10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended March 31, 2014

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 Exchange 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 APRIL 30, 2014
FirstEnergy Corp., $0.10 par value	419,908,686
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 additional channels 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, which may include the following:

• The speed and nature of increased competition in the electric utility industry, in general, and the retail sales market in particular.

• 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.

• The accomplishment of our regulatory and operational goals in connection with our transmission plan and planned distribution rate cases and the effectiveness of our repositioning strategy.

• 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 such as the polar vortex or other significant weather events.

• 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 their availability and 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, but not limited to, possible GHG emission, water discharge, water intake and CCR regulations, the potential impacts of CSAPR, 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 and the steam generator replacement 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, our announced dividend reduction and our proposed capital raising and debt reduction initiatives.

• 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.

• Changing market conditions that could affect the measurement of certain 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 plans, 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.

• The impact of any changes in tax laws or regulations or adverse tax audit results or rulings.

• 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 and Comprehensive Income	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	55
FirstEnergy Corp. Management's Discussion and Analysis of Financial Condition and Results of Operations	55
Management’s Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	96
Item 3. Quantitative and Qualitative Disclosures About Market Risk	98
Item 4. Controls and Procedures	99
Part II. Other Information
Item 1. Legal Proceedings	99
Item 1A. Risk Factors	99
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	99
Item 3. Defaults Upon Senior Securities	99
Item 4. Mine Safety Disclosures	99
Item 5. Other Information	99
Item 6. Exhibits	100

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. As of January 1, 2014, AE merged with and into FirstEnergy Corp.
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply
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
FELHC	FirstEnergy License Holding Company, Inc.
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 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
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 FE 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
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
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
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
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
Anker WV	Anker West Virginia Mining Company, Inc.
Anker Coal	Anker Coal Group, Inc.
AOCI	Accumulated Other Comprehensive Income
Apple®	Apple®, iPad® and iPhone® are registered trademarks of Apple Inc.
ARO	Asset Retirement Obligation
ARR	Auction Revenue Right

ii

GLOSSARY OF TERMS, Continued
ASLB	Atomic Safety and Licensing Board
BGS	Basic Generation Service
BRA	PJM RPM Base Residual Auction
CAA	Clean Air Act
CAIR	Clean Air Interstate Rule
CBA	Collective Bargaining Agreement
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
Dayton	The Dayton Power and Light Company
DCR	Delivery Capital Recovery
DSP	Default Service Plan
Duke	Duke Energy Ohio, a subsidiary of Duke Energy Corporation
EDC	Electric Distribution Company
EDU	Electric Distribution Utility
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
Facebook®	Facebook is a registered trademark of Facebook, Inc.
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.
kV	Kilovolt
KWH	Kilowatt-hour
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

iii

GLOSSARY OF TERMS, Continued
Moody’s	Moody’s Investors Service, Inc.
MOPR	Minimum Offer Price Rule
MVP	Multi-value Project
MW	Megawatt
MWH	Megawatt-hour
NDT	Nuclear Decommissioning Trust
NERC	North American Electric Reliability Corporation
NGO	Non-Governmental Organization
NITS	Network Integration Transmission System
NJBPU	New Jersey Board of Public Utilities
NMB	Non-Market Based
NNSR	Non-Attainment New Source Review
NOV	Notice of Violation
NOx	Nitrogen Oxide
NPDES	National Pollutant Discharge Elimination System
NRC	Nuclear Regulatory Commission
NSR	New Source Review
NUG	Non-Utility Generation
NYISO	New York Independent System Operator
NYPSC	New York State Public Service Commission
OCA	Office of Consumer Advocate
OCC	Ohio Consumers' Counsel
OPEB	Other Post-Employment Benefits
OTTI	Other Than Temporary Impairments
PA DEP	Pennsylvania Department of Environmental Protection
PCRB	Pollution Control Revenue Bond
Pennsylvania Industrials	ME Industrial Users Group and PN Industrial Customer Alliance
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
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

iv

GLOSSARY OF TERMS, Continued
SERTP	Southeastern Regional Transmission Planning
SIP	State Implementation Plan(s) Under the Clean Air Act
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
Twitter®	Twitter is a registered trademark of Twitter, Inc.
U.S. Court of Appeals for the D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
UWUA	Utility Workers Union of America
VIE	Variable Interest Entity
VSCC	Virginia State Corporation Commission
WVCAG	West Virginia Citizen Action Group
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 March 31
(In millions, except per share amounts)	2014			2013
REVENUES:
Electric utilities	$	2,739		$	2,388
Unregulated businesses	1,450			1,335
Total revenues*	4,189			3,723
OPERATING EXPENSES:
Fuel	617			630
Purchased power	1,455			946
Other operating expenses	1,182			882
Provision for depreciation	294			293
Amortization (deferral) of regulatory assets, net	(28		)	59
General taxes	271			265
Total operating expenses	3,791			3,075
OPERATING INCOME	398			648
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(7		)	(117		)
Investment income	22			18
Interest expense	(265		)	(258		)
Capitalized interest	22			15
Total other expense	(228		)	(342		)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	170			306
INCOME TAXES	48			114
INCOME FROM CONTINUING OPERATIONS	122			192
Discontinued operations (net of income taxes of $69 and $2, respectively) (Note 13)	86			4
NET INCOME	$	208		$	196
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations	$	0.29		$	0.46
Basic - Discontinued Operations (Note 13)	0.21			0.01
Basic - Net Earnings per Basic Share	$	0.50		$	0.47
Diluted - Continuing Operations	$	0.29		$	0.46
Diluted - Discontinued Operations (Note 13)	0.20			0.01
Diluted - Net Earnings per Diluted Share	$	0.49		$	0.47
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	419			418
Diluted	420			419
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK**	$	0.72		$	0.55

* Includes excise tax collections of $117 million and $122 million in the three months ended March 31, 2014 and 2013, respectively.

** The three months ended March 31, 2014 includes a dividend declared of $0.36 per share on January 21, 2014, paid on March 1, 2014 and a dividend declared of $0.36 per share on March 18, 2014, payable June 1, 2014. The three months ended March 31, 2013 includes a dividend declared of $0.55 per share on March 19, 2013, paid on June 1, 2013.

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

1

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31
(In millions)	2014			2013
NET INCOME	$	208		$	196
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(42		)	(46		)
Amortized losses on derivative hedges	—			1
Change in unrealized gain on available-for-sale securities	21			5
Other comprehensive loss	(21		)	(40		)
Income tax benefits on other comprehensive loss	(8		)	(16		)
Other comprehensive loss, net of tax	(13		)	(24		)
COMPREHENSIVE INCOME	$	195		$	172

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

2

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	March 31, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	109	$	218
Receivables-
Customers, net of allowance for uncollectible accounts of $55 in 2014 and $52 in 2013	1,869		1,720
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	218		198
Materials and supplies, at average cost	740		752
Prepaid taxes	240		226
Derivatives	247		166
Accumulated deferred income taxes	375		366
Collateral	580		155
Other	199		212
	4,577		4,013
PROPERTY, PLANT AND EQUIPMENT:
In service	44,782		44,228
Less — Accumulated provision for depreciation	13,555		13,280
	31,227		30,948
Construction work in progress	2,661		2,304
	33,888		33,252
INVESTMENTS:
Nuclear plant decommissioning trusts	2,263		2,201
Other	898		903
	3,161		3,104
ASSETS HELD FOR SALE	—		235
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418		6,418
Regulatory assets	1,798		1,854
Other	1,386		1,548
	9,602		9,820
	$	51,228	$	50,424
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,416	$	1,415
Short-term borrowings	3,085		3,404
Accounts payable	1,455		1,250
Accrued taxes	527		485
Accrued compensation and benefits	232		351
Derivatives	159		111
Other	863		621
	7,737		7,637
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 419,837,287 shares and 418,628,559 shares outstanding as of March 31, 2014 and December 31, 2013, respectively	42		42
Other paid-in capital	9,793		9,776
Accumulated other comprehensive income	271		284
Retained earnings	2,496		2,590
Total common stockholders’ equity	12,602		12,692
Noncontrolling interest	3		3
Total equity	12,605		12,695
Long-term debt and other long-term obligations	16,804		15,831
	29,409		28,526
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	7,028		6,968
Retirement benefits	2,713		2,689
Asset retirement obligations	1,704		1,678
Deferred gain on sale and leaseback transaction	850		858
Adverse power contract liability	255		290
Other	1,532		1,778
	14,082		14,261
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	51,228	$	50,424

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

3

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31
(In millions)	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	208		$	196
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	294			293
Amortization (deferral) of regulatory assets, net	(28		)	59
Nuclear fuel amortization	48			53
Deferred purchased power and other costs	(34		)	(25		)
Deferred income taxes and investment tax credits, net	181			134
Deferred rents and lease market valuation liability	33			37
Retirement benefits	(20		)	(64		)
Commodity derivative transactions, net (Note 8)	(17		)	4
Loss on debt redemptions	7			117
Income from discontinued operations (Note 13)	(86		)	(4		)
Changes in current assets and liabilities-
Receivables	(168		)	(34		)
Materials and supplies	12			26
Prepayments and other current assets	(29		)	(159		)
Accounts payable	200			(378		)
Accrued taxes	(242		)	(128		)
Accrued interest	46			53
Accrued compensation and benefits	(118		)	(91		)
Cash collateral, net	(461		)	(1		)
Other	82			(38		)
Net cash (used for) provided from operating activities	(92		)	50
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	1,467			1,800
Short-term borrowings, net	—			181
Redemptions and Repayments-
Long-term debt	(489		)	(846		)
Short-term borrowings, net	(319		)	—
Tender premiums paid on debt redemptions	—			(110		)
Common stock dividend payments	(151		)	(230		)
Other	(10		)	(23		)
Net cash provided from financing activities	498			772
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(821		)	(826		)
Nuclear fuel	(55		)	(27		)
Proceeds from asset sales	394			—
Sales of investment securities held in trusts	621			539
Purchases of investment securities held in trusts	(646		)	(565		)
Cash investments	28			6
Asset removal costs	(39		)	(53		)
Other	3			(1		)
Net cash used for investing activities	(515		)	(927		)
Net change in cash and cash equivalents	(109		)	(105		)
Cash and cash equivalents at beginning of period	218			172
Cash and cash equivalents at end of period	$	109		$	67

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

4

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

	Three Months Ended March 31
(In millions)	2014			2013
STATEMENTS OF INCOME
REVENUES:
Electric sales to non-affiliates	$	1,440		$	1,334
Electric sales to affiliates	349			156
Other	40			34
Total revenues	1,829			1,524
OPERATING EXPENSES:
Fuel	319			300
Purchased power from affiliates	64			132
Purchased power from non-affiliates	1,029			506
Other operating expenses	452			379
Provision for depreciation	74			75
General taxes	39			37
Total operating expenses	1,977			1,429
OPERATING INCOME (LOSS)	(148		)	95
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(5		)	(71		)
Investment income	20			17
Miscellaneous income	—			2
Interest expense — affiliates	(2		)	(1		)
Interest expense — other	(36		)	(52		)
Capitalized interest	12			9
Total other expense	(11		)	(96		)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(159		)	(1		)
INCOME TAX BENEFITS	(56		)	—
LOSS FROM CONTINUING OPERATIONS	(103		)	(1		)
Discontinued operations (net of income taxes of $70 and $2, respectively) (Note 13)	116			3
NET INCOME	$	13		$	2
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	13		$	2
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(5		)	(6		)
Amortized loss on derivative hedges	(2		)	(1		)
Change in unrealized gain on available-for-sale securities	19			5
Other comprehensive income (loss)	12			(2		)
Income taxes (benefits) on other comprehensive income (loss)	4			(1		)
Other comprehensive income (loss), net of tax	8			(1		)
COMPREHENSIVE INCOME	$	21		$	1

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

5

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	March 31, 2014		December 31, 2013
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers, net of allowance for uncollectible accounts of $13 in 2014 and $11 in 2013	583		539
Affiliated companies	369		1,036
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	151		81
Notes receivable from affiliated companies	215		—
Materials and supplies	427		448
Derivatives	244		165
Collateral	544		136
Prepayments and other	179		109
	2,714		2,516
PROPERTY, PLANT AND EQUIPMENT:
In service	12,796		12,472
Less — Accumulated provision for depreciation	4,857		4,755
	7,939		7,717
Construction work in progress	1,356		1,308
	9,295		9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	1,323		1,276
Other	11		11
	1,334		1,287
ASSETS HELD FOR SALE	—		122
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	91		95
Goodwill	23		23
Property taxes	30		41
Unamortized sale and leaseback costs	197		168
Derivatives	65		53
Other	150		172
	556		552
	$	13,899	$	13,502
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	465	$	892
Short-term borrowings-
Affiliated companies	—		431
Other	555		4
Accounts payable-
Affiliated companies	327		765
Other	295		290
Accrued taxes	97		66
Derivatives	159		110
Other	214		197
	2,112		2,755
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of March 31, 2014 and December 31, 2013	3,580		3,080
Accumulated other comprehensive income	62		54
Retained earnings	2,191		2,178
Total common stockholder's equity	5,833		5,312
Long-term debt and other long-term obligations	2,551		2,130
	8,384		7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	850		858
Accumulated deferred income taxes	810		741
Asset retirement obligations	1,029		1,015
Retirement benefits	189		185
Derivatives	36		14
Other	489		492
	3,403		3,305
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	13,899	$	13,502

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

6

FIRSTENERGY SOLUTIONS CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	Three Months Ended March 31
(In millions)	2014			2013
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	13		$	2
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	74			75
Nuclear fuel amortization	48			53
Deferred rents and lease market valuation liability	21			21
Deferred income taxes and investment tax credits, net	48			56
Commodity derivative transactions, net (Note 8)	(17		)	3
Loss on debt redemptions	5			71
Income from discontinued operations (Note 13)	(116		)	(3		)
Changes in current assets and liabilities-
Receivables	553			(177		)
Materials and supplies	21			28
Prepayments and other current assets	(48		)	(55		)
Accounts payable	(430		)	(185		)
Accrued taxes	(49		)	(80		)
Accrued compensation and benefits	(19		)	(16		)
Cash collateral, net	(420		)	38
Other	4			(26		)
Net cash used for operating activities	(312		)	(195		)
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	417			—
Short-term borrowings, net	120			702
Equity contribution from parent	500			—
Redemptions and repayments-
Long-term debt	(445		)	(476		)
Tender premiums paid on debt redemptions	—			(67		)
Other	(4		)	(1		)
Net cash provided from financing activities	588			158
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(298		)	(217		)
Nuclear fuel	(55		)	(27		)
Proceeds from asset sales	307			17
Sales of investment securities held in trusts	423			252
Purchases of investment securities held in trusts	(438		)	(265		)
Loans to affiliated companies, net	(215		)	276
Other	—			1
Net cash (used for) provided from investing activities	(276		)	37
Net change in cash and cash equivalents	—			—
Cash and cash equivalents at beginning of period	2			3
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	Earnings Per Share of Common Stock	9
3	Pensions and Other Postemployment Benefits	11
4	Accumulated Other Comprehensive Income	11
5	Income Taxes	14
6	Variable Interest Entities	14
7	Fair Value Measurements	16
8	Derivative Instruments	22
9	Regulatory Matters	27
10	Commitments, Guarantees and Contingencies	37
11	Supplemental Guarantor Information	45
12	Segment Information	52
13	Discontinued Operations	54

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.

FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP and FET. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., and GPU Nuclear, Inc.

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, 2013.

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 6, 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. These reclassifications include, but are not limited to, the classification of discontinued operations associated with our sale of hydro assets discussed in additional detail in Note 13, Discontinued Operations.

New Accounting Pronouncements

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

2. EARNINGS PER SHARE 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.

9

The following table reconciles basic and diluted earnings per share of common stock:

(In millions, except per share amounts)	Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2014		2013
Income from continuing operations	$	122	$	192
Discontinued operations (Note 13)	86		4
Net income	$	208	$	196
Weighted average number of basic shares outstanding	419		418
Assumed exercise of dilutive stock options and awards(1)	1		1
Weighted average number of diluted shares outstanding	420		419
Earnings per share:
Basic earnings per share:
Income from continuing operations	$	0.29	$	0.46
Discontinued operations (Note 13)	0.21		0.01
Net earnings per basic share	$	0.50	$	0.47
Diluted earnings per share:
Income from continuing operations	$	0.29	$	0.46
Discontinued operations (Note 13)	0.20		0.01
Net earnings per diluted share	$	0.49	$	0.47

⁽¹⁾  For the three months ended March 31, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the three months ended March 31, 2013.

10

3. PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2014			2013			2014			2013
	(In millions)
Service costs	$	42		$	49		$	2		$	3
Interest costs	100			93			10			9
Expected return on plan assets	(115		)	(125		)	(8		)	(8		)
Amortization of prior service costs (credits)	2			3			(44		)	(50		)
Net periodic costs (credits)	$	29		$	20		$	(40	)	$	(46	)

FES' share of the net periodic pensions and OPEB costs (credits) were as follows:

	Pensions				OPEB
For the Three Months Ended March 31,	2014		2013		2014			2013
	(In millions)
Net Periodic Costs	$	4	$	5	$	(5	)	$	(5	)

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 March 31,	2014		2013		2014			2013
	(In millions)
FirstEnergy	$	21	$	11	$	(27	)	$	(30	)
FES	4		3		(4		)	(3		)

11

4. ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, in the three months ended March 31, 2014 and 2013, 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 January 1, 2014	$	(36	)	$	9		$	311		$	284
Other comprehensive income before reclassifications	—			22			—			22
Amounts reclassified from AOCI	—			(9		)	(26		)	(35		)
Net other comprehensive income (loss)	—			13			(26		)	(13		)
AOCI Balance as of March 31, 2014	$	(36	)	$	22		$	285		$	271
AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
Other comprehensive income before reclassifications	—			15			—			15
Amounts reclassified from AOCI	1			(12		)	(28		)	(39		)
Net other comprehensive income (loss)	1			3			(28		)	(24		)
AOCI Balance as of March 31, 2013	$	(37	)	$	18		$	380		$	361
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, 2014	$	(1	)	$	8		$	47		$	54
Other comprehensive income before reclassifications	—			21			—			21
Amounts reclassified from AOCI	(1		)	(9		)	(3		)	(13		)
Net other comprehensive income (loss)	(1		)	12			(3		)	8
AOCI Balance as of March 31, 2014	$	(2	)	$	20		$	44		$	62
AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
Other comprehensive income before reclassifications	—			14			—			14
Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
Net other comprehensive income (loss)	(1		)	4			(4		)	(1		)
AOCI Balance as of March 31, 2013	$	2		$	17		$	52		$	71

12

The following amounts were reclassified from AOCI in the three months ended March 31, 2014 and 2013:

FE	Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(2	)	$	(3	)	Other operating expenses
Long-term debt	2			4			Interest expense ($2) in 2014 and Interest expense ($2) and loss on debt redemptions ($2) in 2013
	—			1			Total before taxes
	—			—			Income taxes
	$	—		$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(14	)	$	(19	)	Investment income
	5			7			Income taxes
	$	(9	)	$	(12	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(42	)	$	(47	)	(a)
	16			19			Income taxes
	$	(26	)	$	(28	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
FES	Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(2	)	$	(3	)	Other operating expenses
Long-term debt	—			2			Loss on debt redemptions
	(2		)	(1		)	Total before taxes
	1			—			Income tax benefits
	$	(1	)	$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(14	)	$	(16	)	Investment income
	5			6			Income tax benefits
	$	(9	)	$	(10	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			1			Income tax benefits
	$	(3	)	$	(4	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

13

5. INCOME TAXES

FirstEnergy’s and FES’s interim effective tax rates reflect the estimated annual effective tax rates for 2014 and 2013, adjusted for tax expense associated with certain discrete items.

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Significant judgment is required in determining FirstEnergy's income taxes and in evaluating tax positions taken or expected to be taken on its tax returns. There were no material changes to FirstEnergy's unrecognized income tax benefits during the first three months of 2014 or 2013.

As of March 31, 2014, it is reasonably possible that approximately $35 million of unrecognized income tax benefits, including interest, may be resolved within the next twelve months as a result of the statute of limitations expiring, all of which 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 three months of 2014 and 2013, there were no material changes to the amount of accrued interest. The net amount of interest accrued as of March 31, 2014 and December 31, 2013 was approximately $9 million.

