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS

FirstEnergy has recognized applicable legal obligations for AROs and their associated cost primarily for nuclear power plant decommissioning, reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks, wastewater treatment lagoons and transformers containing PCBs. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation.

The ARO liabilities for FES primarily relate to the decommissioning of the Beaver Valley, Davis-Besse and Perry nuclear generating facilities. FES uses an expected cash flow approach to measure the fair value of their nuclear decommissioning AROs.

Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not in the recognition of the liability.

The following table summarizes the changes to the ARO balances during 2013:

ARO Reconciliation	FirstEnergy			FES
	(In millions)
Balance, December 31, 2012	$	1,599		$	965
Liabilities settled	(13		)	(14		)
Accretion	85			52
Revisions in estimated cash flows	163			156
Balance, September 30, 2013	$	1,834		$	1,159

During the first quarter of 2013, revisions to estimated cash flows associated with the ARO liability of FES increased the liability. The revision in estimated cash flows related primarily to increased cost estimates for the closure of LBR. The revised cost estimates were the result of a Closure Plan submitted to the PA DEP by FG on March 28, 2013, which provides for placing a final cap over LBR. See Note 13, Commitments, Guarantees, and Contingencies for additional information related to the closure of LBR.

During the third quarter of 2013, studies were completed to update the estimated cost of asbestos remediation for TE and FES. The cost studies resulted in a revision to the estimated cash flows associated with the ARO liabilities of FES and TE and increased the liability for FES and TE by approximately $5 million and $7 million, respectively.

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Impairment of Long-lived Assets (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended				3 Months Ended	9 Months Ended
	Sep. 30, 2013 employees	Jun. 30, 2013	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2012 FES	Oct. 09, 2013 Subsequent Event AE Supply	Jun. 30, 2013 Excessive Inventories	Sep. 30, 2013 Long-Lived Assets to be Abandoned, Total employees	Jul. 08, 2013 Hatfield's Ferry, Units 1-3 MW	Jul. 08, 2013 Mitchell, Units 2-3 MW
Schedule of Generating Plant Retirements [Line Items]
Plant Capacity									1,710	370
Asset Impairment Charges		$ 473	$ 473	$ 0			$ 13
Restructuring and Related Cost, Expected Number of Positions Eliminated (in employees)	250							240
Severance Costs	2			14	10			7
Face amount of debt redeemed						$ 235

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Fair Value Measurements (Details 2) (Level 3, USD $) In Millions, unless otherwise specified																							9 Months Ended
	Sep. 30, 2013 FTRs	Dec. 31, 2012 FTRs	Dec. 31, 2011 FTRs	Sep. 30, 2013 FTRs FES	Dec. 31, 2012 FTRs FES	Dec. 31, 2011 FTRs FES	Sep. 30, 2013 Non Utility Generation Contract		Dec. 31, 2012 Non Utility Generation Contract		Dec. 31, 2011 Non Utility Generation Contract		Sep. 30, 2013 LCAPP Contracts		Dec. 31, 2012 LCAPP Contracts		Dec. 31, 2011 LCAPP Contracts		Sep. 30, 2013 Model FTRs	Sep. 30, 2013 Model FTRs FES	Sep. 30, 2013 Model Non Utility Generation Contract	Sep. 30, 2013 Model LCAPP Contracts	Sep. 30, 2013 Model Minimum FTRs	Sep. 30, 2013 Model Minimum FTRs FES	Sep. 30, 2013 Model Minimum Non Utility Generation Contract MWh	Sep. 30, 2013 Model Minimum LCAPP Contracts	Sep. 30, 2013 Model Maximum FTRs	Sep. 30, 2013 Model Maximum FTRs FES	Sep. 30, 2013 Model Maximum Non Utility Generation Contract MWh	Sep. 30, 2013 Model Maximum LCAPP Contracts	Sep. 30, 2013 Model Weighted Average FTRs	Sep. 30, 2013 Model Weighted Average FTRs FES	Sep. 30, 2013 Model Weighted Average Non Utility Generation Contract MWh	Sep. 30, 2013 Model Weighted Average LCAPP Contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value	$ (11)	$ (1)	$ (22)	$ (11)	$ 0	$ (6)	$ (210)	[1]	$ (254)	[1]	$ (292)	[1]	$ (166)	[1]	$ (144)	[1]	$ 0	[1]	$ (11)	$ (11)	$ (210)	$ (166)
Fair Value Inputs, RTO Auction Clearing Prices																							(5.60)	(5.60)			5.4	5.40			0.62	0.40
Fair Value Inputs, Power																									600				5,864,000				1,421,000
Fair Value Inputs, Power, Regional Prices																									41.40	158.60			57.3	187.60			49.40	171.20

[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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Derivative Instruments (Details 5) (Not Designated as Hedging Instrument, USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (389)	$ (438)	$ (398)	$ (301)
Additions/Change in value of existing contracts	0	(47)	(34)	(325)
Settled contracts	13	60	56	201
Outstanding net asset (liability), Ending Balance	(376)	(425)	(376)	(425)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(231)	(293)	(254)	(293)
Additions/Change in value of existing contracts	7	(50)	(13)	(183)
Settled contracts	14	61	57	194
Outstanding net asset (liability), Ending Balance	(210)	(282)	(210)	(282)
LCAPP
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(158)	(145)	(144)	0
Additions/Change in value of existing contracts	(8)	3	(22)	(142)
Settled contracts	0	0	0	0
Outstanding net asset (liability), Ending Balance	(166)	(142)	(166)	(142)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	0	0	0	(8)
Additions/Change in value of existing contracts	1	0	1	0
Settled contracts	(1)	(1)	(1)	7
Outstanding net asset (liability), Ending Balance	$ 0	$ (1)	$ 0	$ (1)

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Commitments, Guarantees and Contingencies (Tables)

9 Months Ended

Sep. 30, 2013

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations

The following table discloses the additional credit contingent contractual obligations as ofSeptember 30, 2013:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	440	$	6	$	55	$	501
BB+/Ba1 Credit Ratings	$	484	$	6	$	55	$	545
Full impact of credit contingent contractual obligations	$	755	$	58	$	90	$	903

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Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2013

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 as of September 30, 2013:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,288	$	1,079	$	209
Other FE subsidiaries	762		329		433

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion.

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Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2013

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

FirstEnergy
Recurring Fair Value Measurements	September 30, 2013												December 31, 2012
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,299		$	—		$	1,299		$	—		$	1,259		$	—		$	1,259
Derivative assets - commodity contracts	4			197			—			201			—			252			—			252
Derivative assets - FTRs	—			—			3			3			—			—			8			8
Derivative assets - NUG contracts(1)	—			—			23			23			—			—			36			36
Equity securities(2)	461			—			—			461			310			—			—			310
Foreign government debt securities	—			101			—			101			—			126			—			126
U.S. government debt securities	—			171			—			171			—			179			—			179
U.S. state debt securities	—			226			—			226			—			299			—			299
Other(3)	160			157			—			317			126			227			—			353
Total assets	$	625		$	2,151		$	26		$	2,802		$	436		$	2,342		$	44		$	2,822
Liabilities
Derivative liabilities - commodity contracts	$	(5	)	$	(107	)	$	—		$	(112	)	$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—			—			(14		)	(14		)	—			—			(9		)	(9		)
Derivative liabilities - NUG contracts(1)	—			—			(233		)	(233		)	—			—			(290		)	(290		)
Derivative liabilities - LCAPP contracts(1)	—			—			(166		)	(166		)	—			—			(144		)	(144		)
Total liabilities	$	(5	)	$	(107	)	$	(413	)	$	(525	)	$	(3	)	$	(151	)	$	(443	)	$	(597	)
Net assets (liabilities)(4)	$	620		$	2,044		$	(387	)	$	2,277		$	433		$	2,191		$	(399	)	$	2,225

⁽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 or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽⁴⁾  Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, 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 and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2013 and December 31, 2012:

	NUG Contracts(1)									LCAPP Contracts(1)								FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2012 Balance	$	57		$	(349	)	$	(292	)	$	—	$	—		$	—		$	1		$	(23	)	$	(22	)
Unrealized gain (loss)	(20		)	(180		)	(200		)	—		1			1			6			(6		)	—
Purchases	—			—			—			—		(145		)	(145		)	13			(10		)	3
Settlements	(1		)	239			238			—		—			—			(12		)	30			18
December 31, 2012 Balance	$	36		$	(290	)	$	(254	)	$	—	$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
Unrealized gain (loss)	(6		)	(6		)	(12		)	—		(22		)	(22		)	1			2			3
Purchases	—			—			—			—		—			—			5			(15		)	(10		)
Settlements	(7		)	63			56			—		—			—			(11		)	8			(3		)
September 30, 2013 Balance	$	23		$	(233	)	$	(210	)	$	—	$	(166	)	$	(166	)	$	3		$	(14	)	$	(11	)

⁽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 September 30, 2013:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(11	)	Model	RTO auction clearing prices	($5.60) to $5.40	$0.62	Dollars/MWH
NUG Contracts	$	(210	)	Model	Generation Electricity regional prices	600 to 5,864,000 $41.40 to $57.30	1,421,000 $49.40	MWH Dollars/MWH
LCAPP Contracts	$	(166	)	Model	Regional capacity prices	$158.60 to $187.60	$171.20	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 (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of September 30, 2013 and December 31, 2012:

	September 30, 2013(1)						December 31, 2012(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,825	$	21	$	1,846	$	1,827	$	34	$	1,861
FES	868		9		877		778		14		792
Equity securities
FirstEnergy	$	433	$	28	$	461	$	293	$	16	$	309
FES	317		21		338		281		13		294

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 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 AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three months and nine months ended September 30, 2013 and 2012 were as follows:

Three Months Ended
September 30, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	368	$	9	$	(15	)	$	(21	)	$	26
FES	164		5		(3		)	(21		)	16
September 30, 2012	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	1,751	$	81	$	(30	)	$	(2	)	$	18
FES	1,059		60		(21		)	(2		)	10

Nine Months Ended
September 30, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	1,545	$	49	$	(31	)	$	(74	)	$	74
FES	650		38		(14		)	(66		)	44
September 30, 2012	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	2,133	$	118	$	(58	)	$	(9	)	$	51
FES	1,167		85		(40		)	(8		)	27

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 (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of September 30, 2013 and December 31, 2012:

	September 30, 2013						December 31, 2012
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	46	$	1	$	47	$	54	$	30	$	84

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:

	September 30, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	17,007	$	17,721	$	16,957	$	19,460
FES	3,015		3,082		4,194		4,524