FirstEnergy’s effective tax rate from continuing operations for the three months ended March 31, 2014 and 2013 was 28.2% and 37.2%, respectively. The decrease in the effective tax rate is primarily due to an increase in AFUDC equity flow through, changes in state apportionment factors and the elimination of certain future tax liabilities associated with basis differences.

FES’s effective tax rate from continuing operations for the three months ended March 31, 2014 and 2013 was 35.2% and 24.8%, respectively. The increase in the effective tax rate is primarily related to the impact of permanent tax adjustments on estimated annual pretax earnings from continuing operations.

In April 2014, the Internal Revenue Service completed its examination of FE's 2011 and 2012 federal income tax returns and issued Revenue Agent Reports for these years.

6. 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 trusts that were 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.

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.

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.

Ohio Securitization

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.

14

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 FirstEnergy 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 9, 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 at its Regulated Distribution segment 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 20 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 at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $61 million and $49 million during the three months ended March 31, 2014 and 2013, 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.

In March of 2013, FG acquired the remaining interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $221 million. Also during 2013, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for $23 million and in February 2014, NG purchased additional lessor equity interests for approximately $94 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 March 31, 2014:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,293	$	1,081	$	212
Other FE subsidiaries	716		495		221

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.1 billion.

15

7. 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 and NUGs are as follows:

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are 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 8, 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.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2014, from those used as of December 31, 2013. 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.

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Transfers between levels are recognized at the end of the reporting period. There were no transfers between levels during the three months ended March 31, 2014. 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	March 31, 2014												December 31, 2013
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,168		$	—		$	1,168		$	—		$	1,365		$	—		$	1,365
Derivative assets - commodity contracts	11			293			—			304			7			208			—			215
Derivative assets - FTRs	—			—			7			7			—			—			4			4
Derivative assets - NUG contracts(1)	—			—			3			3			—			—			20			20
Equity securities(2)	464			—			—			464			317			—			—			317
Foreign government debt securities	—			94			—			94			—			109			—			109
U.S. government debt securities	—			167			—			167			—			165			—			165
U.S. state debt securities	—			237			—			237			—			228			—			228
Other(3)	54			379			—			433			187			255			—			442
Total assets	$	529		$	2,338		$	10		$	2,877		$	511		$	2,330		$	24		$	2,865
Liabilities
Derivative liabilities - commodity contracts	$	(8	)	$	(179	)	$	—		$	(187	)	$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—			—			(8		)	(8		)	—			—			(12		)	(12		)
Derivative liabilities - NUG contracts(1)	—			—			(188		)	(188		)	—			—			(222		)	(222		)
Total liabilities	$	(8	)	$	(179	)	$	(196	)	$	(383	)	$	(13	)	$	(100	)	$	(234	)	$	(347	)
Net assets (liabilities)(4)	$	521		$	2,159		$	(186	)	$	2,494		$	498		$	2,230		$	(210	)	$	2,518

⁽¹⁾  NUG 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 $9 million and $10 million as of March 31, 2014 and December 31, 2013, 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 contracts, LCAPP contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2014 and December 31, 2013:

	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, 2013 Balance	$	36		$	(290	)	$	(254	)	$	—	$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
Unrealized gain (loss)	(8		)	(17		)	(25		)	—		(22		)	(22		)	3			1			4
Purchases	—			—			—			—		—			—			6			(15		)	(9		)
Terminations(2)	—			—			—			—		166			166			—			—			—
Settlements	(8		)	85			77			—		—			—			(13		)	11			(2		)
December 31, 2013 Balance	$	20		$	(222	)	$	(202	)	$	—	$	—		$	—		$	4		$	(12	)	$	(8	)
Unrealized gain	—			27			27			—		—			—			6			2			8
Settlements	(17		)	7			(10		)	—		—			—			(3		)	2			(1		)
March 31, 2014 Balance	$	3		$	(188	)	$	(185	)	$	—	$	—		$	—		$	7		$	(8	)	$	(1	)

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

⁽²⁾  See Note 8, Derivative Instruments

Level 3 Quantitative Information

The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(1	)	Model	RTO auction clearing prices	($4.20) to $7.60	$0.80	Dollars/MWH
NUG Contracts	$	(185	)	Model	Generation Electricity regional prices	600 to 5,422,000 $47.90 to $59.00	1,033,000 $53.50	MWH Dollars/MWH

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FES
Recurring Fair Value Measurements	March 31, 2014												December 31, 2013
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	586		$	—		$	586		$	—		$	792		$	—		$	792
Derivative assets - commodity contracts	11			294			—			305			7			208			—			215
Derivative assets - FTRs	—			—			4			4			—			—			3			3
Equity securities(1)	327			—			—			327			207			—			—			207
Foreign government debt securities	—			55			—			55			—			65			—			65
U.S. government debt securities	—			25			—			25			—			27			—			27
U.S. state debt securities	—			3			—			3			—			—			—			—
Other(2)	—			319			—			319			—			176			—			176
Total assets	$	338		$	1,282		$	4		$	1,624		$	214		$	1,268		$	3		$	1,485
Liabilities
Derivative liabilities - commodity contracts	$	(8	)	$	(179	)	$	—		$	(187	)	$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—			—			(8		)	(8		)	—			—			(11		)	(11		)
Total liabilities	$	(8	)	$	(179	)	$	(8	)	$	(195	)	$	(13	)	$	(100	)	$	(11	)	$	(124	)
Net assets (liabilities)(3)	$	330		$	1,103		$	(4	)	$	1,429		$	201		$	1,168		$	(8	)	$	1,361

⁽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 $8 million and $9 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2014 and December 31, 2013:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2013 Balance	$	6		$	(6	)	$	—
Unrealized loss	—			(2		)	(2		)
Purchases	5			(12		)	(7		)
Settlements	(8		)	9			1
December 31, 2013 Balance	$	3		$	(11	)	$	(8	)
Unrealized gain	3			1			4
Settlements	(2		)	2			—
March 31, 2014 Balance	$	4		$	(8	)	$	(4	)

Level 3 Quantitative Information

The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(4	)	Model	RTO auction clearing prices	($4.20) to $7.60	$0.60	Dollars/MWH

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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, OE and TE 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 March 31, 2014 and December 31, 2013:

	March 31, 2014(1)						December 31, 2013(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,670	$	44	$	1,714	$	1,881	$	33	$	1,914
FES	698		22		720		918		17		935
Equity securities
FirstEnergy	$	433	$	31	$	464	$	308	$	9	$	317
FES	308		19		327		207		—		207

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $324 million; FES - $276 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 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 ended March 31, 2014 and 2013 were as follows:

Three Months Ended
March 31, 2014	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	621	$	28	$	(16	)	$	(2	)	$	25
FES	423		19		(5		)	(2		)	15
March 31, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	539	$	24	$	(6	)	$	(7	)	$	26
FES	252		20		(3		)	(7		)	13

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 March 31, 2014 and December 31, 2013:

	March 31, 2014						December 31, 2013
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	24	$	8	$	32	$	33	$	2	$	35

Investments in employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $635 million as of March 31, 2014, and $636 million as of December 31, 2013, 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:

	March 31, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	18,034	$	19,321	$	17,049	$	17,957
FES	2,996		3,098		3,001		3,073

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 March 31, 2014 and December 31, 2013.

On March 31, 2014, FE, FES, AE Supply, FET and FE's other borrower subsidiaries entered into extensions and amendments to thethreeexisting multi-year syndicated revolving credit facilities.Each facility was extended until March 31, 2019.The FE facility was amended to increase the lending banks' commitments under the facility by $1 billion to a total of $3.5 billionand to increase the individual borrower sublimit for FE by $1 billionto a total of $3.5 billion. The FES/AE Supply facility was amended to decrease the lending banks' commitments by $1 billion to a total of $1.5 billion. The lending banks' commitments under the FET facility remain at $1 billion and that facilitywas amended to increase ATSI's individual borrower sublimit to $500 millionfrom $100 millionand

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TrAIL's individual borrower sublimit to $400 millionfrom $200 million. FirstEnergy expensed approximately $5 million(FES - $3 million)of unamortized debt expense as a result of the amendments.The amount was included in Loss on Debt Redemptions in the Consolidated Statement of Income in the first quarter of 2014.

On March 31, 2014, FE executed, and fully utilized, a new $1 billionvariable rate term loan credit agreement with a maturity date of March 31, 2019.The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances.

During the first quarter of 2014, FG and NG remarketed approximately $417 millionof PCRBs previously held by the companies.Of the total, $182 million was remarketed with a fixed interest rate of4%per annum with a mandatory put date of June 3, 2019 and $235 millionwas remarketed with a fixed interest rate of3.75%per annum with a mandatory put date of December 3, 2018.

In addition, in the first quarter of 2014, FG and NG repurchased approximately $197million and $16 millionof PCRBs, respectively, which were subject to a mandatory tender. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

On April 1, 2014, PN and ME repurchased approximately $45 million and $29 millionof PCRBs, respectively, which were subject to a mandatory put on such date. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

8. 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 2020.

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 less than $1 million and $2 million as of March 31, 2014 and December 31, 2013, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $9 million is expected to be amortized to income during the next twelve months.

FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. No forward starting swap agreements accounted for as a cash flow hedge were outstanding as of March 31, 2014 or December 31, 2013. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $57 million and $59 million as of March 31, 2014 and December 31, 2013, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months.

In connection with certain debt redemptions, FirstEnergy recorded interest expense related to deferred losses on terminated interest rate swaps of approximately $2 million for the three months ended March 31, 2013.

As of March 31, 2014 and December 31, 2013, no commodity or interest rate derivatives were designated as cash flow hedges.

Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three months ended March 31, 2014 and 2013.

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Fair Value Hedges

FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of March 31, 2014 and December 31, 2013, 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 $41 million and $44 million as of March 31, 2014 and December 31, 2013, respectively. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $3 million and $6 million during the three months ended March 31, 2014 and 2013, respectively.

As of March 31, 2014 and December 31, 2013, no commodity or interest rate derivatives were designated as fair value hedges.

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 March 31, 2014, FirstEnergy’s net asset position under commodity derivative contracts was $117 million, which related to FES positions. Under these commodity derivative contracts, FES posted $85 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $11 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on commodity derivative contracts held as of March 31, 2014, an adverse change of 10% in commodity prices would decrease net income by approximately $40 million during the next twelve months.

NUGs

As of March 31, 2014, FirstEnergy's net liability position under NUG contracts was $185 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 maintained two LCAPP contracts, which were financially settled agreements that allowed 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 expected 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 were considered derivative liabilities with a corresponding regulatory asset. Since the LCAPP contracts were subject to regulatory accounting, changes in their fair value did not impact earnings. On October 11, 2013, the U.S. District Court for the District of New Jersey declared that the LCAPP was 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. The parties filed an appeal with the U.S. Court of Appeals for the Third Circuit and briefing by the parties was completed by March 5, 2014. Consistent with the provisions of the LCAPP contracts, the U.S. District Court's ruling was a termination event. During the fourth quarter of 2013, JCP&L issued termination notices to the counterparties and reversed the derivative liability and corresponding regulatory asset on its Consolidated Balance Sheet.

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FTRs

As of March 31, 2014, FirstEnergy's and FES's net liability position under FTRs was $1 million and $3 million, respectively, and FES posted $4 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
	March 31, 2014		December 31, 2013			March 31, 2014			December 31, 2013
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	240	$	162	Commodity Contracts	$	(154	)	$	(102	)
FTRs	7		4		FTRs	(5		)	(9		)
	247		166			(159		)	(111		)
					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs	(188		)	(222		)
Deferred Charges and Other Assets - Other					Noncurrent Liabilities - Other
Commodity Contracts	64		53		Commodity Contracts	(33		)	(11		)
NUGs	3		20		FTRs	(3		)	(3		)
	67		73			(224		)	(236		)
Derivative Assets	$	314	$	239	Derivative Liabilities	$	(383	)	$	(347	)

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
March 31, 2014	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	304		$	(182	)	$	(4	)	$	118
FTRs	7			(7		)	—			—
NUG contracts	3			—			—			3
	$	314		$	(189	)	$	(4	)	$	121
Derivative Liabilities
Commodity contracts	$	(187	)	$	182		$	2		$	(3	)
FTRs	(8		)	7			1			—
NUG contracts	(188		)	—			—			(188		)
	$	(383	)	$	189		$	3		$	(191	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2013	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	215		$	(106	)	$	(9	)	$	100
FTRs	4			(4		)	—			—
NUG contracts	20			—			—			20
	$	239		$	(110	)	$	(9	)	$	120
Derivative Liabilities
Commodity contracts	$	(113	)	$	106		$	7		$	—
FTRs	(12		)	4			5			(3		)
NUG contracts	(222		)	—			—			(222		)
	$	(347	)	$	110		$	12		$	(225	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2014:

	Purchases	Sales	Net	Units
	(In millions)
Power Contracts	41	38	3	MWH
FTRs	26	—	26	MWH
NUGs	7	—	7	MWH
Natural Gas	65	8	57	mmBTU

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The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2014 and 2013, are summarized in the following tables:

	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2014
Unrealized Gain Recognized in:
Other Operating Expense (1)		$12			$5			$17
Realized Gain (Loss) Reclassified to:
Revenues (2)		($13	)		$52			$39
Purchased Power Expense (3)	436			—			436
Other Operating Expense (4)	—			(7		)	(7		)
Fuel Expense	9			—			9
(1) Includes $12 million for commodity contracts and $5 million for FTRs associated with FES.
(2) Represents losses on structured financial contracts. Includes ($13) million for commodity contracts and $51 million for FTRs associated with FES.
(3) Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power. Includes $436 million for commodity contracts associated with FES.
(4) Includes ($7) million for FTRs associated with FES.
2013
Unrealized Loss Recognized in:
Other Operating Expense (5)		($5	)		($2	)		($7	)
Realized Gain (Loss) Reclassified to:
Revenues (6)		$10			$7			$17
Purchased Power Expense (7)	(11		)	—			(11		)
Other Operating Expense (8)	—			(9		)	(9		)
Fuel Expense	(1		)	—			(1		)
(5) Includes ($5) million for commodity contracts and ($1) million for FTRs associated with FES.
(6) Includes $10 million for commodity contracts and $6 million for FTRs associated with FES.
(7) Includes ($11) million for commodity contracts associated with FES.
(8) Includes ($8) million for FTRs associated with FES.

The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three months ended March 31, 2014 and 2013, are summarized in the following tables:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP(1)			Regulated FTRs			Total
	(In millions)
2014
Unrealized Gain on Derivative Instrument	$	27		$	—		$	4		$	31
Realized Loss on Derivative Instrument	(10		)	—			(1		)	(11		)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	18		$	(2	)	$	—		$	16
Realized Gain (Loss) on Derivative Instrument	23			—			(1		)	22

⁽¹⁾  During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

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 ended March 31, 2014 and 2013:

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	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP(1)			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of January 1, 2014	$	(202	)	$	—		$	—		$	(202	)
Additions/Change in value of existing contracts	27			—			4			31
Settled contracts	(10		)	—			(1		)	(11		)
Outstanding net liability as of March 31, 2014	$	(185	)	$	—		$	3		$	(182	)
Outstanding net liability as of January 1, 2013	$	(254	)	$	(144	)	$	—		$	(398	)
Additions/Change in value of existing contracts	18			(2		)	—			16
Settled contracts	23			—			(1		)	22
Outstanding net liability as of March 31, 2013	$	(213	)	$	(146	)	$	(1	)	$	(360	)

⁽¹⁾  During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

9. 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 any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.

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.PE filed its second annual report on March 27, 2014.

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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; selective increased investment in system hardening; 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 July 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 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 concluded.In the initial briefs of the parties filed on January 27, 2014, the Division of Rate Counsel recommended that base rate revenues be reduced by $214.9 million while the NJBPU Staff recommended a $207.4 million reduction (such amounts do not address the revenue requirements associated with the major storm events of 2011 and 2012).Reply briefs were filed on February 24, 2014. The matter is pending before the ALJ.

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 February 24, 2014, a Stipulation was filed with the NJBPU by JCP&L, the Division of Rate Counsel and NJBPU Staff which will allow recovery of $736 million of JCP&L's $744 million of costs related to the significant weather events of 2011 and 2012.As a result, FirstEnergy recorded a regulatory

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asset impairment charge of approximately $8 million (pre-tax) as of December 31, 2013.By its Order of March 19, 2014, the NJBPU approved the Stipulation of Settlement and on March 25, 2014, transmitted a copy of that Order to the Office of Administrative Law so that “actual recovery of the 2011 costs can be determined in relation to the pending base rate case.”Recovery of 2011 storm costs will be addressed in the pending base rate case; recovery of 2012 storm costs will be determined by the NJBPU.

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 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 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.While briefing has been completed, 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 provides 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 SB221, the Ohio Companies are required to implement energy efficiency programs that 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

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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, on July 31, 2012 the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015.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 denied the Ohio Companies' application for rehearing, in part, but authorized 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.The motion is still pending and additional briefing has followed.While briefing has been completed, the matter has not been scheduled for oral argument.

SB221 requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2024.The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet the renewable energy requirements established under SB221.In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs and selected auditors to perform a financial and management audit.Final audit reports filed with the PUCO generally supported the Ohio Companies' approach to procurement of RECs, but also recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state renewable obligations that the auditor characterized as excessive.Following the hearing, the PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of RECs 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, and to file tariff schedules reflecting the refund and interest costs 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 December 18, 2013, the PUCO denied all of the applications for rehearing. Based on the PUCO ruling a regulatory charge of approximately $51 million, including interest, was recorded in the fourth quarter of 2013.On December 24, 2013, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio.On February 10, 2014, the Supreme Court of Ohio granted the Ohio Companies' motion for stay, which went into effect on February 14, 2014.On February 18, 2014, the Office of Consumers' Counsel and the ELPC also filed appeals of the PUCO's order.The Ohio Companies filed their merit brief with the Supreme Court of Ohio on March 6, 2014.On April 15, 2014, the Supreme Court of Ohio stayed the briefing schedule pending the court's resolution of the Ohio Companies' motion to seal certain confidential portions of the appendix and supplement to their merit brief.

The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.On April 15, 2014, the Ohio Companies reported that they met all of their annual renewable energy resource requirements for reporting year 2013.

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 comment 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.On June 5, 2013, the PUCO requested additional comments and reply comments on the topics of market design and corporate separation, which the Ohio Companies timely filed on July 8, 2013 and July 22, 2013, respectively.The PUCO held a series of workshops throughout 2013, which included an en banc workshop on December 11, 2013.The PUCO Staff filed a report on January 16, 2014, which contained a limited discussion of the workshops and the PUCO Staff's recommendations.The Ohio Companies submitted comments on February 6, 2014 and Reply Comments on February 20, 2014.The PUCO issued its Order in this matter on March 26, 2014, which included a wide range of issues such as, maintaining SSO service in its current form, requiring corporate separation audits of all EDUs, establishing a market development working group, and ordering changes to the bill format.The Ohio Companies filed their Application for Rehearing on April 25, 2014.The Ohio Companies filed their memorandum contra applications for rehearing of other stakeholders on May 5, 2014.

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On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2015, 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 4, 2013, the Pennsylvania Companies filed a DSP 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 SRECs for ME, PN, and Penn.The Pennsylvania Companies have reached a settlement with all parties on all issues raised in the case with the exception of the treatment of NITS charges. On May 6, 2014, the ALJ issued a Recommended Decision recommending adoption of the settlement without modification and the denial of several parties’ request for non-bypassable treatment of NITS charges. A final order is expected from the PPUC by August 2014.

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.On appeal, the Commonwealth Court affirmed 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 and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari.ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania to obtain 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.On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss.As a result of the U.S. District Court's decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013. The balance of marginal transmission losses was fully refunded to customers by the second quarter of 2013.On October 29, 2013, ME and PN filed a Notice of Appeal of the U.S. District Court's decision to dismiss the complaint with the United States Court of Appeals for the Third Circuit.Oral argument was held on April 8, 2014, and, at the end of the argument, the Third Circuit directed ME and PN, and the PPUC, each to submit a brief on April 16, 2014 on the question of whether it is possible to waive the preemptive effect of FERC’s classification of line loss charges as transmission charges.On April 16, 2014, ME and PN, the PPUC, and the Pennsylvania Industrials each submitted briefs on the Third Circuit's questions.

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 a 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 between $1 and$20 million.On November 15, 2013, the Pennsylvania Companies submitted their energy efficiency and peak demand reduction report for the period ending May 31, 2013, in which they indicated that all of the Pennsylvania Companies met their statutory requirements.On March 20, 2014, the PPUC issued an Order initially determining that ME, PN and Penn achieved the 2011 and 2013 statutory energy efficiency benchmarks. The PPUC also initially determined that WP is not in compliance with the 2011 statutory energy efficiency benchmarks but is in compliance with the 2013 energy efficiency benchmarks.As such, the PPUC, with regards to WP’s compliance with the 2011 statutory benchmarks, referred the matter to the PPUC Bureau of Investigation and Enforcement for the initiation of an appropriate proceeding no later than May 30, 2014 to investigate whether WP is in compliance with the 2011 statutory benchmarks and whether WP is subject to statutory penalties.The PPUC also ordered that the initial determination will be deemed final unless any petitions challenging its initial determination are filed within 20 days of the Order.On April 9, 2014, WP filed its petition challenging the PPUC’s initial determination arguing, among other things, that the May 2011 target was not mandatory and WP is in compliance because it achieved its May 2013 targets.On April 21, 2014, WP filed an appeal with the Commonwealth Court of Pennsylvania in which it challenged the PPUC's initial finding of a violation of Act 129 on due process grounds.On that same day, the Bureau of Investigation and Enforcement, consistent with the PPUC's March 20, 2014 Order, initiated a proceeding by filing a Complaint against WP in which it alleges that WP violated Act 129 and recommends a penalty in the amount of $11.4 million.The Pennsylvania Companies have 20 days in which to respond to the Complaint.A prehearing conference is scheduled for May 9, 2014 at which time a procedural schedule for this matter is expected to be established.

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

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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.Based upon information received, the PPUC has not included a peak demand reduction requirement in the Phase II plans.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 requested 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 were held and briefs were submitted by the Pennsylvania Companies and the OCA.On November 8, 2013, the ALJ issued a Recommended Decision recommending that the Pennsylvania Companies' Deployment Plan be adopted with certain modifications, including, among other things, that the Pennsylvania Companies perform further benchmarking analyses on their costs and hire an independent consultant to perform further analyses on potential savings.On December 2, 2013, the Pennsylvania Companies submitted exceptions in which they challenged, among other things, certain recommendations in the ALJ's decision, and requested approval of a modification to the deployment schedule so as to allow the entire Penn smart meter system (170,000 meters) to be built by the end of 2015, instead of the original proposed installation of 60,000 meters by the end of 2016.The OCA took exception to one issue and both parties filed replies to exceptions on December 12, 2013.In its March 6, 2014 Opinion and Order, the PPUC rejected the OCA's exception and many of the ALJ's recommendations, including the recommendation to hire an independent consultant and the disallowance of $5.1 million of customer information system costs, and affirmed the ALJ's recommendation on the accounting treatment for legacy meter costs.The PPUC also directed the Pennsylvania Companies to file an amendment to the Deployment Plan within thirty days of the Order with sufficient supporting documentation for proper evaluation if the Pennsylvania Companies intend to pursue an accelerated deployment schedule, and the PPUC indicated that it would establish an expedited procedural schedule and rule on the filing within 90 days of the March 6, 2014 Order.The Pennsylvania Companies filed an amended Deployment Plan on March 19, 2014, to which, the OCA filed exceptions arguing that the amended plan failed to: 1) list certain potential cost savings categories that are to be considered by the Pennsylvania Companies; and 2) follow proper procedure. On April 7, 2014, the Pennsylvania Companies filed a reply to OCA’s exceptions explaining why they should be rejected.A prehearing conference was held on April 25, 2014, and a procedural schedule was established that is expected to allow the PPUC to issue an order by June 5, 2014.

In the PPUC Order approving the FirstEnergy and AE 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.On March 24, 2014, the PPUC issued a letter withdrawing the Proposed Rulemaking.

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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.

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.A hearing was held on December 3, 2013, and briefing followed.The WVPSC issued an order on April 14, 2014 approving the plan, stating rate recovery will be addressed in the base rate case filed on April 30, 2014. In the interim, MP and PE are authorized to defer all costs associated with the plan.

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 filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposed a net ownership transfer of1,476MW of coal-fired generation capacity to MP.The proposed transfer involved 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.FERC authorized the transfers on April 23, 2013 and the financing on May 13, 2013.A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013.On October 7, 2013, the WVPSC authorized the transaction, with certain conditions, and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately$322 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.Concurrently, MP recognized a regulatory liability of approximately$23 millionrepresenting 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 billionand MP's assumption of a$73.5 millionpollution control note.The$1.1 billionnet consideration was originally financed by MP through an equity infusion from FE of approximately$527 millionand a note payable to AE Supply of approximately$573 million.The note payable to AE Supply was paid in the fourth quarter of 2013.The settlement also required MP and PE to file a base rate case by April 30, 2014.On November 6, 2013, the WVCAG petitioned for appeal with the Supreme Court of Appeals of West Virginia.MP and PE filed their response to the WVCAG petition on December 27, 2013 and WVCAG filed its reply on January 16, 2014.The Supreme Court of Appeals of West Virginia held oral arguments on March 5, 2014.On April 23, 2014 the Supreme Court of Appeals of West Virginia delivered an Opinion affirming the WVPSC order approving the Generation Resource Transaction.

On April 30, 2014, MP and PE filed a rate case requesting a base rate increase of approximately $96 million, or 9.3%. The filing also included a surcharge to recover costs of MP's and PE's vegetation management program in the amount of approximately $48 million. The proposed total rate increase request, including the cost of the vegetation management program, is approximately $144 million, or 14%. MP and PE anticipate a decision from the WVPSC in February 2015.

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

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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 Rates

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 a Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated with several other cases before that court for briefing and disposition.Briefing is complete, oral argument was held on April 22, 2014, and a decision is 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 again accepted the hybrid method.Certain parties 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 NYISO region and; (2) the PJM region and the FERC-jurisdictional members of the SERTP 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.On December 30, 2013, FERC conditionally accepted the PJM/SERTP cross-border project cost allocation filing, subject to refund and future orders in PJM's and SERTP's related Order No. 1000 interregional compliance proceedings.The PJM/NYISO and PJM/MISO cross-border project cost allocation filings remain pending before FERC.On January 16, 2014, FERC issued an order regarding the effective date of PJM's separate Order No. 1000 regional transmission planning and cost allocation compliance filing, noting that it would address the merits of the comments on and protests to that filing and related compliance filings in a future order.

Numerous parties, including ATSI, FES, TrAIL, OE, CEI, TE, Penn, JCP&L, ME, MP, PN, WP and PE, sought judicial review of Order No. 1000 before the U.S. Court of Appeals for the D.C. Circuit.Briefing is complete and oral argument was held on March 20, 2014.

The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.

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 many of the matters involved with the move have been resolved, FERC denied recovery by means of ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately$78.8 millionuntil such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move.On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve the exit fee and transmission cost allocation issues.However, FERC subsequently rejected that settlement, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges.On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

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Separately, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed.Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings in front of FERC and certain U.S. appellate courts.The MISO and its allied parties assert that the benefits to the ATSI zone of the Michigan Thumb project are roughly commensurate with the costs that MISO desires to charge to the ATSI zone, estimated to be as much as $16 million per year.ATSI has submitted evidence that the Michigan Thumb project provides no electric benefits to the ATSI zone and, on that basis, opposes the MISO’s efforts to impose these costs on the ATSI zone loads.The MISO and its allied parties also assert that certain language in the MISO Transmission Owners Agreement requires ATSI to pay these charges.In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek recovery of these charges through its formula rate.While FERC proceedings regarding whether the MISO can charge ATSI for MVP costs remain pending, on February 24, 2014, the U.S. Supreme Court declined to hear appeals filed by FirstEnergy and other parties of the Seventh Circuit's June 2013 decision upholding FERC's acceptance of the MISO's generic MVP cost allocation proposal.

In addition, in a 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.ATSI subsequently filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit.Briefing is complete, oral argument was held on 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 cannot be predicted at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the 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%for 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. PATH, 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 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.

On March 20, 2014, the settlement judge declared an impasse in efforts to achieve settlement. On March 24, 2014, the Chief ALJ terminated settlement judge procedures and appointed an ALJ to preside over the hearing phase of the case.The hearing is scheduled to commence on November 5, 2014.The issues set for hearing include the prudence of the costs, the base return on

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equity and the period of recovery.Depending on the outcome of the hearing, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

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).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.On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $394 million.See Note 13, Discontinued Operations for additional information regarding the assets sold.

MISO Capacity Portability

On June 11, 2012, in response to certain arguments advanced by MISO, 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.FirstEnergy and other parties have 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.On December 19, 2013, FERC issued an order directing that FERC staff are to attend the "joint and common market" stakeholder meetings for the purpose of monitoring progress on the initiatives described in the September 26, 2013 joint informational filing and establishing a new proceeding to reflect the broadened scope of issues contemplated by that filing and the RTOs' 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 publicly-available data 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.

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 2010, FES and AE Supply have lost more than$87 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 re-filed 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

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July 5, 2013,FESC, on behalf of FES and AE Supply, filed a request for rehearing of FERC's order.That request for rehearing, and all subsequent filings in the docket, are pending before FERC.

PJM RPM Tariff Amendments

In November 2013, PJM began to submit a series of amendments to its RPM capacity tariff in order to address certain problems that have been observed in recent auctions.These problems can be grouped into four categories: (i) Demand Response (DR); (ii) imports; (iii) modeling of transmission upgrades in calculating geographic clearing prices; and (iv) arbitrage/capacity replacement.The purpose of PJM’s tariff amendments is to ensure that resources that clear in the RPM auctions are available as physical resources in the delivery year and that the rules implement comparable obligations for different types of resources.In each of the relevant dockets, FirstEnergy submitted comments as part of a coalition of utilities (generally including an affiliate of AEP, Duke and Dayton).The FirstEnergy/coalition position was that all of the PJM proposals should be accepted as proposed, and that the FERC should order PJM to take additional steps that should have the effect of eliminating additional distortions and flaws in the RPM market.PJM made two filings regarding DR; FERC accepted one as proposed on January 30, 2014, and issued a deficiency letter regarding the other on March 6, 2014. FERC also issued deficiency letters requesting additional information from PJM regarding the modeling filing on January 17, 2014 and regarding the imports filing on January 28, 2014.On February 18 and 21, 2014, respectively, PJM filed its responses to FERC's deficiency letters regarding the modeling filing and the imports filing.On April 18, 2014, FERC conditionally accepted PJM's modeling filing, as supplemented, subject to PJM's submission of a compliance filing. On April 22, 2014, FERC accepted PJM's imports filing, as supplemented.The second DR filing, which relates to the rules applicable to DR performance obligations, the arbitrage/capacity replacement filing and related filings in those dockets, and a request for rehearing of the January 30, 2014 order on the first DR filing, are pending before FERC.PJM requested FERC action on the DR performance obligations filing by April 11, 2014, and prior to the May 2014 BRA for the arbitrage/capacity replacement filing.Although FirstEnergy believes that these filings (and the associated tariff changes) should have positive implications for RPM clearing prices, generally there can be no assurance as to their ultimate impact on FirstEnergy.

PJM RPM Auctions - Calculation of Unit-Specific Offer Caps

The PJM RPM capacity tariff describes the rules for calculating the “offer cap” for each unit that offers into the RPM auctions. In summary, the offer cap is calculated by identifying certain going-forward costs, including the going-forward capital requirements, for a given unit, and then subtracting the projected energy and ancillary services revenues, net of marginal costs, from the going-forward costs.The remainder becomes the offer cap. FES learned that the PJM Market Monitor’s practice for calculating the forecast energy and ancillary services revenues has been to use the lower of the unit’s economic or cost-based offers into the PJM energy market.The Market Monitor engages in this practice based on his interpretation of certain provisions of the PJM capacity tariff. However, review of the relevant tariff language suggests that only the cost-based offer data should be used.FES determined that the Market Monitor’s use of the lower of cost-based or economic offer data has the effect of suppressing the offer cap, which can distort the price signal that is intended to come out of the RPM auction process.On April 7, 2014, FES submitted a Petition for Declaratory Order to FERC, asking for an interpretation of the relevant provisions of the PJM capacity tariff.Specifically, FES identified the difference of opinion between FES and the Market Monitor regarding interpretation of the relevant provision and asked FERC to rule on the question of whether the tariff language permits the Market Monitor’s use of the lower of cost-based or economic offer data or requires use of the cost-based offer data.FES asked FERC to rule on the petition by May 9, 2014.On April 18, 2014, the Market Monitor and other parties filed protests to FES's petition, arguing that the PJM capacity tariff allows the Market Monitor to use market-based energy offers instead of cost-based energy offers in calculating RPM auction offer caps and asking FERC to delay action on the petition until after the May 2014 BRA.FES' petition, the protest, and related filings are pending before FERC. The timing of FERC action and the outcome of this proceeding cannot be predicted at this time.

Market-Based Rate Authority, Triennial Update

OE, CEI, TE, Penn, JCP&L, ME, PN, MP, WP, PE, AE Supply, FES, FG, NG, FirstEnergy Generation Mansfield Unit 1 Corp., Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates.One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority.On December 20, 2013, FESC submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement.That filing is pending before FERC.

10. 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 March 31, 2014, outstanding guarantees and other assurances aggregated approximately $4.0 billion, consisting of parental guarantees ($896 million), subsidiaries' guarantees ($2,207 million) and other guarantees ($891 million).

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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.This posted collateral is used to settle gains or losses on those bilateral agreements or derivatives.

Based on FES' power portfolio exposure as ofMarch 31, 2014, FES has posted collateral of$544 million and AE Supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of$28 million.The collateral posted at FES primarily relates to the extreme weather and market conditions experienced in January of 2014. On April 16, 2014, approximately $275 million of cash collateral was returned to FES as a result of the PJM semi-annual peak market activity calculation reset.

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 ofMarch 31, 2014:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	461	$	6	$	49	$	516
BB+/Ba1 Credit Ratings	$	497	$	6	$	49	$	552
Full impact of credit contingent contractual obligations	$	796	$	58	$	87	$	941

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 ofMarch 31, 2014, 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$111 millionand$1 million, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a syndicated three-year senior secured term loan facility dated October 18, 2011, as amended, that matures 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 FE, 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 guarantees of the obligations of Global Holding under the new facility.

In connection with the 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 as collateral.

FE, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed, most recently as of August 14, 2013, to use their best efforts to refinance the facility no later than July 20, 2015, on a non-recourse basis so that FE's guaranty can be terminated and/or released.If that refinancing does not occur, FE may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the facility in full.In lieu of providing such funding, the co-owners, at FE's option, may provide their several guaranties of Global Holding's obligations under the facility.Since January 1, 2013, FE has received a fee for providing its guaranty.The fee is payable semiannually, and accrues at a rate of5%per annum on the average daily outstanding aggregate commitments under the facility for each semiannual period.

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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 Keystone, Portland and Shawville coal-fired plants based on “modifications” dating back to the mid-1980s.JCP&L, as the former owner of 16.67% of the Keystone Station, ME, as a former owner and operator of the Portland Station, and PN as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter or estimate the possible loss or 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.FirstEnergy 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, MP, PE and WP in the U.S. District Court for the Western District of Pennsylvania alleging, among other things, that AE performed major modifications in violation of the NSR 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.On February 6, 2014, the Court entered judgment for AE, AE Supply, MP, PE and WP finding they had not violated the CAA or the Pennsylvania Air Pollution Control Act.On March 10, 2014, New York, Connecticut, and Maryland filed an appeal with the U.S. Court of Appeals for the Third Circuit.This decision does not change the status of these plants which remain deactivated.

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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 D.C. Circuit 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 D.C. Circuit and was ultimately vacated by the Court on August 21, 2012.The Court has ordered the EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR.On April 29, 2014 the U.S. Supreme Court reversed the D.C Circuit decision vacating CSAPR and generally upheld the EPA's authority under the CAA to establish the regulatory structure underpinning CSAPR.Depending on the outcome of further proceedings in this matter and how the EPA and the states implement the final rules, 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 Bruce 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 was challenged in the U.S. Court of Appeals for the D.C. Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1.On April 15, 2014, MATS was upheld by the U.S. Court of Appeals for the D.C. Circuit, however, the Court refused to decide FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers due to a January 2013 petition for reconsideration still pending but not addressed by EPA.Depending on the outcome of further appeals, if any, and how the MATS are ultimately implemented, FirstEnergy's total cost of compliance with MATS is currently estimated to be approximately$465 million(Competitive Energy Services segment of$240 millionand Regulated Distribution segment of$225 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.In February 2014, PJM notified FG that Eastlake Units 1-3 and Lake Shore Unit 18 will be released from RMR status as of September 15, 2014.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.FE and FES have asserted force majeure defenses for delivery shortfalls under certain agreements, and are in discussion with the applicable counterparties.As to two agreements, FE and FES have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately$70 million, and agreed to pay liquidated damages for delivery shortfalls for 2013 and 2014.FE and FES recorded $67 million in liquidated damages in the fourth quarter of 2013, associated with estimated 2013 delivery shortfalls, which were paid in the first quarter of 2014. Additionally, in January 2014, FE and FES reached an agreement in principle with Mepco Holdings LLC to terminate a contract for future coal deliveries to Hatfield for $18 million, which was approved by the United States Bankruptcy Court on February 26, 2014.If FE and FES fail to reach a resolution with applicable counterparties for coal transportation agreements associated with the deactivated plants or unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to their 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.If that were to occur, FE and FES are unable to estimate the loss or range of loss.

Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level.Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies to reduce GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.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 goals to: (1) cut carbon pollution in America 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. GHG emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant deactivations and increased efficiencies, FirstEnergy anticipates

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its CO2 emissions will be reduced 25% below 2005 levels by 2016, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.

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 the 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.The memorandum further directed the EPA to propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units.On September 20, 2013, the EPA proposed a new source performance standard, which would not apply to any existing, modified, or reconstructed fossil fuel generating units, 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 the 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?" Oral argument was held on February 24, 2014. 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.

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.In 1997, the U.S. Senate passed the Byrd-Hagel resolution by a unanimous vote of 95-0. The resolution stated that it is the sense of the Senate that the United States should not be a signatory to any protocol to, or other agreement regarding, the United Nations Framework Convention on Climate Change which would mandate new commitments to limit or reduce GHG emissions, unless the protocol or other agreement also mandates new specific scheduled commitments to limit or reduce GHG emissions for developing country parties within the same compliance period, or would not result in serious harm to the economy of the United States. 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.In November 2013, the U.N. Climate Change Conference in Warsaw, Poland advanced negotiations of a new global agreement to reduce GHG emissions by 2015. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations.The CO₂emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants.In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.

In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants.The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment

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(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.On April 16, 2014, counsel for EPA informed the United States District Court in which a settlement agreement with certain NGOs set April 17, 2014 as a deadline for finalizing the Section 316(b) regulation that an additional 29 days would be needed to finalize the Section 316(b) regulation by May 16, 2014.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 September 30, 2015, 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 ranging from$150 millionto$300 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.Based on the stringency of the TMDL, MP may incur significant costs to reduce sulfate discharges into the Monongahela River if the NPDES permit for the coal-fired Fort Martin plant in West Virginia is required to be modified or renewed to include more stringent effluent limitations for sulfate.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 CCRs produced by electric utilities pose significant financial risk to the industry.In May 2010, the EPA proposedtwooptions for additional regulation of CCRs, 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 CCRs.On April 19, 2013, the EPA stated it would "align" its proposed CCR 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.On January 29, 2014, EPA agreed to take final action by December 19, 2014 on whether or not to pursue the proposed non-hazardous waste option for regulating CCRs in a Consent Decree to be filed in pending litigation.Depending on the content of the EPA's final effluent limitations rule, the specifics of any "alignment", whether EPA chooses to pursue the non-hazardous or hazardous waste option and the potential enactment of legislation, the future costs of compliance with such standards may require material capital expenditures.