FES

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FES
Recurring Fair Value Measurements	September 30, 2013												December 31, 2012
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	742		$	—		$	742		$	—		$	703		$	—		$	703
Derivative assets - commodity contracts	4			197			—			201			—			252			—			252
Derivative assets - FTRs	—			—			2			2			—			—			6			6
Equity securities(1)	338			—			—			338			294			—			—			294
Foreign government debt securities	—			58			—			58			—			61			—			61
U.S. government debt securities	—			26			—			26			—			27			—			27
Other(2)	—			94			—			94			—			104			—			104
Total assets	$	342		$	1,117		$	2		$	1,461		$	294		$	1,147		$	6		$	1,447
Liabilities
Derivative liabilities - commodity contracts	$	(5	)	$	(107	)	$	—		$	(112	)	$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—			—			(13		)	(13		)	—			—			(6		)	(6		)
Total liabilities	$	(5	)	$	(107	)	$	(13	)	$	(125	)	$	(3	)	$	(151	)	$	(6	)	$	(160	)
Net assets (liabilities)(3)	$	337		$	1,010		$	(11	)	$	1,336		$	291		$	996		$	—		$	1,287

⁽¹⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽³⁾  Excludes $12 million and $94 million as of September 30, 2013 and December 31, 2012, 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 September 30, 2013 and December 31, 2012:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2012 Balance	$	1		$	(7	)	$	(6	)
Unrealized gain (loss)	4			(4		)	—
Purchases	9			(7		)	2
Settlements	(8		)	12			4
December 31, 2012 Balance	$	6		$	(6	)	$	—
Unrealized loss	(1		)	(1		)	(2		)
Purchases	4			(12		)	(8		)
Settlements	(7		)	6			(1		)
September 30, 2013 Balance	$	2		$	(13	)	$	(11	)

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 September 30, 2013:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(11	)	Model	RTO auction clearing prices	($5.60) to $5.40	$0.40	Dollars/MWH

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Organization and Basis of Presentation

9 Months Ended

Sep. 30, 2013

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 (FG and NG) and FESC. During the second quarter of 2013, FE completed a $1.5 billion equity contribution to FES.

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, 2012.

FirstEnergy follows GAAP and complies with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the PUCO, the PPUC, the MDPSC, the NYPSC, the WVPSC, the VSCC and the NJBPU. 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 statement 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. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.

FE and its subsidiaries consolidate all majority-owned subsidiaries over which they exercise control and, when applicable, entities for which they have a controlling financial interest. Intercompany transactions and balances are eliminated in consolidation. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 8, Variable Interest Entities). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but with respect to which they are not the primary beneficiary and do not exercise control, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income. These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES.

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.

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Derivative Instruments (Details 2)	Sep. 30, 2013 MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	32,000,000
Sales (in MWH or mmBTUs)	37,000,000
Net (in MWH or mmBTUs)	(5,000,000)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	59,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	59,000,000
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	11,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	11,000,000
LCAPP
Volume of First Energy's outstanding derivative transactions
Volume of Derivatives, Purchases (in MW)	408,000,000
Volume of Derivatives, Sales (in MW)	0
Volume of Derivatives, Net (in MW)	408,000,000
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	64,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	64,000,000

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Goodwill Details (Tables)

9 Months Ended

Sep. 30, 2013

Goodwill [Line Items]

Schedule of Goodwill

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

Goodwill	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Other/Corporate		Consolidated
	(In millions)
Balance as of December 31, 2012	$	5,025	$	526	$	896		$	—	$	6,447
Classification to Assets Held for Sale(1)	—		—		(29		)	—		(29		)
Balance as of September 30, 2013	$	5,025	$	526	$	867		$	—	$	6,418

⁽¹⁾ See Note 16, Discontinued Operations and Assets Held for Sale.

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Organization and Basis of Presentation (Details) (FES, USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Jun. 30, 2013	Sep. 30, 2013	Sep. 30, 2012
FES
Organization, Basis of Presentation and Significant Accounting Policies [Line Items]
Equity contribution from parent	$ 1,500	$ 1,500	$ 0

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Earnings Per Share of Common Stock

9 Months Ended

Sep. 30, 2013

Earnings Per Share [Abstract]

EARNINGS PER SHARE OF COMMON STOCK

EARNINGS PER SHARE OF COMMON STOCK

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 September 30				Nine Months Ended September 30
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2013		2012		2013		2012
	(In millions, except per share amounts)
Net income from continuing operations	$	209	$	422	$	233	$	908
Less: Income attributable to noncontrolling interest	—		—		—		1
Income from continuing operations available to common shareholders	209		422		233		907
Discontinued operations (Note 16)	9		3		17		11
Earnings available to FirstEnergy Corp.	$	218	$	425	$	250	$	918
Weighted average number of basic shares outstanding	418		417		418		418
Assumed exercise of dilutive stock options and awards(1)	1		2		1		1
Weighted average number of diluted shares outstanding	419		419		419		419
Earnings per share:
Basic earnings per share:
Net income from continuing operations	$	0.50	$	1.01	$	0.56	$	2.17
Discontinued operations (Note 16)	0.02		0.01		0.04		0.03
Net earnings per basic share	$	0.52	$	1.02	$	0.60	$	2.20
Diluted earnings per share:
Net income from continuing operations	$	0.50	$	1.00	$	0.56	$	2.16
Discontinued operations (Note 16)	0.02		0.01		0.04		0.03
Net earnings per diluted share	$	0.52	$	1.01	$	0.60	$	2.19

⁽¹⁾  For the three months and nine ended September 30, 2013, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the three and nine months ended September 30, 2012, less than 1 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended				9 Months Ended
	Sep. 30, 2013		Sep. 30, 2012		Sep. 30, 2013		Sep. 30, 2012		Dec. 31, 2012
Segment Financial Information
External revenues	$ 4,036		$ 4,052		$ 11,270		$ 11,778
Internal revenues	0		0		0		2
Total revenues	4,036	[1]	4,052	[1]	11,270	[1]	11,780	[1]
Depreciation and amortization	628		333		1,352		1,032
Investment income	5		39		8		63
Interest expense	257		230		771		750
Income taxes (benefits)	77		307		129		650
Income from continuing operations	209		422		233		908
Discontinued operations (Note 16)	9		3		17		11
NET INCOME (LOSS)	218		425		250		919
Total assets	50,383		48,738		50,383		48,738		50,406
Total goodwill	6,418		6,444		6,418		6,444		6,447
Property additions	548		775		1,960		1,686
Regulated Distribution
Segment Financial Information
External revenues	2,340		2,483		6,593		6,976
Internal revenues	0		0		0		0
Total revenues	2,340		2,483		6,593		6,976
Depreciation and amortization	460		193		882		618
Investment income	14		20		41		62
Interest expense	134		136		404		405
Income taxes (benefits)	50		168		284		355
Income from continuing operations	85		286		474		603
Discontinued operations (Note 16)	0		0		0		0
NET INCOME (LOSS)	85		286		474		603
Total assets	27,030		26,122		27,030		26,122
Total goodwill	5,025		5,025		5,025		5,025		5,025
Property additions	261		308		980		751
Regulated Transmission
Segment Financial Information
External revenues	190		187		546		557
Internal revenues	0		0		0		0
Total revenues	190		187		546		557
Depreciation and amortization	31		28		91		86
Investment income	0		0		0		1
Interest expense	23		24		68		70
Income taxes (benefits)	32		35		93		101
Income from continuing operations	54		59		156		171
Discontinued operations (Note 16)	0		0		0		0
NET INCOME (LOSS)	54		59		156		171
Total assets	4,953		4,519		4,953		4,519
Total goodwill	526		526		526		526
Property additions	105		47		291		169
Competitive Energy Services
Segment Financial Information
External revenues	1,573		1,462		4,350		4,465
Internal revenues	196		209		588		686
Total revenues	1,769		1,671		4,938		5,151
Depreciation and amortization	125		102		347		303
Investment income	(5)		36		(6)		48
Interest expense	53		73		187		209
Income taxes (benefits)	47		74		(189)		165
Income from continuing operations	68		126		(317)		284
Discontinued operations (Note 16)	9		3		17		11
NET INCOME (LOSS)	77		129		(300)		295
Total assets	17,809		16,846		17,809		16,846
Total goodwill	867		893		867		893		896
Property additions	162		412		630		715
Other/Corporate
Segment Financial Information
External revenues	(31)		(31)		(89)		(78)
Internal revenues	0		0		0		0
Total revenues	(31)		(31)		(89)		(78)
Depreciation and amortization	12		9		32		25
Investment income	3		(2)		6		(1)
Interest expense	47		(3)		112		66
Income taxes (benefits)	(44)		(8)		(55)		(49)
Income from continuing operations	0		0		0		0
Discontinued operations (Note 16)	0		0		0		0
NET INCOME (LOSS)	(10)		(13)		(92)		(82)
Total assets	591		1,251		591		1,251
Total goodwill	0		0		0		0
Property additions	20		8		59		51
Reconciling Adjustments
Segment Financial Information
External revenues	(36)		(49)		(130)		(142)
Internal revenues	(196)		(209)		(588)		(684)
Total revenues	(232)		(258)		(718)		(826)
Depreciation and amortization	0		1		0		0
Investment income	(7)		(15)		(33)		(47)
Interest expense	0		0		0		0
Income taxes (benefits)	(8)		38		(4)		78
Income from continuing operations	2		(49)		(80)		(150)
Discontinued operations (Note 16)	0		0		0		0
NET INCOME (LOSS)	12		(36)		12		(68)
Total assets	0		0		0		0
Total goodwill	0		0		0		0
Property additions	$ 0		$ 0		$ 0		$ 0

[1] Includes excise tax collections of $117 million and $123 million in the three months ended September 30, 2013 and 2012, respectively, and $346 million and $351 million in the nine months ended September 30, 2013 and 2012, respectively.