42

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 required 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.FG responded to the PA DEP on December 3, 2013, and as a result of the Closure Plan, FG increased its ARO for LBR by $163 million in 2013.On April 3, 2014, PA DEP issued a permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizes FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCBs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met.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.In addition, 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 and December 5, 2013, complaints were filed on behalf of approximately50individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia and approximately 15 individuals against FG in the U.S. District Court for the Western District of Pennsylvania seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment.The complaints state 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 the complaints, 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 CCR 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 ofMarch 31, 2014based 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$129 millionhave been accrued throughMarch 31, 2014. 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.

43

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofMarch 31, 2014, FirstEnergy had approximately$2.3 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2.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.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranty, as appropriate.By a letter dated March 28, 2013, FENOC informed the NRC that the nuclear decommissioning parental guarantee would be increased to $155 millionduring the second quarter of 2014.Moreover, a new parental guarantee for the Beaver Valley spent fuel storage facility of $9.5 millionwould also be put in place.

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.A 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.Other contentions proposed by the petitioners in this proceeding have been rejected by the ASLB. On February 18, 2014, Beyond Nuclear and Don't Waste Michigan, two of the petitioners in the Davis-Besse license renewal proceeding, requested that the NRC institute a rulemaking on the environmental impacts of high density spent fuel storage and mitigation alternatives. On February 27, 2014, these petitioners requested a suspension of the licensing decision in the Davis-Besse license renewal proceeding to allow the NRC to complete this rulemaking.On March 21, 2014, both FENOC and the NRC opposed the request for a suspension. On April 21, 2014, the Intervenors proposed an additional contention in the license renewal proceeding related to the shield building.

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. The shield building is a 2 1/2-foot thick reinforced concrete structure that provides biological shielding, protection from natural phenomena including wind and tornadoes and additional shielding in the event of an accident. FENOC then expanded its sample size to include all of the existing core bores in the shield building. These inspections, which are now complete, identified additional subsurface cracking that was determined to be pre-existing, but only now identified with the aid of improved inspection technology. These inspections also revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

On February 1, 2014 the Davis-Besse Nuclear Power station entered an outage to install two new steam generators, replace about a third of the unit’s 177 fuel assemblies and perform numerous safety inspections and preventative maintenance activities. These activities, including amounts spent in prior years in preparation for this outage, represent an investment of approximately $600 million by FES at Davis Besse.During the preliminary stages of the outage an area of concrete that was not filled to the expected thickness within the shield building wall was discovered at the top of the temporary construction opening that was created as part of the 2011 outage.The 2011 temporary construction opening was created to install the new reactor head. FENOC has assessed the as-found condition of the concrete and has determined the shield building would have performed its design functions.This condition within the shield building wall was repaired to conform to its original design configuration.

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

44

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.A damages hearing is scheduled for May 13-14, 2014, and a ruling is expected in the fourth quarter of 2014.

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.The PPUC entered an Opinion and Order on January 9, 2014 approving the Settlement with limited modifications regarding the frequency of refresher training and reporting obligations.WP filed a letter on January 17, 2014 accepting those modifications and noting its intent to begin implementation of the settlement terms.

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 loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries.The other potentially material items not otherwise discussed above are described under Note 9, 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.

11. 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 for FES and FirstEnergy and as a financing lease for FG.

The Condensed Consolidating Statements of Income and Comprehensive Income for the three months ended March 31, 2014 and 2013, Condensed Consolidating Balance Sheets as of March 31, 2014 and December 31, 2013, and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2014 and 2013, 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.

45

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,797		$	315		$	362		$	(645	)	$	1,829
OPERATING EXPENSES:
Fuel	—			272			47			—			319
Purchased power from affiliates	645			—			64			(645		)	64
Purchased power from non-affiliates	1,025			4			—			—			1,029
Other operating expenses	228			62			150			12			452
Provision for depreciation	2			29			43			—			74
General taxes	21			11			7			—			39
Total operating expenses	1,921			378			311			(633		)	1,977
OPERATING INCOME (LOSS)	(124		)	(63		)	51			(12		)	(148		)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(3		)	(1		)	(1		)	—			(5		)
Investment income	1			1			21			(3		)	20
Miscellaneous income, including net income from equity investees	103			—			—			(103		)	—
Interest expense — affiliates	(3		)	(1		)	(1		)	3			(2		)
Interest expense — other	(14		)	(24		)	(13		)	15			(36		)
Capitalized interest	—			1			11			—			12
Total other income (expense)	84			(24		)	17			(88		)	(11		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(40		)	(87		)	68			(100		)	(159		)
INCOME TAXES (BENEFITS)	(52		)	(31		)	26			1			(56		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	12			(56		)	42			(101		)	(103		)
Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
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	19			—			19			(19		)	19
Other comprehensive income (loss)	12			(4		)	19			(15		)	12
Income taxes (benefits) on other comprehensive income (loss)	4			(2		)	7			(5		)	4
Other comprehensive income (loss), net of tax	8			(2		)	12			(10		)	8
COMPREHENSIVE INCOME	$	20		$	58		$	54		$	(111	)	$	21

46

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,496		$	531		$	440		$	(943	)	$	1,524
OPERATING EXPENSES:
Fuel	—			247			53			—			300
Purchased power from affiliates	1,013			—			62			(943		)	132
Purchased power from non-affiliates	505			1			—			—			506
Other operating expenses	162			74			131			12			379
Provision for depreciation	1			31			44			(1		)	75
General taxes	20			11			6			—			37
Total operating expenses	1,701			364			296			(932		)	1,429
OPERATING INCOME (LOSS)	(205		)	167			144			(11		)	95
OTHER INCOME (EXPENSE):
Loss on debt redemption	(71		)	—			—			—			(71		)
Investment income	1			—			18			(2		)	17
Miscellaneous income, including net income from equity investees	192			1			—			(191		)	2
Interest expense — affiliates	(2		)	(1		)	(1		)	3			(1		)
Interest expense — other	(25		)	(28		)	(15		)	16			(52		)
Capitalized interest	—			—			9			—			9
Total other income (expense)	95			(28		)	11			(174		)	(96		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(110		)	139			155			(185		)	(1		)
INCOME TAXES (BENEFITS)	(112		)	51			58			3			—
INCOME (LOSS) FROM CONTINUING OPERATIONS	2			88			97			(188		)	(1		)
Discontinued operations (net of income taxes of $2) (Note 13)	—			3			—			—			3
NET INCOME	$	2		$	91		$	97		$	(188	)	$	2
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	2		$	91		$	97		$	(188	)	$	2
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(6		)	(5		)	—			5			(6		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available for sale securities	5			—			5			(5		)	5
Other comprehensive income (loss)	(2		)	(5		)	5			—			(2		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(2		)	2			—			(1		)
Other comprehensive income (loss), net of tax	(1		)	(3		)	3			—			(1		)
COMPREHENSIVE INCOME	$	1		$	88		$	100		$	(188	)	$	1

47

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of March 31, 2014	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	583		—		—		—			583
Affiliated companies	278		185		180		(274		)	369
Other	60		18		73		—			151
Notes receivable from affiliated companies	457		449		230		(921		)	215
Materials and supplies	63		148		216		—			427
Derivatives	244		—		—		—			244
Collateral	544		—		—		—			544
Prepayments and other	100		79		—		—			179
	2,329		881		699		(1,195		)	2,714
PROPERTY, PLANT AND EQUIPMENT:
In service	106		6,148		6,925		(383		)	12,796
Less — Accumulated provision for depreciation	30		1,978		3,038		(189		)	4,857
	76		4,170		3,887		(194		)	7,939
Construction work in progress	26		130		1,200		—			1,356
	102		4,300		5,087		(194		)	9,295
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,323		—			1,323
Investment in affiliated companies	5,891		—		—		(5,891		)	—
Other	—		11		—		—			11
	5,891		11		1,323		(5,891		)	1,334
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		105		—		(105		)	—
Customer intangibles	91		—		—		—			91
Goodwill	23		—		—		—			23
Property taxes	—		11		19		—			30
Unamortized sale and leaseback costs	—		—		—		197			197
Derivatives	65		—		—		—			65
Other	72		223		9		(154		)	150
	251		339		28		(62		)	556
	$	8,573	$	5,531	$	7,137	$	(7,342	)	$	13,899
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	120	$	366	$	(22	)	$	465
Short-term borrowings-
Affiliated companies	636		283		—		(919		)	—
Other	550		5		—		—			555
Accounts payable-
Affiliated companies	373		19		240		(305		)	327
Other	183		112		—		—			295
Accrued taxes	3		68		38		(12		)	97
Derivatives	159		—		—		—			159
Other	51		62		21		80			214
	1,956		669		665		(1,178		)	2,112
CAPITALIZATION:
Total equity	5,807		2,343		3,548		(5,865		)	5,833
Long-term debt and other long-term obligations	712		2,094		931		(1,186		)	2,551
	6,519		4,437		4,479		(7,051		)	8,384
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		850			850
Accumulated deferred income taxes	11		—		763		36			810
Asset retirement obligations	—		188		841		—			1,029
Retirement benefits	22		167		—		—			189
Derivatives	36		—		—		—			36
Other	29		70		389		1			489
	98		425		1,993		887			3,403
	$	8,573	$	5,531	$	7,137	$	(7,342	)	$	13,899

48

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2013	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	539		—		—		—			539
Affiliated companies	938		787		227		(916		)	1,036
Other	52		12		17		—			81
Notes receivable from affiliated companies	203		23		683		(909		)	—
Materials and supplies	76		159		213		—			448
Derivatives	165		—		—		—			165
Collateral	136		—		—		—			136
Prepayments and other	52		50		7		—			109
	2,161		1,033		1,147		(1,825		)	2,516
PROPERTY, PLANT AND EQUIPMENT:
In service	104		6,105		6,645		(382		)	12,472
Less — Accumulated provision for depreciation	28		1,953		2,962		(188		)	4,755
	76		4,152		3,683		(194		)	7,717
Construction work in progress	23		148		1,137		—			1,308
	99		4,300		4,820		(194		)	9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,276		—			1,276
Investment in affiliated companies	5,801		—		—		(5,801		)	—
Other	—		11		—		—			11
	5,801		11		1,276		(5,801		)	1,287
ASSETS HELD FOR SALE	—		122		—		—			122
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		131		—		(131		)	—
Customer intangibles	95		—		—		—			95
Goodwill	23		—		—		—			23
Property taxes	—		15		26		—			41
Unamortized sale and leaseback costs	—		—		—		168			168
Derivatives	53		—		—		—			53
Other	81		228		18		(155		)	172
	252		374		44		(118		)	552
	$	8,313	$	5,840	$	7,287	$	(7,938	)	$	13,502
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	367	$	547	$	(23	)	$	892
Short-term borrowings-
Affiliated companies	977		212		151		(909		)	431
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	741		400		362		(738		)	765
Other	94		196		—		—			290
Accrued taxes	204		23		23		(184		)	66
Derivatives	110		—		—		—			110
Other	70		63		18		46			197
	2,197		1,265		1,101		(1,808		)	2,755
CAPITALIZATION:
Total equity	5,312		2,283		3,493		(5,776		)	5,312
Long-term debt and other long-term obligations	712		1,860		742		(1,184		)	2,130
	6,024		4,143		4,235		(6,960		)	7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		858			858
Accumulated deferred income taxes	32		—		736		(27		)	741
Asset retirement obligations	—		187		828		—			1,015
Retirement benefits	22		163		—		—			185
Derivatives	14		—		—		—			14
Other	24		82		387		(1		)	492
	92		432		1,951		830			3,305
	$	8,313	$	5,840	$	7,287	$	(7,938	)	$	13,502

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(450	)	$	87		$	51		$	—		$	(312	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			235			182			—			417
Short-term borrowings, net	209			72			—			(161		)	120
Equity contribution from parent	500			—			—			—			500
Redemptions and Repayments-
Long-term debt	—			(248		)	(197		)	—			(445		)
Short-term borrowings, net	—			—			(151		)	151			—
Other	(1		)	(2		)	(1		)	—			(4		)
Net cash provided from (used for) financing activities	708			57			(167		)	(10		)	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(28		)	(268		)	—			(298		)
Nuclear fuel	—			—			(55		)	—			(55		)
Proceeds from asset sales	—			307			—			—			307
Sales of investment securities held in trusts	—			—			423			—			423
Purchases of investment securities held in trusts	—			—			(438		)	—			(438		)
Loans to affiliated companies, net	(254		)	(425		)	454			10			(215		)
Other	(2		)	2			—			—			—
Net cash provided from (used for) investing activities	(258		)	(144		)	116			10			(276		)
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			2			—			—			2
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

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FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(529	)	$	298		$	36		$	—		$	(195	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	894			—			586			(778		)	702
Redemptions and Repayments-
Long-term debt	(369		)	(107		)	—			—			(476		)
Short-term borrowings, net	—			(76		)	—			76			—
Tender premiums	(67		)	—			—			—			(67		)
Other	—			(1		)	—			—			(1		)
Net cash provided from financing activities	458			(184		)	586			(702		)	158
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(138		)	(74		)	—			(217		)
Nuclear fuel	—			—			(27		)	—			(27		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			252			—			252
Purchases of investment securities held in trusts	—			—			(265		)	—			(265		)
Loans to affiliated companies, net	75			7			(508		)	702			276
Other	1			—			—			—			1
Net cash used for investing activities	71			(114		)	(622		)	702			37
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3

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12. SEGMENT INFORMATION

FirstEnergy continues to have three reportable operating segments - Regulated Distribution, Regulated Transmission and Competitive Energy Services. The external reporting is consistent with the internal financial reporting used by FirstEnergy’s Chief Executive Officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources.

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 3,780 MWs of generation capacity.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and the regulatory asset associated with the abandoned PATH project. 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 approximately14,000MWs of capacity, including885MWs of capacity subject to RMR arrangements with PJM.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 fuel, 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)
March 31, 2014
External revenues	$	2,552	$	187	$	1,522		$	(35	)	$	(37	)	$	4,189
Internal revenues	—		—		249			—			(249		)	—
Total revenues	2,552		187		1,771			(35		)	(286		)	4,189
Depreciation, amortization and deferrals	131		33		91			11			—			266
Investment income	15		—		14			3			(10		)	22
Interest expense	151		25		46			43			—			265
Income taxes (benefits)	125		30		(73		)	(26		)	(8		)	48
Income (loss) from continuing operations	214		51		(124		)	(32		)	13			122
Discontinued operations, net of tax	—		—		86			—			—			86
Net income (loss)	214		51		(38		)	(32		)	13			208
Total assets	27,742		5,584		17,445			457			—			51,228
Total goodwill	5,092		526		800			—			—			6,418
Property additions	269		217		318			17			—			821
March 31, 2013
External revenues	$	2,212	$	176	$	1,414		$	(27	)	$	(52	)	$	3,723
Internal revenues	—		—		216			—			(216		)	—
Total revenues	2,212		176		1,630			(27		)	(268		)	3,723
Depreciation, amortization and deferrals	202		29		110			11			—			352
Investment income	18		—		10			1			(11		)	18
Interest expense	135		23		73			27			—			258
Income taxes (benefits)	126		31		(24		)	(19		)	—			114
Income (loss) from continuing operations	210		51		(42		)	(30		)	3			192
Discontinued operations, net of tax	—		—		4			—			—			4
Net income (loss)	210		51		(38		)	(30		)	3			196
Total assets	26,943		4,722		18,328			431			—			50,424
Total goodwill	5,025		526		896			—			—			6,447
Property additions	436		89		283			18			—			826

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13. DISCONTINUED OPERATIONS

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. The asset purchase agreement was entered into on August 23, 2013, and amended and restated as of September 4, 2013. On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $394 million (FES - $307 million). The carrying value of the assets sold was $235 million (FES - $122 million), including goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold.

Pre-tax income for the hydroelectric facilities of $155 million and $6 million (FES - $186 million and $5 million) for the three months ended March 31, 2014 and 2013, respectively, were reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Included in income from discontinued operations in the three months ended March 31, 2014, was a pre-tax gain on the sale of assets of $142 million (FES - $177 million). Revenues for the hydroelectric facilities of $5 million and $6 million (FES - $5 million and $6 million) for the three months ended March 31, 2014 and 2013, 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 first quarter of 2014 was $208 million, or basic earnings of $0.50 per share of common stock ($0.49 diluted), compared with net income of $196 million, or basic and diluted earnings of $0.47 per share of common stock in the first quarter of 2013. Net income and changes by segment are summarized below:

	Three Months Ended March 31
	2014			2013			Increase (Decrease)
	(In millions, except per share)
Net Income (Loss) By Segment:
Regulated Distribution	$	214		$	210		$	4
Regulated Transmission	51			51			—
Competitive Energy Services	(38		)	(38		)	—
Other and reconciling adjustments	(19		)	(27		)	8
FirstEnergy Corp.	$	208		$	196		$	12
Earnings per share - Basic	$	0.50		$	0.47		$	0.03
Earnings per share - Diluted	$	0.49		$	0.47		$	0.02

Three months ended March 31, 2014 compared to the three months ended March 31, 2013

The Regulated Distribution segment’s earnings were impacted by the following:

• Higher distribution deliveries of 5.9% across all customer classes with increases of 10.8% and 5.5% in the residential and commercial class, respectively, primarily reflecting increased weather-related usage resulting from heating degree days that were 17% above 2013.

• Increased regulated generation earnings primarily associated with the Harrison/Pleasants asset transfer in October of 2013. Currently, the Harrison Plant is subject to a temporary surcharge including a return on and return of the plant costs.

• Increased distribution operation and maintenance activities and higher non-deferred storm related restoration expenses.

• Increased depreciation expense, primarily associated with a higher asset base.

• Increased interest expense primarily associated with the financing of the Harrison Plant.

The Regulated Transmission segment's earnings were impacted by the following:

• Higher revenue at ATSI and TrAIL primarily resulting from its annual rate filing effective June 2013.

• Increased operating expenses principally due to higher property taxes, depreciation and operating and maintenance expenses.

The Competitive Energy Services segment's earnings were impacted by the following:

• Higher net cost to serve additional retail load as a result of increased customer demand, primarily due to extreme weather conditions, and higher wholesale energy prices.

• Additional purchased power at higher prices resulting from the timing of unplanned outages and derates.

• Additional purchased power resulting from planned outages.

• Higher PJM ancillary service charges for transmission system reliability, partially offset by "pass-through" revenues to commercial and industrial customers, as well as increased capacity expense primarily due to higher capacity rates.

• Reduced fuel and operating expenses, such as operating and maintenance, depreciation and general taxes, associated with the Harrison/Pleasants asset transfer and the deactivation of certain power plants during 2013, partially offset by the cost of replacing that generation.

• Lower interest expense associated with the redemption and repurchase of long-term debt at FES and AE Supply in 2013.

• Other items impacting the Competitive Energy Services Segment's earnings include the following pre-tax changes:

◦ Loss on debt redemptions decreased $110 million primarily related to debt repurchased in the first quarter of 2013.

◦ Gains related to commodity mark-to-market adjustments increased $21 million.

◦ An increase of $146 million from discontinued operations (before income taxes) primarily associated with a $142 million (pre-tax) gain on the sale of certain hydro facilities.

◦ Costs associated with plant closings increased $26 million primarily related to fuel contract terminations.

55

◦ Amortization expense associated with purchase accounting adjustments on commodity contracts decreased $9 million.

◦ PJM charges associated with deactivated plants decreased $15 million.

The Other segment's earnings were impacted by the following:

• A lower effective income tax rate primarily resulting from an increase in AFUDC equity flow-through, changes in state apportionment factors and the elimination of certain future tax liabilities associated with basis differences.

• Increased interest expense due to the issuance of $1.5 billion of FE senior unsecured notes in March of 2013.

Executive Summary

FirstEnergy holds a large and diverse mix of assets, featuring an electric distribution service area and transmission footprint that are among the largest in the nation, as well as a significant competitive generation fleet and retail business.

FirstEnergy’s competitive operations, the Competitive Energy Services segment, has been challenged by prolonged weak demand for power, low capacity payments and declining energy prices. Recently, market dynamics within PJM, the region served by the Competitive Energy Services segment's generating fleet, have been unpredictable. Capacity prices resulting from recent annual auctions have produced prices for generators that have been lower than expected. FirstEnergy believes that a thorough review of the rules associated with the capacity auctions, as well as the broader functioning of the PJM market, are necessary to effectuate a robust competitive market. FirstEnergy intends to actively participate in this dialogue at both PJM and FERC.

As a result of the challenging competitive environment, FirstEnergy has begun redirecting its growth strategy to pursue more predictable and sustainable long-term growth opportunities in its regulated businesses.

The centerpiece of this strategy is a $4.2 billion “Energizing the Future” investment plan beginning in 2014 through 2017 to upgrade and expand the transmission system owned by FirstEnergy’s Regulated Transmission segment. This program is focused on rebuilding the transmission system, starting with ATSI's system and moving east across FirstEnergy's service territory over time. Also included in the investment are projects that enhance system performance, physical security and add operating flexibility and capacity. These activities began in the first quarter of 2014. FirstEnergy expects to fund these investments through a combination of debt, previously announced equity issuances through stock investment and employee benefit plans, and cash. Due to their investments, Regulated Transmission's earnings are expected to grow modestly over the next two years and then accelerate as the investments are fully recognized in rates. In total, FirstEnergy has identified at least $7 billion in transmission investment opportunities across the 24,000 mile transmission system, making this a continuing platform for growth in the years ahead.

In the territory served by FirstEnergy’s distribution segment, Regulated Distribution, the economy has struggled to recover from the recession, and there continues to be weak demand for electricity as evidenced by flat distribution sales over the last three years. However, the location of the Marcellus and Utica shale gas region provides optimism for growth in this portion of Regulated Distribution’s service territory over the long term. More than 200 MW of new industrial demand associated with shale gas activity has already come online in FirstEnergy's region, with more than 400 MW of additional planned expansion at customer facilities. These projects alone are expected to result in more industrial growth over the next two years, and a robust pipeline of mid-stream projects represent further opportunities for additional growth, as well as the potential for growth in the residential class.

FirstEnergy is also pursuing regulatory initiatives across its utility footprint, including a rate case application in West Virginia filed in April 2014, as well as the current rate proceeding in New Jersey. FirstEnergy expects to pursue additional targeted rate filings over the next several years as part of its focus on driving stable and predictable growth at its Regulated Distribution segment in the future.

While the Competitive Energy Services segment is not identified as a growth driver in the near term, FirstEnergy is focused on maintaining the value of its competitive business. FirstEnergy has reduced the size and shifted the mix of its generating assets, as well as reduced operating expenses and capital expenditures. As a result, the remaining competitive fleet is more cost-effective, efficient and environmentally sound. While FirstEnergy cannot predict if or when a power price recovery may occur, FirstEnergy believes it has taken appropriate action over the last two years to reposition this business for such a recovery.

In alignment with FirstEnergy’s strategy to reposition the Regulated Transmission and Regulated Distribution segments and preserve the competitive business, FirstEnergy will also focus on reducing balance sheet risk, maintaining investment grade metrics, and improving the business risk profile at each of our businesses. Specifically, at the regulated businesses, authority has been obtained for various regulated distribution and transmission subsidiaries to issue or refinance debt. Finally, at the competitive business, FirstEnergy completed the sale of certain hydro assets for approximately $394 million on February 12, 2014. The actions taken in 2013 and those planned for 2014 are expected to support a regulated investment strategy.

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Operational Matters

Nuclear Operations

On February 1, 2014 the Davis-Besse Nuclear Power station entered an outage to install two new steam generators, replace about a third of the unit’s 177 fuel assemblies and perform numerous safety inspections and preventative maintenance activities. These activities, including amounts spent in prior years in preparation for this outage, represent an investment of approximately $600 million by FES at Davis Besse.During the preliminary stages of the outage an area of concrete that was not filled to the expected thickness within the shield building wall was discovered at the top of the temporary construction opening that was created as part of the 2011 outage.The 2011 temporary construction opening was created to install the new reactor head. FENOC has assessed the as-found condition of the concrete and has determined the shield building would have performed its design functions.This condition within the shield building wall was repaired to conform to its original design configuration.

Beaver Valley Unit 1 returned to service January 29, 2014, following replacement and testing of its main unit transformer, which experienced a fault on January 6, 2014 that resulted in an automatic shutdown of the Unit.

On April 19, 2014, Beaver Valley Unit 2 shut down for scheduled refueling and maintenance. While the unit is off line, one-third of the reactor's 157 fuel assemblies will be replaced and safety inspections will be conducted, including inspections of the unit's reactor vessel head, turbine and electrical generator. In addition, preventative maintenance expected to support continued safe and reliable operations will be performed on major components including pumps, valves and the cooling tower. Beaver Valley Unit 2 will also undertake a number of projects in preparation for replacement of the unit's three steam generators and reactor head in 2017. These activities include installation of a heavy-duty crane system in containment and measurements to support planning for the future replacement.

January 2014 Extreme Weather and Market Conditions

During January 2014, given higher customer usage associated with extreme weather conditions and unit unavailability, including the Beaver Valley Unit 1 outage, FirstEnergy's Competitive Energy Services segment (including FES) was required to purchase higher volumes of power. These extreme weather events caused an increase in the demand for electricity and natural gas throughout the PJM zones. In order to maintain system reliability, PJM incurred higher ancillary service costs, such as synchronous and operating reserves, throughout these extreme conditions. Approximately $800 million in ancillary service charges for the month of January 2014 were billed to all LSEs serving customers throughout the PJM region based on load served, including FES. Certain of these costs are considered a "pass-through" event under existing contracts and revenue of approximately $33 million was recognized associated with commercial and industrial customers in the three month period ended March 31, 2014.

Sammis Planned Outage

In late March of 2014, Sammis Unit 7 came off line to start a planned maintenance outage. Key projects planned for the outage include boiler tubing repairs, blade replacements and other turbine work, a full rewind of the main generator, air heater basket replacements and a booster fan hub rebuild. Other work may take place depending on the outcome of testing scheduled for this outage.

Employee Relations

On April 14, 2014, a lock-out of UWUA Local 180 members ended. The 20-week lock-out started on November 25, 2013. The employees returned to work under the terms of PN's Last, Best and Final Offer of November 6, 2013. The Last, Best and Final Offer contains wage increases, increases in shift premiums and meal allowances, and additional operational improvements, such as a new job classification intended to increase customer service and efficiency. Employees were reinstated to the positions they held prior to the lock-out. The collective bargaining agreement with IBEW Local 272, which represents approximately 300 employees at the Bruce Mansfield Plant expired on February 16, 2014. The collective bargaining agreement with Local 102, which represents 700 employees at WP and PE, expired on April 30, 2013. FirstEnergy continues to engage in negotiations with each of Local 180, 272, and 102, and work continuation plans are in place in the event of a work stoppage.

Regulatory Matters

JCP&L Rate Filing Update

On February 24, 2014, a Stipulation was filed with the NJBPU by JCP&L, the Division of Rate Counsel and NJBPU Staff which will allow recovery of $736 million of JCP&L’s $744 million of costs related to the significant weather events of 2011 and 2012. On March 19, 2014, the NJBPU issued an order stating that the stipulation was reasonable and in accordance with the law, that the stipulation struck an appropriate balance between the needs of the customers and JCP&L, and that the 2011 and 2012 major storm costs may be recovered from ratepayers. The manner for recovery of 2011 costs will be decided within the current distribution rate case however the mechanism for recovery of the 2012 storm costs remains to be determined. On March 21, 2014, briefs on recovery of the 2012 storm costs were filed at the NJBPU by JCP&L and the Division of Rate Counsel. Reply briefs were filed on April 1, 2014.

57

WV Rate Filing

On April 30, 2014, MP and PE filed a rate case requesting a base rate increase of approximately $96 million, or 9.3%. The filing also included a surcharge to recover costs of MP's and PE's vegetation management program in the amount of approximately $48 million. The proposed total rate increase request, including the cost of the vegetation management program, is approximately $144 million, or 14%. MP and PE anticipate a decision from the WVPSC in February 2015.

Financial Matters

Hydro Asset Sales

On February 12, 2014, FirstEnergy completed the sale of 11 hydroelectric power stations to Harbor Hydro Holdings, LLC, a subsidiary of LS Power Equity Partners II, LP, for approximately $394 million. The hydroelectric power stations included in this sale were owned by FG, AE Supply and Green Valley Hydro, LLC and had a total capacity of 527 MW. The sale includes Seneca Pumped Storage (451 MW) in Warren, Pa.; Allegheny Lock & Dam 5 (6 MW) in Schenley, Pa.; Allegheny Lock & Dam 6 (7 MW) in Ford City, Pa.; Lake Lynn (52 MW) in Lake Lynn, Pa.; Millville (3 MW) in Millville, W. Va.; Dam 4 (2 MW) in Shepherdstown, W. Va.; Dam 5 (1.2 MW) in Falling Waters, W.Va.; Warren (750 kW) in Front Royal, Va.; Luray (1.6 MW) in Luray, Va.; and Shenandoah and Newport (860 kW and 1.4 MW, respectively) in Shenandoah, Va. The 35 employees at these power stations were retained by the new owner. Pre-tax income for the hydroelectric facilities of $155 million and $6 million (FES - $186 million and $5 million) for the three months ended March 31, 2014 and 2013, respectively, were reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Pre-tax income for the three months ended March 31, 2014 primarily relates to the gain on sale of $142 million (FES - $177 million).

Revolving Credit Facilities and Debt Activity

On March 31, 2014, FE, FES, AE Supply, FET and FE's other borrower subsidiaries entered into extensions and amendments to thethreeexisting multi-year syndicated revolving credit facilities.Each facility was extended until March 31, 2019.The FE facility was amended to increase the lending banks' commitments under the facility by $1 billion to a total of $3.5 billionand to increase the individual borrower sublimit for FE by $1 billionto a total of $3.5 billion.The FES/AE Supply facility was amended to decrease the lending banks' commitments by $1 billion to a total of $1.5 billion. The lending banks' commitments under the FET facility remain at $1 billion and that facilitywas amended to increase ATSI's individual borrower sublimit to $500 millionfrom $100 millionand TrAIL's individual borrower sublimit to $400 millionfrom $200 million. FirstEnergy expensed approximately $5 million(FES - $3 million)of unamortized debt expense as a result of the amendments.The amount was included in Loss on Debt Redemptions in the Consolidated Statement of Income in the first quarter of 2014.

On March 31, 2014, FE executed, and fully utilized, a new $1 billionvariable rate term loan credit agreement with a maturity date of March 31, 2019.The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances.

During the first quarter of 2014, FG and NG remarketed approximately $417 millionof PCRBs previously held by the companies.Of the total, $182 million was remarketed with a fixed interest rate of4%per annum with a mandatory put date of June 3, 2019 and $235 millionwas remarketed with a fixed interest rate of3.75%per annum with a mandatory put date of December 3, 2018.

In addition, in the first quarter of 2014, FG and NG repurchased approximately $197million and $16 millionof PCRBs, respectively, which were subject to a mandatory tender. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

On April 1, 2014, PN and ME repurchased approximately $45 million and $29 millionof PCRBs, respectively, which were subject to a mandatory put on such date. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

During the first quarter of 2014, AE Supply returned $500 million of capital to FE Corp. Additionally, FE Corp. contributed $500 million of equity to FES.

FIRSTENERGY’S BUSINESS

FirstEnergy continues to have three reportable operating segments - Regulated Distribution, Regulated Transmission and Competitive Energy Services. The external reporting is consistent with the internal financial reporting used by FirstEnergy’s Chief Executive Officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources.

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,

58

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 3,780 MWs of generation capacity.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and the regulatory asset associated with the abandoned PATH project. 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 approximately14,000MWs of capacity, including885MWs of capacity subject to RMR arrangements with PJM.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 fuel, 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 March 31, 2014, committed sales for calendar year 2014 are at 98% of the 98.8 million MWH target. For the nine months from April to December 2014, supply from expected generation and committed purchases are approximately 103% of the committed sales under normal weather conditions. As of March 31, 2014, committed sales for 2015 and 2016 are approximately 56 million MWHs and 32 million MWHs, respectively. On average, the Competitive Energy Services segment expects to produce approximately 75 - 80 million MWHs of electricity annually. The Competitive Energy Services segment fulfills the difference between committed sales, which is based on estimated customer usage, assuming normal weather, and electricity generated, through forward contracts and options, generation produced by its peaking units and purchasing power on the wholesale market.

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 12, 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 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 segments. A reconciliation of segment financial results is provided in Note 12, Segment Information, of the Combined Notes to Consolidated Financial Statements. Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications include, but are not limited to, the classification of discontinued operations associated with the sale of hydro assets discussed in additional detail in Note 13, Discontinued Operations.

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Summary of Results of Operations — First Quarter 2014 Compared with First Quarter 2013

Financial results for FirstEnergy’s business segments in the first quarter of 2014 and 2013 were as follows:

First Quarter 2014 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,501		$	187		$	1,474		$	(56	)	$	4,106
Other	51			—			48			(16		)	83
Internal	—			—			249			(249		)	—
Total Revenues	2,552			187			1,771			(321		)	4,189
Operating Expenses:
Fuel	153			—			464			—			617
Purchased power	981			—			723			(249		)	1,455
Other operating expenses	627			34			609			(88		)	1,182
Provision for depreciation	162			30			91			11			294
Amortization (deferral) of regulatory assets, net	(31		)	3			—			—			(28		)
General taxes	187			17			54			13			271
Total Operating Expenses	2,079			84			1,941			(313		)	3,791
Operating Income (Loss)	473			103			(170		)	(8		)	398
Other Income (Expense):
Loss on debt redemptions	—			—			(7		)	—			(7		)
Investment income	15			—			14			(7		)	22
Interest expense	(151		)	(25		)	(46		)	(43		)	(265		)
Capitalized interest	2			3			12			5			22
Total Other Expense	(134		)	(22		)	(27		)	(45		)	(228		)
Income (Loss) From Continuing Operations Before Income Taxes	339			81			(197		)	(53		)	170
Income taxes (benefits)	125			30			(73		)	(34		)	48
Income (Loss) From Continuing Operations	214			51			(124		)	(19		)	122
Discontinued Operations, net of tax	—			—			86			—			86
Net Income (Loss)	$	214		$	51		$	(38	)	$	(19	)	$	208

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First Quarter 2013 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,155		$	176		$	1,372		$	(44	)	$	3,659
Other	57			—			42			(35		)	64
Internal	—			—			216			(216		)	—
Total Revenues	2,212			176			1,630			(295		)	3,723
Operating Expenses:
Fuel	87			—			543			—			630
Purchased power	875			—			287			(216		)	946
Other operating expenses	415			30			526			(89		)	882
Provision for depreciation	144			28			110			11			293
Amortization of regulatory assets, net	58			1			—			—			59
General taxes	182			12			60			11			265
Total Operating Expenses	1,761			71			1,526			(283		)	3,075
Operating Income	451			105			104			(12		)	648
Other Income (Expense):
Loss on debt redemptions	—			—			(117		)	—			(117		)
Investment income	18			—			10			(10		)	18
Interest expense	(135		)	(23		)	(73		)	(27		)	(258		)
Capitalized interest	2			—			10			3			15
Total Other Expense	(115		)	(23		)	(170		)	(34		)	(342		)
Income (Loss) From Continuing Operations Before Income Taxes	336			82			(66		)	(46		)	306
Income taxes (benefits)	126			31			(24		)	(19		)	114
Income (Loss) From Continuing Operations	210			51			(42		)	(27		)	192
Discontinued Operations, net of tax	—			—			4			—			4
Net Income (Loss)	$	210		$	51		$	(38	)	$	(27	)	$	196

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Changes Between First Quarter 2014 and First Quarter 2013 Financial Results Increase (Decrease)	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	346		$	11		$	102		$	(12	)	$	447
Other	(6		)	—			6			19			19
Internal	—			—			33			(33		)	—
Total Revenues	340			11			141			(26		)	466
Operating Expenses:
Fuel	66			—			(79		)	—			(13		)
Purchased power	106			—			436			(33		)	509
Other operating expenses	212			4			83			1			300
Provision for depreciation	18			2			(19		)	—			1
Amortization (deferral) of regulatory assets, net	(89		)	2			—			—			(87		)
General taxes	5			5			(6		)	2			6
Total Operating Expenses	318			13			415			(30		)	716
Operating Income (Loss)	22			(2		)	(274		)	4			(250		)
Other Income (Expense):
Loss on debt redemptions	—			—			110			—			110
Investment income	(3		)	—			4			3			4
Interest expense	(16		)	(2		)	27			(16		)	(7		)
Capitalized interest	—			3			2			2			7
Total Other Expense	(19		)	1			143			(11		)	114
Income (Loss) From Continuing Operations Before Income Taxes	3			(1		)	(131		)	(7		)	(136		)
Income taxes (benefits)	(1		)	(1		)	(49		)	(15		)	(66		)
Income (Loss) From Continuing Operations	4			—			(82		)	8			(70		)
Discontinued Operations, net of tax	—			—			82			—			82
Net Income (Loss)	$	4		$	—		$	—		$	8		$	12

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Regulated Distribution — First Quarter 2014 Compared with First Quarter 2013

Net income increased $4 million in the first quarter of 2014 compared to the same period of 2013, as more fully described below.

Revenues —

The $340 millionincrease in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase
Revenues by Type of Service	2014		2013		(Decrease)
	(In millions)
Distribution services	$	983	$	972	$	11
Generation sales:
Retail	1,104		1,005		99
Wholesale	254		62		192
Total generation sales	1,358		1,067		291
Transmission	160		116		44
Other	51		57		(6		)
Total Revenues	$	2,552	$	2,212	$	340

The increase in distribution services revenue is primarily related to higher electric distribution MWH deliveries as described below and an increase in the Ohio Companies' DCR rider revenues, partially offset by a decrease in revenues from the ME and PN NUG riders as a result of the expiration of certain NUG contracts in 2013. Distribution deliveries increased by 5.9% in the first quarter of 2014 compared to the same period of 2013. Distribution deliveries by customer class are summarized in the following table:

	Three Months Ended March 31		Increase
Electric Distribution MWH Deliveries	2014	2013	(Decrease)
	(In thousands)
Residential	16,570	14,956	10.8	%
Commercial	11,028	10,449	5.5	%
Industrial	12,700	12,623	0.6	%
Other	144	147	(2.0	)%
Total Electric Distribution MWH Deliveries	40,442	38,175	5.9	%

Higher deliveries to residential and commercial customers primarily reflect increased weather-related usage resulting from heating degree days that were 17% above 2013, and 19% above normal. In the industrial sector, increased sales to steel, automotive and shale gas customers were partially offset by lower sales to chemical customers. For 2014, FirstEnergy continues to expect an increase in industrial sales, with a majority of that increase resulting from shale gas activities. Additionally, FirstEnergy expects growth in the industrial sector beyond 2014 for potential shale gas projects. As new 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 $291 millionincrease in generation revenues for the first quarter of 2014 compared to the same period of 2013:

Source of Change in Generation Revenues	Increase
	(In millions)
Retail:
Effect of increase in sales volumes	$	39
Change in prices	60
	99
Wholesale:
Effect of increase in sales volumes	82
Change in prices	110
	192
Increase in Generation Revenues	$	291

The increase in retail generation sales volumes was primarily due to increased weather-related usage, as described above, and reduced customer shopping in Maryland, partially offset by higher shopping in other jurisdictions. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 80% from 79% for the Ohio Companies, 65% from 63% for the Pennsylvania Companies and 53% from 52% for JCP&L, and decreased to 41% from 43% for PE. The increase in retail generation prices reflects higher Pennsylvania auction prices, 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. Additionally, the impact of MP's Temporary Transaction Surcharge associated with the Harrison/Pleasants asset transfer was offset by a rate reduction associated with the recovery of ENECs.

The increase in wholesale generation revenues of $192 million in the first quarter of 2014 reflects increased energy prices associated with extreme weather and market conditions in January 2014 and increased volume related to the Harrison/Pleasants asset transfer.

The increase in transmission revenues of $44 million reflects higher FTR revenues at MP related to the extreme weather and market conditions in January 2014 and an increase in the Ohio Companies' NMB transmission rider revenues, partially offset by 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 $318 million primarily due to the following:

• Fuel expense was $66 million higher in 2014 primarily related to increased generation as a result of the Harrison/Pleasants asset transfer.