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Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 250	$ 919
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation	909	834
Nuclear fuel amortization	156	156
Deferred rents and lease market valuation liability	(22)	(62)
Deferred income taxes and investment tax credits, net	114	712
Investments impairments	74	10
Pension trust contribution	0	(600)
Commodity derivative transactions, net (Note 10)	24	(80)
Cash collateral, net	(67)	(3)
Loss on debt redemptions	132	0
Make-whole premiums paid on debt redemptions	(181)	0
Income from discontinued operations (Note 16)	(17)	(11)
Decrease (increase) in operating assets-
Receivables	(7)	(41)
Materials and supplies	117	(63)
Prepayments and other current assets	(59)	(151)
Increase (decrease) in operating liabilities-
Accounts payable	(279)	(227)
Accrued taxes	(146)	(58)
Accrued compensation and retirement benefits	(43)	(71)
Other	(14)	92
Net cash provided from operating activities	1,671	1,276
New financing-
Long-term debt	2,745	660
Short-term borrowings, net	1,435	1,604
Redemptions and Repayments-
Long-term debt	(2,662)	(870)
Tender premiums paid on debt redemptions	(110)	0
Other	(64)	(42)
Net cash provided from (used for) financing activities	654	662
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,960)	(1,686)
Nuclear fuel	(159)	(207)
Sales of investment securities held in trusts	1,545	2,133
Purchases of investment securities held in trusts	(1,567)	(2,188)
Other	3	(23)
Net cash used for investing activities	(2,275)	(1,990)
Net change in cash and cash equivalents	50	(52)
Cash and cash equivalents at beginning of period	172	202
Cash and cash equivalents at end of period	222	150
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	(29)	222
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation	231	200
Nuclear fuel amortization	156	159
Deferred rents and lease market valuation liability	(36)	(144)
Deferred income taxes and investment tax credits, net	205	123
Investments impairments	66	8
Pension trust contribution	0	(209)
Gain on asset sales	(20)	(17)
Commodity derivative transactions, net (Note 10)	24	(67)
Cash collateral, net	(35)	(4)
Loss on debt redemptions	103	0
Make-whole premiums paid on debt redemptions	(31)	0
Income from discontinued operations (Note 16)	(14)	(11)
Decrease (increase) in operating assets-
Receivables	(214)	95
Materials and supplies	66	(40)
Prepayments and other current assets	(22)	5
Increase (decrease) in operating liabilities-
Accounts payable	129	312
Accrued taxes	(131)	(150)
Accrued compensation and retirement benefits	(5)	10
Other	(54)	9
Net cash provided from operating activities	389	501
New financing-
Long-term debt	0	560
Short-term borrowings, net	0	3
Equity contribution from parent	1,500	0
Redemptions and Repayments-
Long-term debt	(1,179)	(246)
Tender premiums paid on debt redemptions	(67)	0
Other	(7)	(9)
Net cash provided from (used for) financing activities	247	308
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(477)	(535)
Nuclear fuel	(159)	(207)
Proceeds from asset sales	21	17
Sales of investment securities held in trusts	650	1,167
Purchases of investment securities held in trusts	(694)	(1,194)
Loans to affiliated companies, net	22	(55)
Other	0	(6)
Net cash used for investing activities	(637)	(813)
Net change in cash and cash equivalents	(1)	(4)
Cash and cash equivalents at beginning of period	3	7
Cash and cash equivalents at end of period	$ 2	$ 3

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Consolidated Statements of Cash Flows (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 250	$ 919
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	909	834
Amortization of regulatory assets, net	443	198
Nuclear fuel amortization	156	156
Deferred purchased power and other costs	(61)	(214)
Deferred income taxes and investment tax credits, net	114	712
Impairments of long-lived assets	473	0
Investments impairments	74	10
Deferred rents and lease market valuation liability	(22)	(62)
Retirement benefits	(133)	(97)
Gain on asset sales	(21)	(17)
Commodity derivative transactions, net (Note 10)	24	(80)
Pension trust contribution	0	(600)
Cash collateral, net	(67)	(3)
Loss on debt redemptions	132	0
Make-whole premiums paid on debt redemptions	(181)	0
Income from discontinued operations (Note 16)	(17)	(11)
Decrease (increase) in operating assets-
Receivables	(7)	(41)
Materials and supplies	117	(63)
Prepayments and other current assets	(59)	(151)
Increase (decrease) in operating liabilities-
Accounts payable	(279)	(227)
Accrued taxes	(146)	(58)
Accrued interest	29	50
Accrued compensation and retirement benefits	(43)	(71)
Other	(14)	92
Net cash provided from operating activities	1,671	1,276
New Financing-
Long-term debt	2,745	660
Short-term borrowings, net	1,435	1,604
Redemptions and Repayments-
Long-term debt	(2,662)	(870)
Tender premiums paid on debt redemptions	(110)	0
Common stock dividend payments	(690)	(690)
Other	(64)	(42)
Net cash provided from (used for) financing activities	654	662
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,960)	(1,686)
Nuclear fuel	(159)	(207)
Sales of investment securities held in trusts	1,545	2,133
Purchases of investment securities held in trusts	(1,567)	(2,188)
Cash investments	(12)	100
Asset removal costs	(125)	(119)
Other	3	(23)
Net cash used for investing activities	(2,275)	(1,990)
Net change in cash and cash equivalents	50	(52)
Cash and cash equivalents at beginning of period	172	202
Cash and cash equivalents at end of period	$ 222	$ 150

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Fair Value Measurements (Details) (Recurring, USD $) In Millions, unless otherwise specified	Sep. 30, 2013		Dec. 31, 2012
Assets
Fair value, assets	$ 2,802		$ 2,822
Liabilities
Fair value, liabilities	(525)		(597)
Net assets (liabilities)	2,277	[1]	2,225	[1]
FES
Assets
Fair value, assets	1,461		1,447
Liabilities
Fair value, liabilities	(125)		(160)
Net assets (liabilities)	1,336	[2]	1,287	[2]
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(112)		(154)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(112)		(154)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(14)		(9)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(13)		(6)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(233)	[3]	(290)	[3]
LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(166)	[3]	(144)	[3]
Corporate debt securities
Assets
Fair value, assets	1,299		1,259
Corporate debt securities | FES
Assets
Fair value, assets	742		703
Commodity contracts | Derivative Assets
Assets
Fair value, assets	201		252
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	201		252
FTRs | Derivative Assets
Assets
Fair value, assets	3		8
FTRs | Derivative Assets | FES
Assets
Fair value, assets	2		6
NUG contracts | Derivative Assets
Assets
Fair value, assets	23	[3]	36	[3]
Equity securities
Assets
Fair value, assets	461	[4]	310	[4]
Equity securities | FES
Assets
Fair value, assets	338	[4]	294	[4]
Foreign government debt securities
Assets
Fair value, assets	101		126
Foreign government debt securities | FES
Assets
Fair value, assets	58		61
U.S. government debt securities
Assets
Fair value, assets	171		179
U.S. government debt securities | FES
Assets
Fair value, assets	26		27
U.S. state debt securities
Assets
Fair value, assets	226		299
Other
Assets
Fair value, assets	317	[5]	353	[5]
Other | FES
Assets
Fair value, assets	94	[5]	104	[5]
Level 1
Assets
Fair value, assets	625		436
Liabilities
Fair value, liabilities	(5)		(3)
Net assets (liabilities)	620	[1]	433	[1]
Level 1 | FES
Assets
Fair value, assets	342		294
Liabilities
Fair value, liabilities	(5)		(3)
Net assets (liabilities)	337	[2]	291	[2]
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(5)		(3)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(5)		(3)
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 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[3]	0	[3]
Level 1 | LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[3]	0	[3]
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 | 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 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	[3]	0	[3]
Level 1 | Equity securities
Assets
Fair value, assets	461	[4]	310	[4]
Level 1 | Equity securities | FES
Assets
Fair value, assets	338	[4]	294	[4]
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. state debt securities
Assets
Fair value, assets	0		0
Level 1 | Other
Assets
Fair value, assets	160	[5]	126	[5]
Level 1 | Other | FES
Assets
Fair value, assets	0	[5]	0	[5]
Level 2
Assets
Fair value, assets	2,151		2,342
Liabilities
Fair value, liabilities	(107)		(151)
Net assets (liabilities)	2,044	[1]	2,191	[1]
Level 2 | FES
Assets
Fair value, assets	1,117		1,147
Liabilities
Fair value, liabilities	(107)		(151)
Net assets (liabilities)	1,010	[2]	996	[2]
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(107)		(151)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(107)		(151)
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 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[3]	0	[3]
Level 2 | LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	[3]	0	[3]
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,299		1,259
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	742		703
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	197		252
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	197		252
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 | NUG contracts | Derivative Assets
Assets
Fair value, assets	0	[3]	0	[3]
Level 2 | Equity securities
Assets
Fair value, assets	0	[4]	0	[4]
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	[4]	0	[4]
Level 2 | Foreign government debt securities
Assets
Fair value, assets	101		126
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	58		61
Level 2 | U.S. government debt securities
Assets
Fair value, assets	171		179
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	26		27
Level 2 | U.S. state debt securities
Assets
Fair value, assets	226		299
Level 2 | Other
Assets
Fair value, assets	157	[5]	227	[5]
Level 2 | Other | FES
Assets
Fair value, assets	94	[5]	104	[5]
Level 3
Assets
Fair value, assets	26		44
Liabilities
Fair value, liabilities	(413)		(443)
Net assets (liabilities)	(387)	[1]	(399)	[1]
Level 3 | FES
Assets
Fair value, assets	2		6
Liabilities
Fair value, liabilities	(13)		(6)
Net assets (liabilities)	(11)	[2]	0	[2]
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	(14)		(9)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(13)		(6)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(233)	[3]	(290)	[3]
Level 3 | LCAPP Contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(166)	[3]	(144)	[3]
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 | 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	3		8
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	2		6
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	23	[3]	36	[3]
Level 3 | Equity securities
Assets
Fair value, assets	0	[4]	0	[4]
Level 3 | Equity securities | FES
Assets
Fair value, assets	0	[4]	0	[4]
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. state debt securities
Assets
Fair value, assets	0		0
Level 3 | Other
Assets
Fair value, assets	0	[5]	0	[5]
Level 3 | Other | FES
Assets
Fair value, assets	$ 0	[5]	$ 0	[5]

[1] Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

[2] Excludes $12 million and $94 million as of September 30, 2013 and December 31, 2012, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

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

[4] NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

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Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 323	$ 389	$ 385	$ 426
Other comprehensive income (loss) before reclassifications	5	25	19	44
Amounts reclassified from AOCI	(29)	(47)	(105)	(103)
Net other comprehensive income (loss)	(24)	(22)	(86)	(59)
AOCI Ending Balance	299	367	299	367
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	62	84	72	76
Other comprehensive income (loss) before reclassifications	4	23	17	45
Amounts reclassified from AOCI	(4)	(29)	(27)	(43)
Net other comprehensive income (loss)	0	(6)	(10)	2
AOCI Ending Balance	62	78	62	78
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(37)	(39)	(38)	(39)
Other comprehensive income (loss) before reclassifications	0	0	0	1
Amounts reclassified from AOCI	1	0	2	(1)
Net other comprehensive income (loss)	1	0	2	0
AOCI Ending Balance	(36)	(39)	(36)	(39)
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	1	6	3	8
Other comprehensive income (loss) before reclassifications	0	(1)	0	0
Amounts reclassified from AOCI	0	(1)	(2)	(4)
Net other comprehensive income (loss)	0	(2)	(2)	(4)
AOCI Ending Balance	1	4	1	4
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	13	27	15	19
Other comprehensive income (loss) before reclassifications	5	25	19	38
Amounts reclassified from AOCI	(1)	(25)	(17)	(30)
Net other comprehensive income (loss)	4	0	2	8
AOCI Ending Balance	17	27	17	27
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	12	25	13	16
Other comprehensive income (loss) before reclassifications	4	24	17	37
Amounts reclassified from AOCI	(1)	(25)	(15)	(29)
Net other comprehensive income (loss)	3	(1)	2	8
AOCI Ending Balance	15	24	15	24
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	347	401	408	446
Other comprehensive income (loss) before reclassifications	0	0	0	5
Amounts reclassified from AOCI	(29)	(22)	(90)	(72)
Net other comprehensive income (loss)	(29)	(22)	(90)	(67)
AOCI Ending Balance	318	379	318	379
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	49	53	56	52
Other comprehensive income (loss) before reclassifications	0	0	0	8
Amounts reclassified from AOCI	(3)	(3)	(10)	(10)
Net other comprehensive income (loss)	(3)	(3)	(10)	(2)
AOCI Ending Balance	$ 46	$ 50	$ 46	$ 50