• Purchased power costs were $106 million higher in 2014 primarily related to higher unit power supply costs during the first quarter of 2014 compared to the same period of 2013, partially offset by lower required volumes as a result of the Harrison/Pleasants asset transfer.

Source of Change in Purchased Power	Increase(Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to increased unit costs	$	117
Change due to decreased volumes	(45		)
	72
Purchases from affiliates:
Change due to increased unit costs	30
Change due to increased volumes	3
	33
Increase in costs deferred	1
Increase in Purchased Power Costs	$	106

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• Other operating expenses increased $212 million primarily due to:

• Higher transmission expenses of $125 million primarily due to PJM transmission costs associated with higher congestion rates at MP as a result of extreme weather and market conditions in January 2014 and higher transmission volumes as a result of the Harrison/Pleasants asset transfer. The differences between current transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.

• Higher distribution operating and maintenance expenses of $64 million primarily due to higher maintenance activities and storm-related restoration costs, including $22 million associated with Winter Storm Nika during the first quarter of 2014 as well as higher pension related costs.

• Higher energy efficiency expenses of $9 million in Pennsylvania primarily related to smart meter implementation, which are recovered through rates, and

• Increased regulated generation operating and maintenance expenses of $14 million, reflecting increased costs associated with the Harrison/Pleasants asset transfer and a planned outage at Fort Martin.

• Depreciation expense increased $18 million due to a higher asset base, including $7 million associated with the Harrison/Pleasants asset transfer.

• Amortization (deferral) of regulatory assets decreased $89 million primarily due to higher storm cost deferrals, including $15 million related to Winter Storm Nika, lower default generation service costs recovery in Pennsylvania, a reduction of NUG costs recovery at ME and PN, and increased deferral of energy efficiency program costs, partially offset by lower transmission cost deferrals in Ohio and the completion of marginal transmission loss refunds at ME and PN.

• General taxes increased $5 million primarily due to higher property taxes and an increase in the West Virginia business and occupation tax as a result of the Harrison/Pleasants asset transfer.

Other Expense —

Other expense increased $19 million in the first quarter of 2014 primarily due to higher interest expense at MP as a result of financing the Harrison/Pleasants asset transfer and at JCP&L resulting from new debt issuances in 2013.

Regulated Transmission — First Quarter 2014 Compared with First Quarter 2013

Net income was $51 million in the first quarter of 2014 compared to $51 million in the same period of 2013.

Revenues —

Total revenues increased $11 million principally at ATSI and TrAIL associated with increased rates resulting from their annual rate filing effective June 2013.

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

	Three Months Ended March 31				Increase
Revenues by Transmission Asset Owner	2014		2013		(Decrease)
	(In millions)
ATSI	$	56	$	49	$	7
TrAIL	53		48		5
PATH	4		5		(1		)
Utilities	74		74		—
Total Revenues	$	187	$	176	$	11

Operating Expenses —

Total operating expenses increased $13 million principally due to higher property tax, depreciation and other expenses.

Competitive Energy Services — First Quarter 2014 Compared with First Quarter 2013

Net income was unchanged in the first quarter of 2014, compared to the same period of 2013, as more fully described below.

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Revenues —

Total revenues increased by $141 million in the first quarter of 2014, compared to the same period of 2013, primarily due to increased Transmission revenue and increased sales volumes in Governmental Aggregation, Mass Market, and POLR and Structured Sales channels. Revenues were also impacted by higher unit prices compared to 2013 as a result of increased channel pricing and ancillary pass-through revenues associated with PJM expenses incurred in January 2014.

The increase in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase (Decrease)
Revenues by Type of Service	2014		2013
	(In millions)
Direct	$	713	$	710	$	3
Governmental Aggregation	320		292		28
Mass Market	142		117		25
POLR and Structured	363		351		12
Wholesale	67		71		(4		)
Transmission	118		47		71
Other	48		42		6
Total Revenues	$	1,771	$	1,630	$	141

	Three Months Ended March 31		Increase (Decrease)
MWH Sales by Channel	2014	2013
	(In thousands)
Direct	12,841	13,614	(5.7	)%
Governmental Aggregation	5,769	5,386	7.1	%
Mass Market	2,126	1,780	19.4	%
POLR and Structured	8,172	6,817	19.9	%
Wholesale	11	228	(95.2	)%
Total MWH Sales	28,919	27,825	3.9	%

The following table summarizes the price and volume factors contributing to changes in revenues:

	Source of Change in Revenues
	Increase (Decrease)
MWH Sales Channel:	Sales Volumes			Prices			Gain on Settled Contracts		Capacity Revenue			Total
	(In millions)
Direct	$	(40	)	$	43		$	—	$	—		$	3
Governmental Aggregation	21			7			—		—			28
Mass Market	23			2			—		—			25
POLR and Structured Sales	68			(56		)	—		—			12
Wholesale	(6		)	—			3		(1		)	(4		)

The increase in Direct revenues of $3 million resulted from higher unit prices, partially offset by lower sales volumes from large commercial and industrial customers. Direct sales volumes decreased due to Competitive Energy Services’ strategy to be more selective in customers targeted in response to the current market environment. The increase in Governmental Aggregation revenues of $28 million primarily reflects increased weather-related usage resulting from heating degree days that were 17% higher than the first quarter of 2013 and higher unit prices. The increase in Mass Market of $25 million resulted from the acquisition of new customers

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primarily in Ohio and Pennsylvania, increased weather-related usage and higher unit prices. The Direct, Governmental Aggregation and Mass Market customer base remained at 2.7 million customers as of March 31, 2014. Higher unit prices in each of the above sales channels resulted from increased channel pricing. Additionally, higher Direct unit prices were impacted by approximately $33 million of ancillary pass-through revenues associated with PJM expenses incurred in January 2014 as more fully described below.

The increase in POLR and structured revenues of $12 million was due to higher POLR and structured sales volumes primarily as a result of increased weather-related usage described above. Lower structured unit prices were primarily due to extreme weather and market conditions in January 2014 that reduced the gains on various structured financial sales contracts, partially offset by higher POLR rates associated with recent auctions.

Wholesale revenues decreased $4 million, primarily due to a 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 Harrison/Pleasants asset transfer and the deactivation of certain power plants in 2013, and increased sales volume requirements discussed above.

Transmission revenue increased $71 million due to higher congestion and ancillary revenue associated with additional retail load.

Other revenue increased $6 million primarily due to higher lease revenues from additional repurchased equity interests in affiliated sale and leasebacks since the first quarter of 2013. Competitive Energy Services earns lease revenue associated with the equity interests it purchased.

Operating Expenses —

Total operating expenses increased by $415 million in the first quarter of 2014 due to the following:

• Fuel costs decreased $79 million primarily due to lower volumes associated with the Harrison/Pleasants asset transfer, the deactivation of certain power plants in 2013 and lower nuclear generation due to outages, partially offset by higher unit prices and the termination of a coal contract for $18 million.

• Purchased power costs increased $436 million due to higher volumes ($267 million), increased prices ($124 million), and higher capacity expenses ($45 million). Higher purchased volumes were primarily due to increased sales volume requirements and lower available generation due to outages, the Harrison/Pleasants asset transfer and the deactivation of certain power plants in 2013. The increase in prices was primarily a result of extreme weather and market conditions in January 2014, partially offset by net gains on financially settled contracts. Increased customer demand that was unhedged and replacement power requirements due to the timing of unplanned outages and derates contributed to purchasing additional volumes at these higher prices. The increase in capacity expense was the result of higher capacity rates primarily in the MAAC zone and increased sales volumes.

• Fossil operating costs decreased $51 million due primarily to lower labor costs resulting from previously deactivated units, the Harrison/Pleasants asset transfer and fewer planned outage days in the first quarter of 2014 as compared to the same period of 2013.

• Nuclear operating costs increased $15 million as a result of higher contractor, materials and equipment costs associated with the refueling outage at Davis-Besse that began on February 1, 2014. In the same period of 2013, there was a refueling outage at Perry that began on March 18, 2013.

• Transmission expenses increased $133 million due primarily to higher operating reserve and market-based ancillary costs associated with the extreme weather and market conditions in January 2014. A portion of these ancillary charges from PJM, which were for system reliability, are able to be passed through to commercial and industrial customers. Additionally, effective June 1, 2013, network expenses associated with POLR sales in Pennsylvania became the responsibility of suppliers.

• General taxes decreased $6 million due primarily to lower payroll taxes as a result of lower labor costs noted above and the Harrison/Pleasants asset transfer, partially offset by higher gross receipts taxes.

• Depreciation expense decreased $19 million primarily due to a reduction in the asset base as a result of the plant deactivations and the Harrison/Pleasants asset transfer noted above.

• Other operating expenses decreased $14 million primarily due to a reduction in mark-to-market expenses on commodity contract positions, partially offset by higher leasehold costs from the Ohio Companies due to increased generation by Perry and increased agent fees associated with the retail business.

Other Expense —

Total other expense in the first quarter of 2014 decreased $143 million compared to the same period of 2013 due to the absence of a $110 million loss on debt redemption in connection with senior notes that were repurchased in 2013, higher investment income of $4 million on NDT investments, and lower net interest expense of $29 million due to debt redemptions.

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Discontinued Operations —

Discontinued operations increased net income in the first quarter of 2014 compared to the same period of last year primarily due to a a pre-tax gain of approximately $142 million associated with the sale of hydro assets described above.

Other — First Quarter 2014 Compared with First Quarter 2013

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 $8 millionincrease in net income in the first quarter of 2014 compared to the same period of 2013 primarily due to tax benefits resulting from higher AFUDC equity flow-through, changes in state apportionment factors and the elimination of certain future tax liabilities associated with basis differences. This benefit was partially offset by increased interest expense due to the issuance of $1.5 billion of FE senior unsecured notes in March 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 March 31, 2014 and December 31, 2013, and the changes during the three months ended March 31, 2014:

Regulatory Assets (Liabilities) by Source	March 31, 2014			December 31, 2013			Increase (Decrease)
	(In millions)
Regulatory transition costs	$	236		$	266		$	(30	)
Customer receivables for future income taxes	514			518			(4		)
Nuclear decommissioning and spent fuel disposal costs	(207		)	(198		)	(9		)
Asset removal costs	(363		)	(362		)	(1		)
Deferred transmission costs	92			112			(20		)
Deferred generation costs	360			346			14
Deferred distribution costs	190			194			(4		)
Contract valuations	229			260			(31		)
Storm-related costs	466			455			11
Other	281			263			18
Total	$	1,798		$	1,854		$	(56	)

Regulatory assets that do not earn a current return totaled approximately $514 million as of March 31, 2014 primarily related to storm damage costs.

As of March 31, 2014 and December 31, 2013, FirstEnergy had approximately $382 million and $440 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 2014 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.

In January 2014, FirstEnergy’s Board of Directors declared a revised quarterly dividend of $0.36 per share of outstanding common stock. The dividend was paid on March 1, 2014, to shareholders of record at the close of business on February 7, 2014. This revised dividend equates to an indicated annual dividend of $1.44 per share, reduced from the $0.55 per share quarterly dividend ($2.20 per share annually) that FirstEnergy had paid since 2008. In March 2014, FirstEnergy's Board of Directors declared a quarterly dividend of $0.36 per share of outstanding common stock that will be paid on June 1, 2014, to shareholders of record at the close of business on May 7, 2014.

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As a result of the challenging competitive environment, FirstEnergy has begun redirecting its growth strategy to pursue more predictable and sustainable long-term growth opportunities in its regulated businesses.

The centerpiece of this strategy is a $4.2 billion “Energizing the Future” investment plan beginning in 2014 through 2017 to upgrade and expand the transmission system owned by FirstEnergy’s Regulated Transmission segment. This program is focused on rebuilding the transmission system, starting with ATSI's system and moving east across FirstEnergy's service territory over time. Also included in the investment are projects that enhance system performance, physical security and add operating flexibility and capacity. These activities began in the first quarter of 2014. FirstEnergy expects to fund these investments through a combination of debt, previously announced equity issuances through stock investment and employee benefit plans, and cash.In total, FirstEnergy has identified at least $7 billion in transmission investment opportunities across the 24,000 mile transmission system, making this a continuing platform for growth in the years ahead.

In alignment with FirstEnergy’s strategy to reposition the Regulated Transmission and Regulated Distribution segments and preserve the competitive business, FirstEnergy will also focus on reducing balance sheet risk, maintaining investment grade metrics, and improving the business risk profile at each of our businesses. Specifically, at the regulated businesses, authority has been obtained for various regulated distribution and transmission subsidiaries to issue or refinance debt. Finally, at the competitive business, FirstEnergy completed the sale of certain hydro assets for approximately $394 million on February 12, 2014. The actions taken in 2013 and those planned for 2014 are expected to support a regulated investment strategy.

Any financing plans by FirstEnergy, including refinancing of maturing debt and reductions in short-term borrowings, are subject to market conditions and other factors. No assurance can be given that any such financings, refinancings, or reductions in short-term debt, as the case may be, will be completed as anticipated. In addition, FirstEnergy expects to continually evaluate any planned financings, which may result in changes from time to time.

As of March 31, 2014, 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 March 31, 2014, included the following:

Currently Payable Long-Term Debt	(In millions)
PCRBs supported by bank LOCs (1)	$	415
Unsecured notes	600
FMB	175
Unsecured PCRBs (1)	26
Collateralized lease obligation bonds	91
Sinking fund requirements	103
Other notes	6
	$	1,416

⁽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 $3,085 million of short-term borrowings as of March 31, 2014, and $3,404 million as of December 31, 2013. FirstEnergy’s available liquidity as of April 30, 2014, was as follows:

Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	March 2019	$	3,500	$	1,629
FES / AE Supply	Revolving	March 2019	1,500		1,031
FET(2)	Revolving	March 2019	1,000		250
		Subtotal	$	6,000	$	2,910
		Cash	—		74
		Total	$	6,000	$	2,984

⁽¹⁾  FE and the Utilities.

⁽²⁾  Includes FET, ATSI and TrAIL.

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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).On March 31, 2014, FE, FES, AE Supply, FET and FE's other borrower subsidiaries entered into extensions and amendments to thethreeexisting multi-year syndicated revolving credit facilities.Each facility was extended until March 31, 2019.The FE facility was amended to increase the lending banks' commitments under the facility by $1 billion to a total of $3.5 billionand to increase the individual borrower sublimit for FE by $1 billionto a total of $3.5 billion.The FES/AE Supply facility was amended to decrease the lending banks' commitments by $1 billion to a total of $1.5 billion. The lending banks' commitments under the FET facility remain at $1 billion and that facilitywas amended to increase ATSI's individual borrower sublimit to $500 millionfrom $100 millionand TrAIL's individual borrower sublimit to $400 millionfrom $200 million. FirstEnergy expensed approximately $5 million(FES - $3 million)of unamortized debt expense as a result of the amendments.The amount was included in Loss on Debt Redemptions in the Consolidated Statement of Income in the first quarter of 2014.

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 (as defined under each of the Facilities, as amended) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

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 of March 31, 2014:

Borrower	FE Revolving Credit Facility Sublimit			FES/AE Supply Revolving Credit Facility Sublimit			FET Revolving Credit Facility Sublimit			Regulatory and Other Short-Term Debt Limitations
	(In millions)
FE		$	3,500		$	—		$	—		$	—	(1)
FES		—			1,500			—			—		(2)
AE Supply		—			1,000			—			—		(2)
FET		—			—			1,000			—		(1)
OE		500			—			—			500		(3)
CEI		500			—			—			500		(3)
TE		500			—			—			500		(3)
JCP&L		600			—			—			850		(3)
ME		300			—			—			500		(3)
PN		300			—			—			300		(3)
WP		200			—			—			200		(3)
MP		500			—			—			500		(3)
PE		150			—			—			150		(3)
ATSI		—			—			500			500		(3)
Penn		50			—			—			50		(3)
TrAIL		—			—			400			400		(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, $630 million of the FE Facility and $225 million of the FET Facility, subject to each borrower’s sublimit, 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.

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As of March 31, 2014, the borrowers were in compliance with the applicable debt to total capitalization ratios under the respective Facilities.

Term Loans

On March 31, 2014, FE executed, and fully utilized, a new $1 billionvariable rate term loan credit agreement with a maturity date of March 31, 2019.The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Additionally, FE has a $200 million variable rate term loan, due December 31, 2015. Each of the term loans contains covenants and other terms and conditions substantially similar to those of the FE Facility described above, including the same consolidated debt to total capitalization ratio requirement.

FirstEnergy Money Pools

FirstEnergy’s utility operating subsidiary 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 three months of 2014 was 1.68% per annum for the regulated companies’ money pool and 1.25% per annum for the unregulated companies’ money pool.

Pollution Control Revenue Bonds

As of March 31, 2014, FirstEnergy’s currently payable long-term debt included approximately $415 million ($342 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 March 31, 2014 were issued by the following banks:

Bank	Aggregate Amount(1)		Termination Date	Reimbursements of Draws Due
	(In millions)
UBS(2)	$	268	April 2014	April 2014
CitiBank N.A.	164		June 2014	June 2014
The Bank of Nova Scotia(2)	49		April 2014	April 2014
The Bank of Nova Scotia	81		April 2015	April 2015
The Bank of Nova Scotia	96		December 2015	December 2015
Total	$	658

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

⁽²⁾  The LOCs for UBS and The Bank of Nova Scotia with a termination date of April 2014 expired in April 2014.

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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 March 31, 2014:

	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-	Baa2	BBB+
MP	BBB+	Baa1	A-	—	—	—
OE	BBB+	A3	BBB+	BBB-	Baa2	BBB
PN	—	—	—	BBB-	Baa2	BBB
Penn	BBB+	A3	BBB+	—	—	—
PE	BBB+	Baa1	A-	—	—	—
TE	BBB	Baa1	BBB	—	—	—
TrAIL	—	—	—	BBB-	Baa1	BBB+
WP	BBB+	A3	A-	—	—	—

On April 21, 2014, Moody's assigned a Baa3 Issuer Rating to FET and raised TrAIL's senior unsecured rating to A3 from Baa1. On May 1, 2014, Fitch affirmed FE's Issuer Default and senior unsecured debt ratings of BB+. Fitch also affirmed the ratings of FE’s subsidiaries as indicated in the table above. The Rating Outlook for all companies is Stable. Fitch expects to withdraw its ratings of FE’s subsidiaries in the second quarter of 2014.

Debt capacity is subject to the consolidated debt to total capitalization limits in the Facilities previously discussed. As of March 31, 2014, FE and its subsidiaries could issue additional debt of approximately $4.8 billion and remain within the limitations of the financial covenants required by the Facilities (as amended). As of March 31, 2014, FES' incremental debt capacity under its consolidated debt to total capitalization financial covenant is also $4.8 billion given FE's consolidated debt to total capitalization ratio under its Facility, as amended.

Changes in Cash Position

As of March 31, 2014, FirstEnergy had $109 million of cash and cash equivalents compared to $218 million of cash and cash equivalents as of December 31, 2013. As of March 31, 2014 and December 31, 2013, FirstEnergy had approximately $75 million and $103 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 used for operating activities was $92 million during the first three months of 2014 compared with $50 million provided from operating activities during the first three months of 2013, as summarized in the following table:

	Three Months Ended March 31
Operating Cash Flows	2014			2013			Increase (Decrease)
	(In millions)
Net income	$	208		$	196		$	12
Non-cash charges	378			604			(226		)
Working capital and other	(678		)	(750		)	72
	$	(92	)	$	50		$	(142	)

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The $142 million decrease in operating cash flows for the first quarter of 2014 compared to the same period of 2013 was primarily due to increased cash posted as collateral due to the extreme weather and market conditions experienced in January of 2014. On April 16, 2014, approximately $275 million of cash collateral was returned to FES as a result of the PJM semi-annual peak market activity calculation reset.

The $226 million decrease in non-cash charges is primarily due to the following:

• $110 million decrease from loss on debt redemptions incurred in 2013 associated with the completion of the FES/AE Supply tender offers and FES debt redemptions.

• $9 million decrease from lower deferred purchased power and other costs primarily due to the expiration of certain NUG agreements.