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Pension and Other Postemployment Benefits (Tables)

9 Months Ended

Sep. 30, 2013

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Costs

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended September 30,	2013			2012			2013			2012
	(In millions)
Service costs	$	49		$	40		$	3		$	3
Interest costs	93			97			9			12
Expected return on plan assets	(125		)	(121		)	(8		)	(9		)
Amortization of prior service costs (credits)	3			3			(50		)	(50		)
Net periodic costs (credits)	$	20		$	19		$	(46	)	$	(44	)

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Nine Months Ended September 30,	2013			2012			2013			2012
	(In millions)
Service costs	$	147		$	120		$	9		$	9
Interest costs	279			291			27			36
Expected return on plan assets	(375		)	(363		)	(24		)	(27		)
Amortization of prior service costs (credits)	9			9			(157		)	(152		)
Net periodic costs (credits)	$	60		$	57		$	(145	)	$	(134	)

Net Periodic Pension and OPEB Costs

The net periodic pension and OPEB costs (net of amounts capitalized) recognized in earnings by FE and FES were as follows:

Net Periodic Benefit Expense (Credit)	Pensions				OPEB
For the Three Months Ended September 30,	2013		2012		2013			2012
	(In millions)
FirstEnergy	$	16	$	14	$	(31	)	$	(30	)
FES	5		5		(4		)	(4		)

Net Periodic Benefit Expense (Credit)	Pensions				OPEB
For the Nine Months Ended September 30,	2013		2012		2013			2012
	(In millions)
FirstEnergy	$	41	$	41	$	(95	)	$	(92	)
FES	13		13		(12		)	(12		)

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Derivative Instruments (Details Textuals) (USD $)	3 Months Ended		9 Months Ended									9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2013 Commodity contracts	Sep. 30, 2013 NUGs	Sep. 30, 2013 FTRs	Sep. 30, 2013 FES Commodity contracts	Sep. 30, 2013 FES FTRs	Sep. 30, 2013 JCP&L contracts	Oct. 11, 2013 JCP&L Subsequent Event appeal	Sep. 30, 2013 Cash Flow Hedges agreements	Dec. 31, 2012 Cash Flow Hedges agreements	Sep. 30, 2013 Fair Value Hedging agreements	Sep. 30, 2012 Fair Value Hedging	Sep. 30, 2013 Fair Value Hedging agreements	Sep. 30, 2012 Fair Value Hedging	Dec. 31, 2012 Fair Value Hedging agreements
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 5,000,000		$ 5,000,000	$ 10,000,000
Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months			10,000,000
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding												0	0
Unamortized gains or losses associated with prior interest rate hedges	61,000,000		61,000,000	70,000,000
Losses to be amortized to interest expenses during next twelve months												9,000,000				13,000,000
Number of fixed-for-floating interest rate swap agreements outstanding														0		0		0
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	48,000,000		48,000,000	79,000,000
Reclassifications from long-term debt														4,000,000	6,000,000	15,000,000	17,000,000
Unamortized gain (loss) on extinguishment of debt	9,000,000		17,000,000											9,000,000		17,000,000
Net asset position under commodity derivative contracts					89,000,000
Collateral posted								43,000,000	6,000,000
Additional collateral related to commodity derivatives								9,000,000
Expected adverse change in quoted market prices of derivative instruments	10.00%		10.00%
Decrease net income due to adverse change in commodity prices			27,000,000
Proceeds from Interest Rate Derivative, Termination		6,000,000
Liability position						210,000,000	11,000,000
Number of outstanding LCAPP contracts										2
Number of appeals dismissed											2
Period in which LSEs may request direct allocation of FTRs			2 years
Direct allocation of FTRs, cost			$ 0

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Fair Value Measurements (Details Textuals) (USD $)	3 Months Ended		9 Months Ended			0 Months Ended		9 Months Ended	0 Months Ended	3 Months Ended		9 Months Ended			0 Months Ended		3 Months Ended	9 Months Ended		1 Months Ended				0 Months Ended	1 Months Ended				1 Months Ended								0 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012	May 08, 2013 Revolving Credit Facility credit_facility	Oct. 31, 2013 Revolving Credit Facility Subsequent Event	Sep. 30, 2013 NUG contracts	May 08, 2013 FE Revolving Credit Facility	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Dec. 31, 2012 FES	May 08, 2013 FES Revolving Credit Facility	Oct. 31, 2013 FES Corp and Allegheny Energy Inc Revolving Credit Facility Subsequent Event	Sep. 30, 2013 FGCO	Sep. 30, 2013 FGCO	Jun. 03, 2013 FGCO	Aug. 31, 2013 Ohio Funding Companies	Jun. 30, 2013 Ohio Funding Companies	Aug. 31, 2013 Ohio Funding Companies Minimum	Aug. 31, 2013 Ohio Funding Companies Maximum	May 08, 2013 JCP&L Revolving Credit Facility	Mar. 31, 2013 Senior Notes FE	Mar. 31, 2013 Senior Notes FES	Mar. 31, 2013 Senior Notes FES Year 2021	Mar. 31, 2013 Senior Notes FES Year 2039	Mar. 31, 2013 Senior Notes Allegheny Energy Inc	Mar. 31, 2013 Senior Notes Allegheny Energy Inc Year 2019	Mar. 31, 2013 Senior Notes Allegheny Energy Inc Year 2039	Mar. 31, 2013 Senior Notes FES Corp and Allegheny Energy Inc Minimum	Mar. 31, 2013 Senior Notes FES Corp and Allegheny Energy Inc Maximum	Mar. 31, 2013 Senior Notes, 2.75% Due 2018 Senior Notes FE	Mar. 31, 2013 Senior Notes, 4.25% Due 2023 Senior Notes FE	Mar. 31, 2013 Senior Notes, 3.50% Due 2023 Senior Notes Met-Ed	Apr. 15, 2013 Senior Notes, 4.80% Due 2015 Senior Notes FES	Mar. 31, 2013 Senior Notes, 4.80% Due 2015 Senior Notes FES	Jun. 30, 2013 Phase In Recovery Bonds Ohio Funding Companies	Aug. 31, 2013 Notes, 4.7% Due 2024 Unsecured Debt JCP&L	Mar. 31, 2013 Senior Notes, 4.95% Due 2013 Senior Notes, 3.50% Due 2023 Senior Notes Met-Ed	Jun. 30, 2013 Existing Taxable Bonds Ohio Funding Companies	Jun. 30, 2013 Existing Taxable Bonds Ohio Funding Companies Year 2013	Jun. 30, 2013 Existing Taxable Bonds Ohio Funding Companies Year 2015	Jun. 30, 2013 Existing Taxable Bonds Ohio Funding Companies Year 2020
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price								3 years
Investment excludes Receivables, Payables and Accrued income	$ 13,000,000		$ 13,000,000		$ 110,000,000					$ 12,000,000		$ 12,000,000		$ 94,000,000
Cash balance excluded from available for sale securities	106,000,000		106,000,000		326,000,000					55,000,000		55,000,000		196,000,000
Investments not required to be disclosed	646,000,000		646,000,000		644,000,000
Debt instrument, face amount																									1,500,000,000									650,000,000	850,000,000	300,000,000			445,000,000	500,000,000		410,000,000	225,000,000	150,000,000	35,000,000
Stated interest rate percentage																						5.65%	7.25%									5.75%	6.80%	2.75%	4.25%	3.50%	4.80%	4.80%		4.70%	4.95%
Debt repurchased																										369,000,000	252,000,000	117,000,000	294,000,000	194,000,000	100,000,000						400,000,000
Face amount of debt repurchased																			235,000,000	660,000,000																					150,000,000
Payments of debt redemption premiums																										67,000,000			43,000,000								31,000,000
Debt repurchase notice amount																																						400,000,000
Loss on debt redemptions	9,000,000	0	(132,000,000)	0						0	0	(103,000,000)	0				0	0							119,000,000	71,000,000											32,000,000
Line of Credit Facility, Number of Credit Facilities Extended						3
Line of Credit Facility, Term, Extension Period									1 year						1 year									1 year
Line of Credit Facility, Increase, Borrowing Capacity									500,000,000						500,000,000									175,000,000
Line of Credit Facility, Current Borrowing Capacity							2,500,000,000.0		2,500,000,000						2,500,000,000	2,500,000,000.0								600,000,000
Line of Credit Facility, Amounts Excluded From Debt to Capital Ratio Calculation							1,400,000,000									785,700,000
Line of Credit Facility, Increase, Amounts Excluded From Debt to Capital Ratio Calculation							1,350,000,000.00
Weighted average interest rate on debt																																							2.48%			5.71%
Make-whole premiums paid on debt redemptions			$ 181,000,000	$ 0								$ 31,000,000	$ 0							$ 120,000,000	$ 30,000,000

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Income Taxes

9 Months Ended

Sep. 30, 2013

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Judgment is required in determining FirstEnergy's income taxes and in evaluating tax positions taken or expected to be taken on its tax returns. In the third quarter of 2013, FirstEnergy increased its liability for unrecognized income tax benefits by approximately $5 million. There were no material changes to FirstEnergy's unrecognized income tax benefits during the first nine months of 2012.

As of September 30, 2013, it is reasonably possible that approximately $4 million of unrecognized income tax benefits may be resolved within the next twelve months, all of which, if recognized, would affect FirstEnergy's effective tax rate.

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 nine months of 2013 and 2012, there were no material changes to the amount of accrued interest. The net amount of interest accrued as of September 30, 2013 and December 31, 2012 was approximately $10 million and $9 million, respectively.

As of December 31, 2012, the deferred income taxes consisted of $319 million of current federal, $466 million of long-term federal and $389 million of state and local net operating loss carryforwards. The American Taxpayer Relief Act of 2012 (Act) was enacted in January 2013 and provides 50% accelerated (bonus) depreciation for qualifying expenditures made in 2013. As a result of the availability of 50% bonus depreciation for 2013, none of the $319 million of the current federal deferred tax asset as of December 31, 2012, will be realized in 2013, but will be available for future periods. As of September 30, 2013,FirstEnergy expects to utilize federal and state net operating loss carryforwards in the next twelve months and therefore has classified $290 million to current deferred income taxes.

As discussed in Note 3, Impairment of Long-Lived Assets, on July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating two coal-fired generating plants. As a result of the decision, FirstEnergy determined that it is more likely than not that certain state and local net operating loss carryforwards will not be realized through future operations or through the reversal of existing temporary differences. As a result, FirstEnergy recorded a valuation reserve of approximately $20 million against net operating loss carryforwards in the second quarter of 2013.

On July 9, 2013, Pennsylvania House Bill 465 (HB 465) was enacted, adopting new market-based sourcing rules for certain items of income as well as increasing the Pennsylvania net operating loss deduction credit for tax years beginning after December 31, 2013 and 2014 to the greater of 25% or $4 million of taxable income and 30% or $5 million of taxable income, respectively. Based on income projections, Pennsylvania net operating loss carryforward valuation reserves were reduced by approximately $8 million in the third quarter of 2013.

During the third quarter of 2013, FirstEnergy made changes to state apportionment factors in certain jurisdictions based on sales sourcing rules for electricity, which reduced deferred tax liabilities by approximately $9 million. Furthermore, in the third quarter of 2013, based on the assessment of business operations, FirstEnergy determined that income from certain subsidiaries should not be apportioned to certain tax jurisdictions due to the absence of business nexus. This assessment resulted in a reduction to deferred tax liabilities of approximately $22 million.

FirstEnergy's three and nine months ended September 30, 2013 effective tax rate was 26.9% and 35.6%, respectively. The effective tax rate for the three months ended September 30, 2013 benefited by reductions in valuation reserves against net operating loss carryforwards, and changes in state apportionment factors as described above. The effective tax rate for the nine months ended September 30, 2013 benefited by changes in state apportionment factors as discussed above, however, was partially offset by a net increase in valuation reserves against net operating loss carryforwards.

FirstEnergy's three and nine months ended September 30, 2012 effective tax rate was 42.1% and 41.7%, respectively. The effective tax rate for the three and nine months ended September 30, 2012 was negatively impacted by recognition of valuation reserves against net operating loss carryforwards and the elimination of certain tax deductions associated with Medicare Part D subsidies.

FES’ three and nine months ended September 30, 2013 effective tax rate was 41.1% and 30.6%, respectively. The effective tax rate for the nine months ended September 30, 2013 was impacted by the loss on debt redemptions of approximately $103 million and a $4 million valuation reserve against net operating loss carryforwards.

FES’three and nine months ended September 30, 2012 effective tax rate was 40.5% and 39.7%, respectively. FES’ effective tax rate for the three and nine months ended September 30, 2012 was negatively impacted by higher state apportionment allocation factors.

The 2013 effective tax rate for FirstEnergy and FES is estimated to be approximately 37%.

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Impairment of Long-lived Assets

9 Months Ended

Sep. 30, 2013

Property, Plant and Equipment [Abstract]

Impairment of Long-lived Assets

IMPAIRMENT OF LONG-LIVED ASSETS

FirstEnergy reviews long-lived assets, including regulatory assets, for impairment whenever events or changes in circumstances indicate that the carrying value of such assets may not be recoverable. The recoverability of a long-lived asset is measured by comparing its carrying value to the sum of undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value is greater than the undiscounted cash flows, an impairment exists and a loss is recognized for the amount by which the carrying value of the long-lived asset exceeds its estimated fair value. FirstEnergy utilizes the income approach, based upon discounted cash flows to estimate fair value.

Generating Plant Retirements - 2013

On July 8, 2013, officers of FirstEnergy and AE Supply committed to deactivating the following generating units by October 9, 2013:

Generating Units	MW Capacity	Location
Hatfield's Ferry, Units 1-3	1,710	Masontown, Pennsylvania
Mitchell, Units 2-3	370	Courtney, Pennsylvania

As a result of this decision, in the second quarter of 2013, FirstEnergy recorded a pre-tax impairment of approximately $473 million to continuing operations, which also includes pre-tax impairments of $13 million related to excessive inventory at these facilities. The impairment charge is included within the results of the Competitive Energy Services Segment.

Approximately 240 plant employees and generation related positions were affected by these plant deactivations. FirstEnergy recorded approximately $7 million (pre-tax) severance related expenses that were recognized in Other operating expenses in the Consolidated Statements of Income during the nine months ended 2013.

On October 9, 2013, Hatfield's Ferry Units 1-3 and Mitchell Units 2-3 were deactivated. With the termination of operations at Hatfield's Ferry, AE Supply has the right to redeem $235 million of its outstanding PCRBs at par. A conditional notice of full redemption was issued on October 18, 2013, calling the $235 million of outstanding PCRB's for redemption on November 15, 2013.

AE Supply has obligations, such as fuel supply, that could be affected by the plant closings and management is currently unable to reasonably estimate potential costs, or a range thereof, that could be incurred.

Generating Plant Retirements - 2012

As of September 1, 2012, Albright, Armstrong, Bay Shore Units 2-4, Eastlake Units 4-5, R. Paul Smith, Rivesville and Willow Island were deactivated.FG entered into RMR arrangements with PJM for Eastlake Units 1-3, Ashtabula Unit 5 and Lake Shore Unit 18 through the spring of 2015, when they are scheduled to be deactivated. During the nine months ended September 30, 2012, FirstEnergy recognized pre-tax severance expense of approximately $14 million ($10 million by FES) as a result of the deactivations. These costs are included in Other operating expenses in the Consolidated Statements of Income (Loss).

Cost Savings Initiatives

In addition to deactivating Hatfield's Ferry and Mitchell, FirstEnergy identified and intends to implement additional cost control opportunities across the organization. These actions include reductions to medical and other employee benefits and other organizational changes, including a reduction in staffing of an additional 250 positions. FirstEnergy incurred approximately $2 million (pre-tax) of severance related expenses in the third quarter of 2013.

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Regulatory Matters (Details) (USD $)	3 Months Ended	9 Months Ended		3 Months Ended	9 Months Ended		1 Months Ended			9 Months Ended			1 Months Ended		3 Months Ended			0 Months Ended	9 Months Ended	0 Months Ended			9 Months Ended	0 Months Ended		9 Months Ended			0 Months Ended				0 Months Ended			1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended		9 Months Ended					3 Months Ended	9 Months Ended	12 Months Ended						0 Months Ended		0 Months Ended						1 Months Ended	9 Months Ended			1 Months Ended	3 Months Ended	1 Months Ended			9 Months Ended
	Jun. 30, 2013	Sep. 30, 2013 entities	Sep. 30, 2012	Jun. 30, 2013 FES	Sep. 30, 2013 FES	Sep. 30, 2012 FES	Oct. 31, 2013 AE Supply Subsequent Event	Oct. 31, 2013 M P [Member] Subsequent Event	Apr. 30, 2007 FERC kv	Sep. 30, 2013 FERC class	Jan. 21, 2010 FERC issues	Sep. 04, 2013 FERC Hydroelectric Asset Sale MW plant	May 31, 2013 FERC MOPR Reform	Dec. 07, 2012 FERC MOPR Reform exemption	Sep. 30, 2013 FERC Synchronous Condensers	Dec. 20, 2012 FERC Synchronous Condensers	Sep. 30, 2013 FERC PJM	Aug. 24, 2012 FERC PATH	Sep. 30, 2013 FERC PATH kv	Aug. 24, 2012 FERC PATH-Allegheny	Aug. 24, 2012 FERC Path-WV	Sep. 28, 2012 FERC Path-WV challenge	Sep. 30, 2013 FERC FES and AE Supply FTR Underfunding Complaint Minimum	Sep. 03, 2013 MARYLAND	Dec. 22, 2011 MARYLAND	Sep. 30, 2013 MARYLAND	Aug. 31, 2011 MARYLAND	Oct. 06, 2009 MARYLAND	Jun. 14, 2013 NEW JERSEY	Sep. 30, 2013 NEW JERSEY component bgs	Feb. 22, 2013 NEW JERSEY	Nov. 30, 2012 NEW JERSEY	Jun. 14, 2013 NEW JERSEY JCP&L	Aug. 07, 2013 OHIO	Jan. 31, 2013 OHIO Party	Aug. 31, 2011 OHIO proposals	Oct. 31, 2009 OHIO proposals	Sep. 30, 2013 OHIO plan	Dec. 31, 2009 OHIO	Dec. 12, 2012 OHIO questions	Sep. 30, 2013 OHIO Year 2012 MWh	Sep. 30, 2013 OHIO Year 2013 MWh	Sep. 30, 2013 OHIO Year 2014 MWh	Sep. 30, 2013 OHIO Annually Through 2025 MWh	Sep. 30, 2013 OHIO Annually Through 2018	Sep. 30, 2013 PENNSYLVANIA	Sep. 30, 2013 PENNSYLVANIA	Dec. 31, 2010 PENNSYLVANIA	Apr. 04, 2013 PENNSYLVANIA enhancement	Feb. 15, 2013 PENNSYLVANIA choice workgroup comment	Jan. 16, 2013 PENNSYLVANIA Party issues	May 31, 2011 PENNSYLVANIA	Apr. 29, 2011 PENNSYLVANIA questions	Oct. 10, 2013 PENNSYLVANIA Subsequent Event proposals	Sep. 30, 2013 PENNSYLVANIA Year 2013	Oct. 10, 2013 PENNSYLVANIA Three Month Period Subsequent Event	Oct. 10, 2013 PENNSYLVANIA Twelve Month Period Subsequent Event	Oct. 10, 2013 PENNSYLVANIA Twenty-Four Month Period Subsequent Event	Oct. 10, 2013 PENNSYLVANIA Forty-Eight Month Period Subsequent Event	Sep. 30, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Feb. 06, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Apr. 30, 2010 WEST VIRGINIA	Sep. 30, 2013 WEST VIRGINIA MW	Oct. 22, 2012 WEST VIRGINIA hearing	Feb. 28, 2011 WEST VIRGINIA Facilities	Oct. 31, 2013 WEST VIRGINIA Subsequent Event	Sep. 30, 2013 WEST VIRGINIA Subsequent Event	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	Sep. 30, 2013 California Claims Matters FERC	Sep. 30, 2013 The Seneca Pumped Storage Project FERC MW	Sep. 30, 2013 The Seneca Pumped Storage Project Relicensing
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
Recovery period for expenditures for cost recovery program																									5 years	3 years
Maximum penalty assessed, in dollars per day per violation																										25,000
Expected increase in cost due to proposed plan																										106,000,000
Expected Infrastructure Investments																								2,700,000,000
Expected Infrastructure Investments, Period																								15 years
Number of Supply Components																														2
Number of Basic Generation Services																														1
Requested increase in revenues																															603,000,000	31,500,000
Increase (Decrease) in Revenue Recovery Request																															112,000,000
Number of cost recovery choices																																																		2
Load cap percentage minimum																																						80.00%
Maximum trance award to a single supplier																																						80.00%
Generation discount for low income customers																																						6.00%
Recovery Period																																						5 years
Costs avoided by customers																																						360,000,000
Fund to assist low income customers																																						12,000,000
ESP Extension Term																																						2 years
Loss Contingency, New Claims Filed, Number																																			2
Generation supply auction period, after approval																																						3 years
Generation supply auction period, before approval																																						1 year
Annual energy savings																																									1,211,000	1,726,000	2,306,000	2,903,000
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%
Number of plans																																						3
Portfolio Plan, Estimated Cost																																						250,000,000
Portion of Revenue Obtained to be Received																																						20.00%
Request for proposals conducted																																				2	3
Credit to Non-Shopping Customers																																		43,300,000
Credit to Non-Shopping Customers, Implementation Period																																		60 days
Marginal Transmission Refund Period																																															29 months
Marginal transmission losses																																																254,000,000
Asset Impairment Charges	473,000,000	473,000,000	0																																											254,000,000																				330,000,000
Regulatory Liabilities																																																																			23,000,000
Minimum reduction in Utilities reduce energy consumption																																																				1.00%			3.00%
Minimum reduction in Utilities peak demand																																																							4.50%
Loss Contingency, Range of Possible Loss, Maximum																																																												20,000,000	234,000,000
Number of parties not settled																																																			1
Number of issues not settled																																																			1
Energy Contract, Term																																																								3 months	12 months	24 months	48 months
Number of Requests For Proposal																																																						1
Request for Proposal, Project Term																																																						2 years
Annualized base rate increase																																																														40,000,000
Storm Restoration Deferral Period																																																														5 years
Number of public hearings held																																																																2
Period of time to implement plan																																																															6 months
Additional base rate increase																													20,600,000																																	20,000,000
Recommend Reduction in Base Rates for Electric Service																																	202,800,000
Decrease in ENEC rates																																																														20,000,000
Number of electric generation facilities																																																																	3
Number of electric generation facilities, owned by third party																																																																				1	1
Cash Consideration received in Asset Swap Transaction							1,100,000,000
Noncash or Part Noncash Acquisition, Debt Assumed							73,500,000
Cash Consideration provided in Asset Swap Transaction								1,100,000,000
Equity contribution from parent				1,500,000,000	1,500,000,000	0		527,000,000
Proceeds from Collection of (Payments to Fund) Long-term Loans to Related Parties					22,000,000	(55,000,000)		573,000,000
Power threshold for cost methodology									500
Compliance Filing, Hybrid Methodology, Beneficiary Pays Cost Allocation																	50.00%
Denied Recovery Charges of Exit Fees										78,800,000
Identified issues for written comments											9
Annual Revenue requirements in Zone										16,000,000
Number of classes of regulatory proceedings										2
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
Cost recovery, PP&E reclassified to Regulatory Assets																				62,000,000	59,000,000
Number of Formal Challenges																						3
Auctioned Energy Price													59
Hydroelectric project																																																																								451
Application to Sell Power Plant Projects, Number												11
Application to Sell Power Plant Projects, Combined Power												527
Application to Sell Power Plant Projects, Price												400,000,000
Asset Transfer, Price																21,500,000
Period of cycle																																																																									5 years
Number of Exemptions Added														2
Estimated Conversion Costs																60,000,000
Asset Transfer, Recognized Gain															17,000,000
Percent of Meters to be Installed																																														98.50%	98.50%
Expected Cost of Meter Installations																																														1,250,000,000	1,250,000,000
Directed Questions for Investigation																																								22													11
Number of Workgroups Established																																																		5
Number of Comments Established																																																		1
Number of Retail Market Enhancements																																																	1
Regulatory Asset, Cost Recovery, Proposed Return on Equity																		10.90%
Base Return On Equity																		10.40%
Return On Equity Granted For Regional Transmission Organization Participation																		0.50%
Remaining Recovery Period of Regulatory Assets																		5 years
Revenues Lost of Which the Entity is Entitled																							$ 64,000,000
Resource Plan, Proposed Transfer																																																															1,476
Annual Load Growth Rate																																																															1.40%
Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation																	50.00%
Period of Time to File Case																																																															6 months
Regional Enforcement Entities		8