• $87 million decrease in amortization (deferral) of regulatory assets primarily due to lower default generation service costs recovery in Pennsylvania, partially offset by the completion of marginal transmission loss refunds at ME and PN.

• $47 million increase due to deferred income taxes and investment tax credits.

• $44 million increase in retirement benefits due to reduced payments in 2014 as compared to 2013.

• $82 million decrease associated with discontinued operations primarily as a result of the adjustment to eliminate from operating activities the gain on sale in 2014 of approximately $78 million (after-tax).

• $21 million decrease due primarily to unrealized gains on commodity transactions as described in the Results of Operations above.

The $72 million increase in cash from working capital and other is primarily due to the following:

• $460 million decrease due to cash collateral paid resulting from higher PJM collateral requirements associated with the extreme weather and market conditions in January of 2014.

• $134 million decrease associated with higher customer receivables, primarily as a result of increased weather related usage as described in the Results of Operations above.

• $578 million increase in accounts payable due to the timing of payments to vendors, including payments in 2013 related to restoration costs associated with Hurricane Sandy.

• $120 million increase in customer deposits and changes in other assets and liabilities.

• $27 million decrease in accrued compensation and benefits associated with higher incentive compensation payments in 2014 compared to 2013.

Cash Flows From Financing Activities

In the first three months of 2014, cash provided from financing activities was $498 million compared to $772 million of net cash provided from financing activities during the first three months of 2013. The following table summarizes new debt financing (net of any discounts) and redemptions and repurchases:

	Three Months Ended March 31
Securities Issued or Redeemed / Repaid	2014			2013
	(In millions)
New Issues
PCRBs	$	417		$	—
Term Loan	1,050			—
Unsecured Notes	—			1,800
	$	1,467		$	1,800
Redemptions / Repayments
PCRBs	$	(444	)	$	—
Senior secured notes	(45		)	(17		)
Unsecured notes	—			(829		)
	$	(489	)	$	(846	)
Tender premiums paid on debt redemptions	—			(110		)
Short-term borrowings, net	$	(319	)	$	181

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On March 31, 2014, FE, FES, AE Supply, FET and FE's other borrower subsidiaries entered into extensions and amendments to thethreeexisting multi-year syndicated revolving credit facilities.Each facility was extended until March 31, 2019.The FE facility was amended to increase the lending banks' commitments under the facility by $1 billion to a total of $3.5 billionand to increase the individual borrower sublimit for FE by $1 billionto a total of $3.5 billion.The FES/AE Supply facility was amended to decrease the lending banks' commitments by $1 billion to a total of $1.5 billion. The lending banks' commitments under the FET facility remain at $1 billion and that facilitywas amended to increase ATSI's individual borrower sublimit to $500 millionfrom $100 millionand TrAIL's individual borrower sublimit to $400 millionfrom $200 million. FirstEnergy expensed approximately $5 million(FES - $3 million)of unamortized debt expense as a result of the amendments.The amount was included in Loss on Debt Redemptions in the Consolidated Statement of Income in the first quarter of 2014.

On March 31, 2014, FE executed, and fully utilized, a new $1 billionvariable rate term loan credit agreement with a maturity date of March 31, 2019.The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances.

During the first quarter of 2014, FG and NG remarketed approximately $417 millionof PCRBs previously held by the companies.Of the total, $182 million was remarketed with a fixed interest rate of4%per annum with a mandatory put date of June 3, 2019 and $235 millionwas remarketed with a fixed interest rate of3.75%per annum with a mandatory put date of December 3, 2018.

In addition, in the first quarter of 2014, FG and NG repurchased approximately $197million and $16 millionof PCRBs, respectively, which were subject to a mandatory tender. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

On April 1, 2014, PN and ME repurchased approximately $45 million and $29 millionof PCRBs, respectively, which were subject to a mandatory put on such date. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

During the first quarter of 2014, AE Supply returned $500 million of capital to FE Corp. Additionally, FE Corp. contributed $500 million of equity to FES.

Cash Flows From Investing Activities

Cash used for investing activities in the first three months of 2014 principally represented cash used for property additions. The following table summarizes investing activities for the first three months of 2014 and the comparable period of 2013:

	Three Months Ended March 31
Cash Used for Investing Activities	2014			2013		Increase (Decrease)
	(In millions)
Property Additions:
Regulated distribution	$	269		$	436	$	(167	)
Regulated transmission	217			89		128
Competitive energy services	318			283		35
Other and reconciling adjustments	17			18		(1		)
Nuclear fuel	55			27		28
Proceeds from asset sales	(394		)	—		(394		)
Investments	(3		)	20		(23		)
Asset removal costs	39			53		(14		)
Other	(3		)	1		(4		)
	$	515		$	927	$	(412	)

Net cash used for investing activities during the first three months of 2014 decreased by $412 million compared to the same period of 2013. The decrease was principally due to the proceeds from the sale of the Hydro assets of $394 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 and its subsidiaries could be required to make under these guarantees as of March 31, 2014, was approximately $4.0 billion, as summarized below:

Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FE's Guarantees on Behalf of its Subsidiaries
Energy and Energy-Related Contracts(1)	$	257
LOC (long-term debt) - interest coverage(2)	5
Deferred compensation arrangements	476
Other(3)	158
	896
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts	76
LOC (long-term debt) - interest coverage(2)	2
FES’ guarantee of NG’s nuclear property insurance	89
FES’ guarantee of FG’s sale and leaseback obligations	2,030
Other	10
	2,207
Global Holding facility	350
Surety Bonds	464
LOCs(4)	77
	891
Total Guarantees and Other Assurances	$	3,994

⁽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 $658 million, of which $415 million is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

⁽³⁾  Includes guarantees of $125 million for nuclear decommissioning funding assurances, $11 million supporting OE’s sale and leaseback arrangements, and $22 million for various leases. By a letter dated March 28, 2013, FENOC informed the NRC that the nuclear decommissioning parental guarantee would be increased to $155 million during the second quarter of 2014. Moreover, a new parental guarantee for the Beaver Valley spent fuel storage facility of $9.5 million would also be put in place.

⁽⁴⁾  Includes $7 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $45 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $25 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.This posted collateral is used to settle gains or losses on those bilateral agreements or derivatives.

Based on FES' power portfolio exposure as ofMarch 31, 2014, FES has posted collateral of$544 millionand AE Supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of$28 million.The collateral posted at FES primarily

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relates to the extreme weather and market conditions experienced in January of 2014. On April 16, 2014, approximately $275 million of cash collateral was returned to FES as a result of the PJM semi-annual peak market activity calculation reset.

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 ofMarch 31, 2014:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	461	$	6	$	49	$	516
BB+/Ba1 Credit Ratings	$	497	$	6	$	49	$	552
Full impact of credit contingent contractual obligations	$	796	$	58	$	87	$	941

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 ofMarch 31, 2014, 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$111 millionand$1 million, respectively.

Other Commitments and Contingencies

FE is a guarantor under a syndicated three-year senior secured term loan facility dated October 18, 2011, as amended, that matures 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 FE, 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 guarantees of the obligations of Global Holding under the new facility.

In connection with the 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 as collateral.

FE, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed, most recently as of August 14, 2013, to use their best efforts to refinance the facility no later than July 20, 2015, on a non-recourse basis so that FE's guaranty can be terminated and/or released.If that refinancing does not occur, FE may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the facility in full.In lieu of providing such funding, the co-owners, at FE's option, may provide their several guaranties of Global Holding's obligations under the facility.Since January 1, 2013, FE has received a fee for providing its guaranty.The fee is payable semiannually, and accrues at a rate of5%per annum on the average daily outstanding aggregate commitments under the facility for each 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 Unit 1 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 $1.1 billion as of March 31, 2014 and primarily relates to the 2007 Bruce Mansfield Unit 1 sale and leaseback arrangement expiring in 2040. 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.

In February 2014, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for approximately $94 million. As of March 31, 2014, FirstEnergy's leasehold interest was 8.11% of Perry Unit 1, 93.83% of Bruce Mansfield Unit 1 and 2.60% of Beaver Valley Unit 2.

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 7, Fair Value Measurements, of the Combined Notes to Consolidated Financial Statements). Sources of information for the valuation of derivative contracts assets and liabilities as of March 31, 2014 are summarized by year in the following table:

Source of Information- Fair Value by Contract Year	2014		2015			2016			2017			2018			Thereafter			Total
	(In millions)
Prices actively quoted(1)	$	3	$	—		$	—		$	—		$	—		$	—		$	3
Other external sources(2)	16		(33		)	(24		)	(15		)	—			—			(56		)
Prices based on models	9		—			1			1			(13		)	(14		)	(16		)
Total(3)	$	28	$	(33	)	$	(23	)	$	(14	)	$	(13	)	$	(14	)	$	(69	)

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

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

⁽³⁾  Includes $185 million in non-hedge derivative contracts primarily related to NUG contracts. NUG contracts are generally subject to regulatory accounting and do not materially impact earnings.

FirstEnergy performs sensitivity analyses to estimate its exposure to the market risk of its commodity positions. Based on derivative contracts held as of March 31, 2014, a 10% adverse change in commodity prices would decrease net income by approximately $40 million during the next 12 months.

Equity Price Risk

As of March 31, 2014, the FirstEnergy pension plan assets were approximately allocated as follows: 33% in equity securities, 38% in fixed income securities, 20% in absolute return strategies, 6% in real estate and 3% 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 three months ended March 31, 2014, FirstEnergy made no contributions to its qualified pension plans. See Note 3, Pensions and Other Postemployment Benefits, of the Combined Notes to Consolidated Financial Statements for additional details on FirstEnergy's pension plans and OPEB. Through March 31, 2014, FirstEnergy's pension plan assets earned approximately 2.9% as compared to an annual 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 March 31, 2014, approximately 66% of the funds were invested in fixed income securities, 21% of the funds were invested in equity securities and 13% 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 $1,487 million, $463 million and $305 million for fixed income securities, equity securities and short-term investments, respectively, as of March 31, 2014, excluding $8 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 March 31, 2014. 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 three months ended March 31, 2014, no contributions were made to the NDT.

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. At this time FirstEnergy is unable to determine or project the mark-to-market adjustment that may be recorded as of December 31, 2014.

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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 of A (S&P) for energy contract counterparties.

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 any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.

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

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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.PE filed its second annual report on March 27, 2014.

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; selective increased investment in system hardening; 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 July 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 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 concluded.In the initial briefs of the parties filed on January 27, 2014, the Division of Rate Counsel recommended that base rate revenues be reduced by $214.9 million while the

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NJBPU Staff recommended a $207.4 million reduction (such amounts do not address the revenue requirements associated with the major storm events of 2011 and 2012).Reply briefs were filed on February 24, 2014. The matter is pending before the ALJ.

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 February 24, 2014, a Stipulation was filed with the NJBPU by JCP&L, the Division of Rate Counsel and NJBPU Staff which will allow recovery of $736 million of JCP&L's $744 million of costs related to the significant weather events of 2011 and 2012.As a result, FirstEnergy recorded a regulatory asset impairment charge of approximately $8 million (pre-tax) as of December 31, 2013.By its Order of March 19, 2014, the NJBPU approved the Stipulation of Settlement and on March 25, 2014, transmitted a copy of that Order to the Office of Administrative Law so that “actual recovery of the 2011 costs can be determined in relation to the pending base rate case.”Recovery of 2011 storm costs will be addressed in the pending base rate case; recovery of 2012 storm costs will be determined by the NJBPU.

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 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 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.While briefing has been completed, 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 provides 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 SB221, the Ohio Companies are required to implement energy efficiency programs that 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, on July 31, 2012 the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015.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 denied the Ohio Companies' application for rehearing, in part, but authorized 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.The motion is still pending and additional briefing has followed.While briefing has been completed, the matter has not been scheduled for oral argument.

SB221 requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2024.The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet the renewable energy requirements established under SB221.In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs and selected auditors to perform a financial and management audit.Final audit reports filed with the PUCO generally supported the Ohio Companies' approach to procurement of RECs, but also recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state renewable obligations that the auditor characterized as excessive.Following the hearing, the PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of RECs 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, and to file tariff schedules reflecting the refund and interest costs 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 December 18, 2013, the PUCO denied all of the applications for rehearing. Based on the PUCO ruling a regulatory charge of approximately $51 million, including interest, was recorded in the fourth quarter of 2013.On December 24, 2013, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio.On February 10, 2014, the Supreme Court of Ohio granted the Ohio Companies' motion for stay, which went into effect on February 14, 2014.On February 18, 2014, the Office of Consumers' Counsel and the ELPC also filed appeals of the PUCO's order.The Ohio Companies filed their merit brief with the Supreme Court of Ohio on March 6, 2014.On April 15, 2014, the Supreme Court of Ohio stayed the briefing schedule pending the court's resolution of the Ohio Companies' motion to seal certain confidential portions of the appendix and supplement to their merit brief.

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The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.On April 15, 2014, the Ohio Companies reported that they met all of their annual renewable energy resource requirements for reporting year 2013.

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 comment 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.On June 5, 2013, the PUCO requested additional comments and reply comments on the topics of market design and corporate separation, which the Ohio Companies timely filed on July 8, 2013 and July 22, 2013, respectively.The PUCO held a series of workshops throughout 2013, which included an en banc workshop on December 11, 2013.The PUCO Staff filed a report on January 16, 2014, which contained a limited discussion of the workshops and the PUCO Staff's recommendations.The Ohio Companies submitted comments on February 6, 2014 and Reply Comments on February 20, 2014.The PUCO issued its Order in this matter on March 26, 2014, which included a wide range of issues such as, maintaining SSO service in its current form, requiring corporate separation audits of all EDUs, establishing a market development working group, and ordering changes to the bill format.The Ohio Companies filed their Application for Rehearing on April 25, 2014.The Ohio Companies filed their memorandum contra applications for rehearing of other stakeholders on May 5, 2014.

On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2015, 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 4, 2013, the Pennsylvania Companies filed a DSP 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 SRECs for ME, PN, and Penn.The Pennsylvania Companies have reached a settlement with all parties on all issues raised in the case with the exception of the treatment of NITS charges. On May 6, 2014, the ALJ issued a Recommended Decision recommending adoption of the settlement without modification and the denial of several parties’ request for non-bypassable treatment of NITS charges. A final order is expected from the PPUC by August 2014.

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.On appeal, the Commonwealth Court affirmed 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 and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari.ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania to obtain 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.On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss.As a result of the U.S. District Court's decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013. The balance of marginal transmission losses was fully refunded to customers by the second quarter of 2013.On October 29, 2013, ME and PN filed a Notice of Appeal of the U.S. District Court's decision to dismiss the complaint with the United States Court of Appeals for the Third Circuit.Oral argument was held on April 8, 2014, and, at the end of the argument, the Third Circuit directed ME and PN, and the PPUC, each to submit a brief on April 16, 2014 on the question of whether it is possible to waive the preemptive effect of FERC’s classification of line loss charges as transmission charges.On April 16, 2014, ME and PN, the PPUC, and the Pennsylvania Industrials each submitted briefs on the Third Circuit's questions.

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 a 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 between $1 and$20 million.On November 15, 2013, the Pennsylvania Companies submitted their energy efficiency and peak demand reduction report for the period ending May 31, 2013, in which they indicated that all of the Pennsylvania Companies met their statutory

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requirements.On March 20, 2014, the PPUC issued an Order initially determining that ME, PN and Penn achieved the 2011 and 2013 statutory energy efficiency benchmarks. The PPUC also initially determined that WP is not in compliance with the 2011 statutory energy efficiency benchmarks but is in compliance with the 2013 energy efficiency benchmarks.As such, the PPUC, with regards to WP’s compliance with the 2011 statutory benchmarks, referred the matter to the PPUC Bureau of Investigation and Enforcement for the initiation of an appropriate proceeding no later than May 30, 2014 to investigate whether WP is in compliance with the 2011 statutory benchmarks and whether WP is subject to statutory penalties.The PPUC also ordered that the initial determination will be deemed final unless any petitions challenging its initial determination are filed within 20 days of the Order.On April 9, 2014, WP filed its petition challenging the PPUC’s initial determination arguing, among other things, that the May 2011 target was not mandatory and WP is in compliance because it achieved its May 2013 targets.On April 21, 2014, WP filed an appeal with the Commonwealth Court of Pennsylvania in which it challenged the PPUC's initial finding of a violation of Act 129 on due process grounds.On that same day, the Bureau of Investigation and Enforcement, consistent with the PPUC's March 20, 2014 Order, initiated a proceeding by filing a Complaint against WP in which it alleges that WP violated Act 129 and recommends a penalty in the amount of $11.4 million.The Pennsylvania Companies have 20 days in which to respond to the Complaint.A prehearing conference is scheduled for May 9, 2014 at which time a procedural schedule for this matter is expected to be established.

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.Based upon information received, the PPUC has not included a peak demand reduction requirement in the Phase II plans.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 requested 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 were held and briefs were submitted by the Pennsylvania Companies and the OCA.On November 8, 2013, the ALJ issued a Recommended Decision recommending that the Pennsylvania Companies' Deployment Plan be adopted with certain modifications, including, among other things, that the Pennsylvania Companies perform further benchmarking analyses on their costs and hire an independent consultant to perform further analyses on potential savings.On December 2, 2013, the Pennsylvania Companies submitted exceptions in which they challenged, among other things, certain recommendations in the ALJ's decision, and requested approval of a modification to the deployment schedule so as to allow the entire Penn smart meter system (170,000 meters) to be built by the end of 2015, instead of the original proposed installation of 60,000 meters by the end of 2016.The OCA took exception to one issue and both parties filed replies to exceptions on December 12, 2013.In its March 6, 2014 Opinion and Order, the PPUC rejected the OCA's exception and many of the ALJ's recommendations, including the recommendation to hire an independent consultant and the disallowance of $5.1 million of customer information system costs, and affirmed the ALJ's recommendation on the accounting treatment for legacy meter costs.The PPUC also directed the Pennsylvania Companies to file an amendment to the Deployment Plan within thirty days of the Order with sufficient supporting documentation for proper evaluation if the Pennsylvania Companies intend to pursue an accelerated deployment schedule, and the PPUC indicated that it would establish an expedited procedural schedule and rule on the filing within 90 days of the March 6, 2014 Order.The Pennsylvania Companies filed an amended Deployment Plan on March 19, 2014, to which, the OCA filed exceptions arguing that the amended plan failed to: 1) list certain potential cost savings categories that are to be considered by the Pennsylvania Companies; and 2) follow proper procedure. On April 7, 2014, the Pennsylvania Companies filed a reply to OCA’s exceptions explaining why they should be rejected.A prehearing conference was held on April 25, 2014, and a procedural schedule was established that is expected to allow the PPUC to issue an order by June 5, 2014.

In the PPUC Order approving the FirstEnergy and AE 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,

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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.On March 24, 2014, the PPUC issued a letter withdrawing the Proposed Rulemaking.

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.

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.A hearing was held on December 3, 2013, and briefing followed.The WVPSC issued an order on April 14, 2014 approving the plan, stating rate recovery will be addressed in the base rate case filed on April 30, 2014. In the interim, MP and PE are authorized to defer all costs associated with the plan.

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 filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposed a net ownership transfer of1,476MW of coal-fired generation capacity to MP.The proposed transfer involved 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.FERC authorized the transfers on April 23, 2013 and the financing on May 13, 2013.A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013.On October 7, 2013, the WVPSC authorized the transaction, with certain conditions, and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately$322 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.Concurrently, MP recognized a regulatory liability of approximately$23 millionrepresenting 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 billionand MP's assumption of a$73.5 millionpollution control note.The$1.1 billionnet consideration was originally financed by MP through an equity infusion from FE of approximately$527 millionand a note payable to AE Supply of approximately$573 million.The note payable to AE Supply was paid in the fourth quarter of 2013.The settlement also required MP and PE to file a base rate case by April 30, 2014.On November 6, 2013, the WVCAG petitioned for appeal with the Supreme Court of Appeals of West Virginia.MP and PE filed their response to the WVCAG petition on December 27, 2013 and WVCAG filed its reply on January 16, 2014.The Supreme Court of Appeals of West Virginia held oral arguments on March 5, 2014.On April 23, 2014 the Supreme Court of Appeals of West Virginia delivered an Opinion affirming the WVPSC order approving the Generation Resource Transaction.