XML

Derivative Instruments

9 Months Ended

Sep. 30, 2013

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 contractual derivative agreements through 2031.

Cash Flow Hedges

FirstEnergy has used cash flow hedges for risk management purposes to manage the volatility related to exposures associated with fluctuating commodity prices and interest rates. The effective portion of gains and losses on a derivative contract is 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 instruments previously designated to be in a cash flow hedging relationship totaled $5 million and $10 million as of September 30, 2013 and December 31, 2012, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $10 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. No forward starting swap agreements accounted for as a cash flow hedge were outstanding as of September 30, 2013 or December 31, 2012. Total unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $61 million and $70 million as of September 30, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months.

Refer to Note 6, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three and nine months ended September 30, 2013 and 2012.

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 September 30, 2013 and December 31, 2012, no fixed-for-floating interest rate swap agreements were outstanding.

Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $48 million and $79 million as of September 30, 2013 and December 31, 2012, respectively. Based on current estimates, approximately $13 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $4 million and $6 million during the three months ended September 30, 2013 and 2012, respectively and $15 million and $17 million during the nine months ended September 30, 2013 and 2012, respectively. In connection with the redemptions of senior notes by FES and taxable bonds by CEI and OE, unamortized gains associated with fixed for floating interest rate swap agreements of $9 million and $17 million were included in the Gain (loss) on debt redemptions in the Consolidated Statements of Income for the three and nine months ended September 30, 2013, respectively. Refer to Note 9, Fair Value Measurements - Long-Term Debt and Other Long-Term Obligations, for additional information regarding FirstEnergy's debt redemptions during the three and nine months ended September 30, 2013.

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 combustion turbine units. Heating oil futures are entered into based on expected consumption of oil and the financial risk in FirstEnergy’s coal transportation contracts. Derivative instruments are not used in quantities greater than forecasted needs.

As of September 30, 2013, FirstEnergy’s net asset position under commodity derivative contracts was $89 million, which related to FES positions. Under these commodity derivative contracts, FES posted $43 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $9 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 September 30, 2013, an adverse change of 10% in commodity prices would decrease net income by approximately $27 million during the next twelve months.

Interest Rate Swaps

In 2013, in connection with certain debt redemptions, FirstEnergy recorded gains of approximately $17 million, including $9 million in the third quarter related to terminated interest rate swaps. In August 2012, FirstEnergy terminated all of the forward starting swap agreements that were executed in the second quarter of 2012, resulting in a net gain, recorded in the third quarter of 2012 as a reduction to interest expense, and cash proceeds of approximately $6 million.

NUGs

As of September 30, 2013, FirstEnergy's net liability position under NUG contracts was $210 million representing contracts held at JCP&L, ME and PN. NUG contracts represent purchased power agreements with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings.

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. 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 with a corresponding regulatory asset. Since the LCAPP contracts are subject to regulatory accounting, changes in their fair value do not impact earnings. On October 11, 2013, the U.S. District Court for the District of New Jersey declared that the LCAPP is preempted by the FPA and unconstitutional. On October 22, 2013, the Superior Court of New Jersey Appellate Division dismissed two consolidated appeals which had been taken from the final order of the NJBPU which accepted and adopted the recommendation of the NJBPU's Agent regarding implementation of the LCAPP law. Dismissal of the consolidated appeals, along with pending matters currently on remand to the NJBPU, was without prejudice subject to the parties exercising their appellate rights in the federal courts. JCP&L continues to maintain a derivative liability with a corresponding regulatory asset on its Consolidated Balance Sheet until the the matter is finally resolved.

FTRs

As of September 30, 2013, FirstEnergy's and FES's net liability position under FTRs was $11 million and FES posted $6 million of collateral. 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 FES and AE Supply are included in other operating expenses as unrealized gains or losses. Unrealized gains or losses on FTRs held by FirstEnergy’s utilities 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.

FirstEnergy records the fair value of derivative instruments on a gross basis. The following table summarizes the fair value and classification of derivative instruments on FirstEnergy’s Consolidated Balance Sheets:

Derivative Assets					Derivative Liabilities
	Fair Value					Fair Value
	September 30, 2013		December 31, 2012			September 30, 2013			December 31, 2012
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	137	$	153	Commodity Contracts	$	(94	)	$	(119	)
FTRs	3		7		FTRs	(11		)	(7		)
	140		160			(105		)	(126		)
					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs	(233		)	(290		)
Deferred Charges and Other Assets - Other					LCAAP	(166		)	(144		)
Commodity Contracts	64		99		Noncurrent Liabilities - Other
FTRs	—		1		Commodity Contracts	(18		)	(36		)
NUGs	23		36		FTRs	(3		)	(2		)
	87		136			(420		)	(472		)
Derivative Assets	$	227	$	296	Derivative Liabilities	$	(525	)	$	(598	)

FirstEnergy enters into contracts with counterparties that allow for net settlement of derivative assets and derivative liabilities. Certain of these contracts contain margining provisions that require the use of collateral to mitigate credit exposure between FirstEnergy and these counterparties. In situations where collateral is pledged to mitigate exposures related to derivative and non-derivative instruments with the same counterparty, FirstEnergy allocates the collateral based on the percentage of the net fair value of derivative instruments to the total fair value of the combined derivative and non-derivative instruments. The following tables summarize the fair value of derivative instruments on FirstEnergy’s Consolidated Balance Sheets and the effect of netting arrangements and collateral on its financial position:

				Amounts Not Offset in Consolidated Balance Sheet
September 30, 2013	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	201		$	(104	)	$	(11	)	$	86
FTRs	3			(3		)	—			—
NUG contracts	23			—			—			23
	$	227		$	(107	)	$	(11	)	$	109
Derivative Liabilities
Commodity contracts	$	(112	)	$	104		$	5		$	(3	)
FTRs	(14		)	3			6			(5		)
NUG contracts	(233		)	—			—			(233		)
LCAPP contracts	(166		)	—			—			(166		)
	$	(525	)	$	107		$	11		$	(407	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2012	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	252		$	(142	)	$	(5	)	$	105
FTRs	8			(8		)	—			—
NUG contracts	36			—			—			36
	$	296		$	(150	)	$	(5	)	$	141
Derivative Liabilities
Commodity contracts	$	(155	)	$	142		$	12		$	(1	)
FTRs	(9		)	8			1			—
NUG contracts	(290		)	—			—			(290		)
LCAPP contracts	(144		)	—			—			(144		)
	$	(598	)	$	150		$	13		$	(435	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of September 30, 2013:

	Purchases	Sales	Net		Units
	(In millions, except for LCAPP)
Power Contracts	32	37	(5	)	MWH
FTRs	59	—	59		MWH
NUGs	11	—	11		MWH
LCAPP	408	—	408		MW
Natural Gas	64	—	64		mmBTU

The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months and nine months ended September 30, 2013 and 2012, are summarized in the following tables:

	Three Months Ended September 30
	Commodity Contracts			FTRs			Interest Rate Swaps		Total
	(In millions)
2013
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	11		$	(8	)	$	—	$	3
Realized Gain (Loss) Reclassified to:
Revenues	$	14		$	6		$	—	$	20
Purchased Power Expense	(17		)	—			—		(17		)
Other Operating Expense	—			(10		)	—		(10		)
Fuel Expense	(2		)	—			—		(2		)
2012
Unrealized Gain (Loss) Recognized in:
Other Operating Expense	$	7		$	(5	)	$	—	$	2
Interest Expense	—			—			20		20
Realized Gain (Loss) Reclassified to:
Revenues	$	46		$	6		$	—	$	52
Purchased Power Expense	(27		)	—			—		(27		)
Other Operating Expense	—			(10		)	—		(10		)
Fuel Expense	3			—			—		3
Interest Expense	—			—			6		6

	Nine Months Ended September 30
	Commodity Contracts			FTRs			Interest Rate Swaps		Total
	(In millions)
2013
Unrealized Loss Recognized in:
Other Operating Expense	$	(5	)	$	(10	)	$	—	$	(15	)
Realized Gain (Loss) Reclassified to:
Revenues	$	29		$	19		$	—	$	48
Purchased Power Expense	(30		)	—			—		(30		)
Other Operating Expense	—			(28		)	—		(28		)
2012
Unrealized Gain Recognized in:
Other Operating Expense	$	72		$	12		$	—	$	84
Realized Gain (Loss) Reclassified to:
Revenues	$	260		$	18		$	—	$	278
Purchased Power Expense	(248		)	—			—		(248		)
Other Operating Expense	—			(51		)	—		(51		)
Fuel Expense	2			—			—		2
Interest Expense	—			—			6		6

The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three and nine months ended September 30, 2013 and 2012, are summarized in the following tables:

	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	7		$	(8	)	$	1		$	—
Realized Gain (Loss) on Derivative Instrument	14			—			(1		)	13
2012
Unrealized Gain (Loss) on Derivative Instrument	$	(50	)	$	3		$	—		$	(47	)
Realized Gain (Loss) on Derivative Instrument	61			—			(1		)	60

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	(13	)	$	(22	)	$	1		$	(34	)
Realized Gain (Loss) on Derivative Instrument	57			—			(1		)	56
2012
Unrealized Loss on Derivative Instrument	$	(183	)	$	(142	)	$	—		$	(325	)
Realized Gain on Derivative Instrument	194			—			7			201

The following tables provide 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 nine months ended September 30, 2013 and 2012:

	Three Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of July 1, 2013	$	(231	)	$	(158	)	$	—		$	(389	)
Additions/Change in value of existing contracts	7			(8		)	1			—
Settled contracts	14			—			(1		)	13
Outstanding net liability as of September 30, 2013	$	(210	)	$	(166	)	$	—		$	(376	)
Outstanding net liability as of July 1, 2012	$	(293	)	$	(145	)	$	—		$	(438	)
Additions/Change in value of existing contracts	(50		)	3			—			(47		)
Settled contracts	61			—			(1		)	60
Outstanding net liability as of September 30, 2012	$	(282	)	$	(142	)	$	(1	)	$	(425	)

	Nine Months Ended September 30
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of January 1, 2013	$	(254	)	$	(144	)	$	—		$	(398	)
Additions/Change in value of existing contracts	(13		)	(22		)	1			(34		)
Settled contracts	57			—			(1		)	56
Outstanding net liability as of September 30, 2013	$	(210	)	$	(166	)	$	—		$	(376	)
Outstanding net liability as of January 1, 2012	$	(293	)	$	—		$	(8	)	$	(301	)
Additions/Change in value of existing contracts	(183		)	(142		)	—			(325		)
Settled contracts	194			—			7			201
Outstanding net liability as of September 30, 2012	$	(282	)	$	(142	)	$	(1	)	$	(425	)

XML

Variable Interest Entities

9 Months Ended

Sep. 30, 2013

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. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary.

VIEs included in FirstEnergy’s consolidated financial statements are: the PNBV capital trust that was created to refinance debt originally issued in connection with sale and leaseback transactions; wholly-owned limited liability companies of the Ohio Companies (as described below); wholly owned limited liability companies of JCP&L created to sell transition bonds to securitize the recovery of JCP&L’s bondable stranded costs and special purpose limited liability companies created to issue environmental control bonds that were used to construct environmental control facilities.

In September 2012, the Ohio Companies formed CEI Funding LLC, OE Funding LLC and TE Funding LLC, respectively, as separate, wholly-owned limited liability SPEs. Each SPE is a bankruptcy-remote, special purpose limited liability company that is restricted to activities necessary to issue phase-in recovery bonds and perform other functions in connection with the bond issuance. Creditors of FirstEnergy and the Ohio Companies have no recourse to any assets or revenues of the SPEs. The phase-in recovery bonds issued by these SPEs are payable only from, and secured by, phase-in recovery property held by the SPEs (i.e. the right to impose, charge and collect irrevocable non-bypassable usage-based charges payable by retail electric customers in the service territories of the Ohio Companies) and the bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. The SPEs are considered VIEs and each one is consolidated into its applicable utility.InJune 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

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 nine months ended September 30, 2013, was primarily due to $6 million of distributions to owners.

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

Mining Operations

FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting.

Trusts

FirstEnergy's consolidated financial statements include PNBV. FirstEnergy used debt and available funds to purchase the notes issued by PNBV for the purchase of lease obligation bonds. Ownership of PNBV includes a 3% equity interest by an unaffiliated third party and a 3% equity interest held by OES Ventures, a wholly owned subsidiary of OE.

PATH-WV

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 that was to be constructed by PATH-WV.

On August 24, 2012, PJM removed the PATH project from its long-range expansion plans. See Note 12, Regulatory Matters, for additional information on the abandonment of PATH.

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 and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy 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, any of these entities.

FirstEnergy has determined that for all but two of these NUG entities, it does not have variable interests in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold variable interests in the remaining two entities; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.

Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $48 million and $65 million during the three months ended September 30, 2013 and 2012, respectively and $139 million and $184 million during the nine months ended September 30, 2013 and 2012, respectively.

Sale and Leaseback

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 arrangements.

During 2012, NG repurchasedlessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for$129 million. In 2012, FG acquired certain equity and other lessor interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $262 millionand in March of 2013, FG acquired the remaining interests for approximately $221 million.

FES, 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 as of September 30, 2013:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,288	$	1,079	$	209
Other FE subsidiaries	762		329		433

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.2 billion.

XML

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Nov. 04, 2013
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	0001031296
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		418,229,541
FES
Entity Information [Line Items]
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	0001407703
Document Type	10-Q
Document Period End Date	Sep. 30, 2013
Amendment Flag	false
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	Q3
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		7

XML

Fair Value Measurements

9 Months Ended

Sep. 30, 2013

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

RECURRING AND NONRECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques 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 FirstEnergy's Risk Policy Committee, are used to measure fair value. A more detailed description of FirstEnergy's valuation process for FTRs, NUGs and LCAPPs 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 periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than 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 10, Derivative Instruments, for additional information regarding FirstEnergy's FTRs.

NUG contracts represent purchase 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 and adjusted periodically using a mark-to-model methodology, 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 ICE 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 and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable input into the model is forecasted regional capacity prices. Pricing for the LCAPP contracts is a combination of PJM RPM capacity auction prices and internal models using historical trends and market data for the remaining years under contract. Capacity prices beyond the 2016/2017 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. See Note 10, Derivative Instruments for additional information regarding LCAAP contracts.

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 September 30, 2013, from those used as of December 31, 2012. 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 nine months ended September 30, 2013. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

FirstEnergy
Recurring Fair Value Measurements	September 30, 2013												December 31, 2012
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,299		$	—		$	1,299		$	—		$	1,259		$	—		$	1,259
Derivative assets - commodity contracts	4			197			—			201			—			252			—			252
Derivative assets - FTRs	—			—			3			3			—			—			8			8
Derivative assets - NUG contracts(1)	—			—			23			23			—			—			36			36
Equity securities(2)	461			—			—			461			310			—			—			310
Foreign government debt securities	—			101			—			101			—			126			—			126
U.S. government debt securities	—			171			—			171			—			179			—			179
U.S. state debt securities	—			226			—			226			—			299			—			299
Other(3)	160			157			—			317			126			227			—			353
Total assets	$	625		$	2,151		$	26		$	2,802		$	436		$	2,342		$	44		$	2,822
Liabilities
Derivative liabilities - commodity contracts	$	(5	)	$	(107	)	$	—		$	(112	)	$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—			—			(14		)	(14		)	—			—			(9		)	(9		)
Derivative liabilities - NUG contracts(1)	—			—			(233		)	(233		)	—			—			(290		)	(290		)
Derivative liabilities - LCAPP contracts(1)	—			—			(166		)	(166		)	—			—			(144		)	(144		)
Total liabilities	$	(5	)	$	(107	)	$	(413	)	$	(525	)	$	(3	)	$	(151	)	$	(443	)	$	(597	)
Net assets (liabilities)(4)	$	620		$	2,044		$	(387	)	$	2,277		$	433		$	2,191		$	(399	)	$	2,225

⁽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 or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽⁴⁾  Excludes $13 million and $110 million as of September 30, 2013 and December 31, 2012, 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 and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended September 30, 2013 and December 31, 2012:

	NUG Contracts(1)									LCAPP Contracts(1)								FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2012 Balance	$	57		$	(349	)	$	(292	)	$	—	$	—		$	—		$	1		$	(23	)	$	(22	)
Unrealized gain (loss)	(20		)	(180		)	(200		)	—		1			1			6			(6		)	—
Purchases	—			—			—			—		(145		)	(145		)	13			(10		)	3
Settlements	(1		)	239			238			—		—			—			(12		)	30			18
December 31, 2012 Balance	$	36		$	(290	)	$	(254	)	$	—	$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
Unrealized gain (loss)	(6		)	(6		)	(12		)	—		(22		)	(22		)	1			2			3
Purchases	—			—			—			—		—			—			5			(15		)	(10		)
Settlements	(7		)	63			56			—		—			—			(11		)	8			(3		)
September 30, 2013 Balance	$	23		$	(233	)	$	(210	)	$	—	$	(166	)	$	(166	)	$	3		$	(14	)	$	(11	)

⁽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 September 30, 2013:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(11	)	Model	RTO auction clearing prices	($5.60) to $5.40	$0.62	Dollars/MWH
NUG Contracts	$	(210	)	Model	Generation Electricity regional prices	600 to 5,864,000 $41.40 to $57.30	1,421,000 $49.40	MWH Dollars/MWH
LCAPP Contracts	$	(166	)	Model	Regional capacity prices	$158.60 to $187.60	$171.20	Dollars/MW-Day

FES
Recurring Fair Value Measurements	September 30, 2013												December 31, 2012
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	742		$	—		$	742		$	—		$	703		$	—		$	703
Derivative assets - commodity contracts	4			197			—			201			—			252			—			252
Derivative assets - FTRs	—			—			2			2			—			—			6			6
Equity securities(1)	338			—			—			338			294			—			—			294
Foreign government debt securities	—			58			—			58			—			61			—			61
U.S. government debt securities	—			26			—			26			—			27			—			27
Other(2)	—			94			—			94			—			104			—			104
Total assets	$	342		$	1,117		$	2		$	1,461		$	294		$	1,147		$	6		$	1,447
Liabilities
Derivative liabilities - commodity contracts	$	(5	)	$	(107	)	$	—		$	(112	)	$	(3	)	$	(151	)	$	—		$	(154	)
Derivative liabilities - FTRs	—			—			(13		)	(13		)	—			—			(6		)	(6		)
Total liabilities	$	(5	)	$	(107	)	$	(13	)	$	(125	)	$	(3	)	$	(151	)	$	(6	)	$	(160	)
Net assets (liabilities)(3)	$	337		$	1,010		$	(11	)	$	1,336		$	291		$	996		$	—		$	1,287

⁽¹⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽³⁾  Excludes $12 million and $94 million as of September 30, 2013 and December 31, 2012, 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 September 30, 2013 and December 31, 2012:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2012 Balance	$	1		$	(7	)	$	(6	)
Unrealized gain (loss)	4			(4		)	—
Purchases	9			(7		)	2
Settlements	(8		)	12			4
December 31, 2012 Balance	$	6		$	(6	)	$	—
Unrealized loss	(1		)	(1		)	(2		)
Purchases	4			(12		)	(8		)
Settlements	(7		)	6			(1		)
September 30, 2013 Balance	$	2		$	(13	)	$	(11	)

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 September 30, 2013:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(11	)	Model	RTO auction clearing prices	($5.60) to $5.40	$0.40	Dollars/MWH

INVESTMENTS

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

At the end of each reporting period, FirstEnergy evaluates its investments for OTTI. Investments classified as AFS securities are evaluated to determine whether a decline in fair value below the cost basis is other than temporary. FirstEnergy first considers its intent and ability to hold an equity security until recovery and then considers, among other factors, the duration and the extent to which the security's fair value has been less than its cost and the near-term financial prospects of the security issuer when evaluating an investment for impairment. For debt securities, FirstEnergy considers its intent to hold the securities, the likelihood that it will be required to sell the securities before recovery of its cost basis and the likelihood of recovery of the securities' entire amortized cost basis. If the decline in fair value is determined to be other than temporary, the cost basis of the securities is written down to fair value.

Unrealized gains and losses on AFS securities are recognized in AOCI. However, unrealized losses held in the NDTs of FES are recognized in earnings since the trust arrangements, as they are currently defined, do not meet the required ability and intent to hold criteria in consideration of OTTI.

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, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.

AFS Securities

FirstEnergy holds debt and equity securities within its NDT, nuclear fuel disposal and NUG trusts. These trust investments are considered AFS securities, recognized at fair market value. FirstEnergy has no securities held for trading purposes.

The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of September 30, 2013 and December 31, 2012:

	September 30, 2013(1)						December 31, 2012(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,825	$	21	$	1,846	$	1,827	$	34	$	1,861
FES	868		9		877		778		14		792
Equity securities
FirstEnergy	$	433	$	28	$	461	$	293	$	16	$	309
FES	317		21		338		281		13		294

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $106 million; FES - $55 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $326 million; FES - $196 million.

Proceeds from the sale of investments in AFS securities, realized gains and losses on those sales, OTTI and interest and dividend income for the three months and nine months ended September 30, 2013 and 2012 were as follows:

Three Months Ended
September 30, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	368	$	9	$	(15	)	$	(21	)	$	26
FES	164		5		(3		)	(21		)	16
September 30, 2012	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	1,751	$	81	$	(30	)	$	(2	)	$	18
FES	1,059		60		(21		)	(2		)	10

Nine Months Ended
September 30, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	1,545	$	49	$	(31	)	$	(74	)	$	74
FES	650		38		(14		)	(66		)	44
September 30, 2012	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	2,133	$	118	$	(58	)	$	(9	)	$	51
FES	1,167		85		(40		)	(8		)	27

Held-To-Maturity Securities

The following table provides the amortized cost basis, unrealized gains (there were no unrealized losses) and approximate fair values of investments in held-to-maturity securities as of September 30, 2013 and December 31, 2012:

	September 30, 2013						December 31, 2012
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	46	$	1	$	47	$	54	$	30	$	84

Investments in emission allowances, employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $646 million as of September 30, 2013, and $644 million as of December 31, 2012, 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 as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate 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:

	September 30, 2013				December 31, 2012
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	17,007	$	17,721	$	16,957	$	19,460
FES	3,015		3,082		4,194		4,524

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. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of September 30, 2013 and December 31, 2012.

During the first quarter of 2013, FE issued in aggregate $1.5 billion of senior unsecured notes in two series: $650 million of 2.75% senior notes due March 15, 2018 and $850 million of 4.25% senior notes due March 15, 2023. The stated interest rates are subject to adjustments based upon changes in the credit ratings of FirstEnergy but will not decrease below the issued rates. The proceeds were used to repay short-term borrowings and to invest in the money pool for FES and AE Supply's use in funding a portion of their concurrent tender offers.

Also during the first quarter of 2013, pursuant to tender offers launched in February 2013, FES and AE Supply repurchased $369 million and $294 million, respectively, of outstanding senior notes with interest rates ranging from 5.75% to 6.8%. The $369 million of FES repurchases consisted of original maturities of $252 million due 2021 and $117 million due 2039. The $294 million of AE Supply repurchases consisted of original maturities of $194 million due 2019 and $100 million due 2039. FES and AE Supply paid $67 million and $43 million, respectively, in tender premiums to repurchase the tendered senior notes. FirstEnergy recorded a loss on debt redemption of $119 million (FES - $71 million), including such premiums and other related expenses. The tender premiums paid are included in cash flows from financing activities in the Consolidated Statement of Cash Flows.

In March 2013, ME issued $300 million of 3.50% senior unsecured notes due March 15, 2023. Proceeds from this offering were used to repay $150 million of ME 4.95% senior unsecured notes that matured in March 2013 and short-term borrowings.

On April 15, 2013, FES redeemed $400 million of its 4.80% senior notes due 2015 and recorded a loss on debt redemption of $32 million including $31 million of make-whole premiums paid. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

On June 3, 2013, FG exercised a mandatory put option and repurchased approximately $235 million of PCRBs due 2023, which FG is currently holding for remarketing subject to future market and other conditions.

As discussed in Note 8, Variable Interest Entities, in June 2013, the SPEs formed by the Ohio Companies issued $445 million of phase-in recovery bonds with a weighted average coupon of 2.48% to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds were sold to a trust that concurrently sold a like aggregate amount of its pass through trust certificates to public investors. The proceeds were primarily used to redeem $410 million in existing taxable bonds of the Ohio Companies with a weighted average coupon of 5.71% and pay $30 million of make-whole premiums associated with such redemptions which will also be recovered. The $410 million redemption consisted of original maturities of $225 million due 2013, $150 million due 2015 and $35 million due 2020. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows.

During August, the Ohio Companies redeemed an additional $660 million of long-term debt with interest rates ranging from 5.65% to 7.25% and paid approximately $120 million of make-whole premiums which were deferred as a regulatory asset and will be amortized over the original life of the redeemed debt. The make-whole premiums paid are included in cash flows from operating activities in the Consolidated Statement of Cash Flows. Additionally, during August, JCP&L issued $500 million of 4.7% unsecured notes due April 2024 and used the proceeds to pay down a portion of its short-term debt obligations.

On May 8, 2013, FE, FES, and FE's other borrowing subsidiaries entered into extensions and amendments to the three existing multi-year syndicated revolving credit facilities. Each facility was extended until May 2018, unless the lenders agree, at the request of the applicable borrowers, to an additional one-year extension. The FE Facility was amended to increase the lending banks' commitments under the facility by $500 million to a total of $2.5 billion and to increase the individual borrower sub-limits for FE by $500 million to a total of $2.5 billion and for JCP&L by $175 million to a total of $600 million.

On October 31, 2013, FE amended its existing $2.5 billion multi-year syndicated revolving credit facility to exclude certain after-tax, non-cash write-downs and non-cash charges of approximately $1.4 billion from the debt to total capitalization ratio calculations incurred through September 30, 2013. Additionally, the amendment provides for a future allowance of approximately $1.35 billion for after-tax non-cash write-downs and non-cash charges over the remaining life of the facility. Similarly, the FES/AE Supply $2.5 billion revolving credit facility was also amended to exclude certain similar after-tax, non-cash write-downs and non-cash charges of $785.7 million incurred through September 30, 2013 from the debt to total capitalization ratio calculations. The effect of these amendments will apply to the compliance reports for the period ended September 30, 2013, which are due November 29, 2013.

XML

Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Derivative Assets
Fair Value	$ 227	$ 296
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(107)	(150)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(11)	(5)
Net Fair Value	109	141
Derivative Liabilities
Fair Value	(525)	(598)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	107	150
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	11	13
Net Fair Value	(407)	(435)
Power Contracts
Derivative Assets
Fair Value	201	252
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(104)	(142)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(11)	(5)
Net Fair Value	86	105
Derivative Liabilities
Fair Value	(112)	(155)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	104	142
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	5	12
Net Fair Value	(3)	(1)
FTRs
Derivative Assets
Fair Value	3	8
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(3)	(8)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
Derivative Liabilities
Fair Value	(14)	(9)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	3	8
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	6	1
Net Fair Value	(5)	0
NUGs
Derivative Assets
Fair Value	23	36
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	23	36
Derivative Liabilities
Fair Value	(233)	(290)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	(233)	(290)
LCAPP
Derivative Liabilities
Fair Value	(166)	(144)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	0	0
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	$ (166)	$ (144)

XML

Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2013	Dec. 31, 2012
Fair value of commodity derivatives
Derivative Assets	$ 227	$ 296
Derivative Liabilities	(525)	(598)
Current Assets
Fair value of commodity derivatives
Derivative Assets	140	160
Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	87	136
Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(105)	(126)
Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(420)	(472)
Power Contracts | Current Assets
Fair value of commodity derivatives
Derivative Assets	137	153
Power Contracts | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	64	99
Power Contracts | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(94)	(119)
Power Contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(18)	(36)
FTRs | Current Assets
Fair value of commodity derivatives
Derivative Assets	3	7
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	0	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(11)	(7)
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(3)	(2)
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	23	36
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(233)	(290)
LCAPP | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	$ (166)	$ (144)