On April 30, 2014, MP and PE filed a rate case requesting a base rate increase of approximately $96 million, or 9.3%. The filing also included a surcharge to recover costs of MP's and PE's vegetation management program in the amount of approximately $48

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million. The proposed total rate increase request, including the cost of the vegetation management program, is approximately $144 million, or 14%. MP and PE anticipate a decision from the WVPSC in February 2015.

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 Rates

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 a Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated with several other cases before that court for briefing and disposition.Briefing is complete, oral argument was held on April 22, 2014, and a decision is 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 again accepted the hybrid method.Certain parties 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 NYISO region and; (2) the PJM region and the FERC-jurisdictional members of the SERTP 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.On December 30, 2013, FERC conditionally accepted the PJM/SERTP cross-border project cost allocation filing, subject to refund and future orders in PJM's and SERTP's related Order No. 1000 interregional compliance proceedings.The PJM/NYISO and PJM/MISO cross-border project cost allocation filings remain pending before FERC.On January 16, 2014, FERC issued an order regarding the effective date of PJM's

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separate Order No. 1000 regional transmission planning and cost allocation compliance filing, noting that it would address the merits of the comments on and protests to that filing and related compliance filings in a future order.

Numerous parties, including ATSI, FES, TrAIL, OE, CEI, TE, Penn, JCP&L, ME, MP, PN, WP and PE, sought judicial review of Order No. 1000 before the U.S. Court of Appeals for the D.C. Circuit.Briefing is complete and oral argument was held on March 20, 2014.

The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.

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 many of the matters involved with the move have been resolved, FERC denied recovery by means of ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately$78.8 millionuntil such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move.On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve the exit fee and transmission cost allocation issues.However, FERC subsequently rejected that settlement, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges.On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

Separately, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed.Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings in front of FERC and certain U.S. appellate courts.The MISO and its allied parties assert that the benefits to the ATSI zone of the Michigan Thumb project are roughly commensurate with the costs that MISO desires to charge to the ATSI zone, estimated to be as much as $16 million per year.ATSI has submitted evidence that the Michigan Thumb project provides no electric benefits to the ATSI zone and, on that basis, opposes the MISO’s efforts to impose these costs on the ATSI zone loads.The MISO and its allied parties also assert that certain language in the MISO Transmission Owners Agreement requires ATSI to pay these charges.In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek recovery of these charges through its formula rate.While FERC proceedings regarding whether the MISO can charge ATSI for MVP costs remain pending, on February 24, 2014, the U.S. Supreme Court declined to hear appeals filed by FirstEnergy and other parties of the Seventh Circuit's June 2013 decision upholding FERC's acceptance of the MISO's generic MVP cost allocation proposal.

In addition, in a 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.ATSI subsequently filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit.Briefing is complete, oral argument was held on 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 cannot be predicted at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the 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.

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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%for 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. PATH, 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 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.

On March 20, 2014, the settlement judge declared an impasse in efforts to achieve settlement. On March 24, 2014, the Chief ALJ terminated settlement judge procedures and appointed an ALJ to preside over the hearing phase of the case.The hearing is scheduled to commence on November 5, 2014.The issues set for hearing include the prudence of the costs, the base return on equity and the period of recovery.Depending on the outcome of the hearing, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

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).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.On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $394 million.See Note 13, Discontinued Operations for additional information regarding the assets sold.

MISO Capacity Portability

On June 11, 2012, in response to certain arguments advanced by MISO, 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.FirstEnergy and other parties have 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.On December 19, 2013, FERC issued an order directing that FERC staff are to attend the "joint and common market" stakeholder meetings for the purpose of monitoring progress on the initiatives described in the September 26, 2013 joint informational filing and establishing a new proceeding to reflect the broadened scope of issues contemplated by that filing and the RTOs' 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 publicly-available data 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.

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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 2010, FES and AE Supply have lost more than$87 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 re-filed 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,FESC, on behalf of FES and AE Supply, filed a request for rehearing of FERC's order.That request for rehearing, and all subsequent filings in the docket, are pending before FERC.

PJM RPM Tariff Amendments

In November 2013, PJM began to submit a series of amendments to its RPM capacity tariff in order to address certain problems that have been observed in recent auctions.These problems can be grouped into four categories: (i) Demand Response (DR); (ii) imports; (iii) modeling of transmission upgrades in calculating geographic clearing prices; and (iv) arbitrage/capacity replacement.The purpose of PJM’s tariff amendments is to ensure that resources that clear in the RPM auctions are available as physical resources in the delivery year and that the rules implement comparable obligations for different types of resources.In each of the relevant dockets, FirstEnergy submitted comments as part of a coalition of utilities (generally including an affiliate of AEP, Duke and Dayton).The FirstEnergy/coalition position was that all of the PJM proposals should be accepted as proposed, and that the FERC should order PJM to take additional steps that should have the effect of eliminating additional distortions and flaws in the RPM market.PJM made two filings regarding DR; FERC accepted one as proposed on January 30, 2014, and issued a deficiency letter regarding the other on March 6, 2014. FERC also issued deficiency letters requesting additional information from PJM regarding the modeling filing on January 17, 2014 and regarding the imports filing on January 28, 2014.On February 18 and 21, 2014, respectively, PJM filed its responses to FERC's deficiency letters regarding the modeling filing and the imports filing.On April 18, 2014, FERC conditionally accepted PJM's modeling filing, as supplemented, subject to PJM's submission of a compliance filing. On April 22, 2014, FERC accepted PJM's imports filing, as supplemented.The second DR filing, which relates to the rules applicable to DR performance obligations, the arbitrage/capacity replacement filing and related filings in those dockets, and a request for rehearing of the January 30, 2014 order on the first DR filing, are pending before FERC.PJM requested FERC action on the DR performance obligations filing by April 11, 2014, and prior to the May 2014 BRA for the arbitrage/capacity replacement filing.Although FirstEnergy believes that these filings (and the associated tariff changes) should have positive implications for RPM clearing prices, generally there can be no assurance as to their ultimate impact on FirstEnergy.

PJM RPM Auctions - Calculation of Unit-Specific Offer Caps

The PJM RPM capacity tariff describes the rules for calculating the “offer cap” for each unit that offers into the RPM auctions. In summary, the offer cap is calculated by identifying certain going-forward costs, including the going-forward capital requirements, for a given unit, and then subtracting the projected energy and ancillary services revenues, net of marginal costs, from the going-forward costs.The remainder becomes the offer cap. FES learned that the PJM Market Monitor’s practice for calculating the forecast energy and ancillary services revenues has been to use the lower of the unit’s economic or cost-based offers into the PJM energy market.The Market Monitor engages in this practice based on his interpretation of certain provisions of the PJM capacity tariff. However, review of the relevant tariff language suggests that only the cost-based offer data should be used.FES determined that the Market Monitor’s use of the lower of cost-based or economic offer data has the effect of suppressing the offer cap, which can distort the price signal that is intended to come out of the RPM auction process.On April 7, 2014, FES submitted a Petition for Declaratory Order to FERC, asking for an interpretation of the relevant provisions of the PJM capacity tariff.Specifically, FES identified the difference of opinion between FES and the Market Monitor regarding interpretation of the relevant provision and asked FERC to rule on the question of whether the tariff language permits the Market Monitor’s use of the lower of cost-based or economic offer data or requires use of the cost-based offer data.FES asked FERC to rule on the petition by May 9, 2014.On April 18, 2014, the Market Monitor and other parties filed protests to FES's petition, arguing that the PJM capacity tariff allows the Market Monitor to use market-based energy offers instead of cost-based energy offers in calculating RPM auction offer caps and asking FERC to delay action on the petition until after the May 2014 BRA.FES' petition, the protest, and related filings are pending before FERC. The timing of FERC action and the outcome of this proceeding cannot be predicted at this time.

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Market-Based Rate Authority, Triennial Update

OE, CEI, TE, Penn, JCP&L, ME, PN, MP, WP, PE, AE Supply, FES, FG, NG, FirstEnergy Generation Mansfield Unit 1 Corp., Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates.One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority.On December 20, 2013, FESC submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement.That filing 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 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 Keystone, Portland and Shawville coal-fired plants based on “modifications” dating back to the mid-1980s.JCP&L, as the former owner of 16.67% of the Keystone Station, ME, as a former owner and operator of the Portland Station, and PN as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter or estimate the possible loss or 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.FirstEnergy 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, MP, PE and WP in the U.S. District Court for the Western District of Pennsylvania alleging, among other things, that AE performed major modifications in violation of the NSR 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.On February 6, 2014, the Court entered judgment for AE, AE Supply, MP, PE and WP finding they had not violated the CAA or the Pennsylvania Air Pollution Control Act.On March 10, 2014, New York, Connecticut, and Maryland filed an appeal with the U.S. Court of Appeals for the Third Circuit.This decision does not change the status of these plants which remain deactivated.

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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 D.C. Circuit 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 D.C. Circuit and was ultimately vacated by the Court on August 21, 2012.The Court has ordered the EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR.On April 29, 2014 the U.S. Supreme Court reversed the D.C Circuit decision vacating CSAPR and generally upheld the EPA's authority under the CAA to establish the regulatory structure underpinning CSAPR.Depending on the outcome of further proceedings in this matter and how the EPA and the states implement the final rules, 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 Bruce 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 was challenged in the U.S. Court of Appeals for the D.C. Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1.On April 15, 2014, MATS was upheld by the U.S. Court of Appeals for the D.C. Circuit, however, the Court refused to decide FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers due to a January 2013 petition for reconsideration still pending but not addressed by EPA.Depending on the outcome of further appeals, if any, and how the MATS are ultimately implemented, FirstEnergy's total cost of compliance with MATS is currently estimated to be approximately$465 million(Competitive Energy Services segment of$240 millionand Regulated Distribution segment of$225 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.In February 2014, PJM notified FG that Eastlake Units 1-3 and Lake Shore Unit 18 will be released from RMR status as of September 15, 2014.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.FE and FES have asserted force majeure defenses for delivery shortfalls under certain agreements, and are in discussion with the applicable counterparties.As to two agreements, FE and FES have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately$70 million, and agreed to pay liquidated damages for delivery shortfalls for 2013 and 2014.FE and FES recorded $67 million in liquidated damages in the fourth quarter of 2013, associated with estimated 2013 delivery shortfalls, which were paid in the first quarter of 2014. Additionally, in January 2014, FE and FES reached an agreement in principle with Mepco Holdings LLC to terminate a contract for future coal deliveries to Hatfield for $18 million, which was approved by the United States Bankruptcy Court on February 26, 2014.If FE and FES fail to reach a resolution with applicable counterparties for coal transportation agreements associated with the deactivated plants or unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to their 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.If that were to occur, FE and FES are unable to estimate the loss or range of loss.

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Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level.Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies to reduce GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.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 goals to: (1) cut carbon pollution in America 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. GHG emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2016, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.

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 the 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.The memorandum further directed the EPA to propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units.On September 20, 2013, the EPA proposed a new source performance standard, which would not apply to any existing, modified, or reconstructed fossil fuel generating units, 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 the 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?" Oral argument was held on February 24, 2014. 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.

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.In 1997, the U.S. Senate passed the Byrd-Hagel resolution by a unanimous vote of 95-0. The resolution stated that it is the sense of the Senate that the United States should not be a signatory to any protocol to, or other agreement regarding, the United Nations Framework Convention on Climate Change which would mandate new commitments to limit or reduce GHG emissions, unless the protocol or other agreement also mandates new specific scheduled commitments to limit or reduce GHG emissions for developing country parties within the same compliance period, or would not result in serious harm to the economy of the United States. 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.In November 2013, the U.N. Climate Change Conference in Warsaw, Poland advanced negotiations of a new global agreement to reduce GHG emissions by 2015. 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

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CO₂emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants.In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.

In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants.The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system).In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures.In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures.On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a12%annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities.On April 16, 2014, counsel for EPA informed the United States District Court in which a settlement agreement with certain NGOs set April 17, 2014 as a deadline for finalizing the Section 316(b) regulation that an additional 29 days would be needed to finalize the Section 316(b) regulation by May 16, 2014.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 September 30, 2015, 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 ranging from$150 millionto$300 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.Based on the stringency of the TMDL, MP may incur significant costs to reduce sulfate discharges into the Monongahela River if the NPDES permit for the coal-fired Fort Martin plant in West Virginia is required to be modified or renewed to include more stringent effluent limitations for sulfate.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 CCRs produced by electric utilities pose significant financial risk to the industry.In May 2010, the EPA proposedtwooptions for additional regulation of CCRs, including the option of regulation as a special waste under the EPA's hazardous waste management program which could

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have a significant impact on the management, beneficial use and disposal of CCRs.On April 19, 2013, the EPA stated it would "align" its proposed CCR 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.On January 29, 2014, EPA agreed to take final action by December 19, 2014 on whether or not to pursue the proposed non-hazardous waste option for regulating CCRs in a Consent Decree to be filed in pending litigation.Depending on the content of the EPA's final effluent limitations rule, the specifics of any "alignment", whether EPA chooses to pursue the non-hazardous or hazardous waste option and the potential enactment of legislation, 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 required 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.FG responded to the PA DEP on December 3, 2013, and as a result of the Closure Plan, FG increased its ARO for LBR by $163 million in 2013.On April 3, 2014, PA DEP issued a permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizes FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCBs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met.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.In addition, 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 and December 5, 2013, complaints were filed on behalf of approximately50individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia and approximately 15 individuals against FG in the U.S. District Court for the Western District of Pennsylvania seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment.The complaints state 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 the complaints, 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 CCR 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 ofMarch 31, 2014based 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$129 millionhave been accrued throughMarch 31, 2014. 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.

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OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

Under NRC regulations, FirstEnergy must ensure that adequate funds will be available to decommission its nuclear facilities.As ofMarch 31, 2014, FirstEnergy had approximately$2.3 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2.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.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranty, as appropriate.By a letter dated March 28, 2013, FENOC informed the NRC that the nuclear decommissioning parental guarantee would be increased to $155 millionduring the second quarter of 2014.Moreover, a new parental guarantee for the Beaver Valley spent fuel storage facility of $9.5 millionwould also be put in place.

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.A 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.Other contentions proposed by the petitioners in this proceeding have been rejected by the ASLB. On February 18, 2014, Beyond Nuclear and Don't Waste Michigan, two of the petitioners in the Davis-Besse license renewal proceeding, requested that the NRC institute a rulemaking on the environmental impacts of high density spent fuel storage and mitigation alternatives. On February 27, 2014, these petitioners requested a suspension of the licensing decision in the Davis-Besse license renewal proceeding to allow the NRC to complete this rulemaking.On March 21, 2014, both FENOC and the NRC opposed the request for a suspension. On April 21, 2014, the Intervenors proposed an additional contention in the license renewal proceeding related to the shield building.

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. The shield building is a 2 1/2-foot thick reinforced concrete structure that provides biological shielding, protection from natural phenomena including wind and tornadoes and additional shielding in the event of an accident. FENOC then expanded its sample size to include all of the existing core bores in the shield building. These inspections, which are now complete, identified additional subsurface cracking that was determined to be pre-existing, but only now identified with the aid of improved inspection technology. These inspections also revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

On February 1, 2014 the Davis-Besse Nuclear Power station entered an outage to install two new steam generators, replace about a third of the unit’s 177 fuel assemblies and perform numerous safety inspections and preventative maintenance activities. These activities, including amounts spent in prior years in preparation for this outage, represent an investment of approximately $600 million by FES at Davis Besse.During the preliminary stages of the outage an area of concrete that was not filled to the expected thickness within the shield building wall was discovered at the top of the temporary construction opening that was created as part of the 2011 outage.The 2011 temporary construction opening was created to install the new reactor head. FENOC has assessed the as-found condition of the concrete and has determined the shield building would have performed its design functions.This condition within the shield building wall was repaired to conform to its original design configuration.

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.

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ICG Litigation

On December 28, 2006, AE Supply and MP filed a complaint in the Court of Common Pleas of Allegheny County, Pennsylvania against 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.A damages hearing is scheduled for May 13-14, 2014, and a ruling is expected in the fourth quarter of 2014.

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.The PPUC entered an Opinion and Order on January 9, 2014 approving the Settlement with limited modifications regarding the frequency of refresher training and reporting obligations.WP filed a letter on January 17, 2014 accepting those modifications and noting its intent to begin implementation of the settlement terms.

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 loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries.The other potentially material items not otherwise discussed above are described under Note 9, 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.

95

FIRSTENERGY SOLUTIONS CORP.

MANAGEMENT’S NARRATIVE

ANALYSIS OF RESULTS OF OPERATIONS

FES is a wholly owned subsidiary of FE. 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 AE Supply and MP), and owns, through its subsidiary, NG, FirstEnergy’s nuclear generation facilities. FENOC, a wholly owned subsidiary of FE, 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. On February 12, 2014, FES sold its hydroelectric generation facility to LS Power and recorded a pre-tax gain of $177 million associated with the sale in the first quarter of 2014.

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 first quarter of 2014, FE completed a $500 million 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 increased by $11 million in the first three months of 2014 compared to the same period of 2013, as more fully described below.

Revenues -

Total revenues increased$305 million, in the first three months of 2014, compared to the same period of 2013, primarily due to increased Transmission revenue and increased sales volumes in Governmental Aggregation, Mass Market sales, and POLR and Structured Sales channels, partially offset by a decline in wholesale sales. Revenues were also impacted by higher unit prices compared to 2013 as a result of increased channel pricing and ancillary pass-through revenues associated with PJM expenses incurred in January 2014.

The increase in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase
Revenues by Type of Service	2014		2013		(Decrease)
	(In millions)
Direct	$	713	$	694	$	19
Governmental Aggregation	320		292		28
Mass Market	142		117		25
POLR and Structured	350		287		63
Wholesale	157		60		97
Transmission	107		40		67
Other	40		34		6
Total Revenues	$	1,829	$	1,524	$	305

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	Three Months Ended March 31		Increase
MWH Sales by Channel	2014	2013	(Decrease)
	(In thousands)
Direct	12,801	13,341	(4.0	)%
Governmental Aggregation	5,769	5,386	7.1	%
Mass Market	2,126	1,780	19.4	%
POLR and Structured	7,736	5,678	36.2	%
Total MWH Sales	28,432	26,185	8.6	%

The following table summarizes the price and volume factors contributing to changes in revenues:

	Source of Change in Revenues
	Increase (Decrease)
MWH Sales Channel:	Sales Volumes			Prices			Financially Settled Contracts		Capacity Revenue			Total
	(In millions)
Direct	$	(28	)	$	47		$	—	$	—		$	19
Governmental Aggregation	21			7			—		—			28
Mass Market	23			2			—		—			25
POLR and Structured Sales	104			(41		)	—		—			63
Wholesale	—			—			102		(5		)	97

The increase in Direct revenues of $19 million resulted from higher unit prices, partially offset by lower sales volumes from large commercial and industrial customers. Direct sales volumes decreased due to FES’ strategy to be more selective in customers targeted in response to the current market environment. The increase in Governmental Aggregation revenues of $28 million primarily reflects increased weather-related usage resulting from heating degree days that were 17% higher than the first quarter of 2013 and higher unit prices. The increase in Mass Market of $25 million resulted from the acquisition of new customers primarily in Ohio and Pennsylvania, increased weather-related usage and higher unit prices. The Direct, Governmental Aggregation and Mass Market customer base remained at 2.7 million customers as of March 31, 2014. Higher unit prices in each of the above sales channels resulted from increased channel pricing. Additionally, higher Direct unit prices were impacted by approximately $33 million of ancillary pass-through revenues associated with PJM expenses incurred in January 2014 as more fully described below.

The increase in POLR and structured revenues of $63 million was due to higher POLR and structured sales volumes primarily as a result of increased weather-related usage described above. Lower structured unit prices were primarily due to extreme weather and market conditions in January 2014 that reduced the gains on various structured financial sales contracts, partially offset by higher POLR rates associated with recent auctions.

Wholesale revenues increased $97 million due to higher net gains of $102 million on financially settled contracts, primarily with AE Supply, and a $5 million decrease in capacity revenues resulting primarily from reduced PJM tariff payments on RMR units. Increased gains on financially settled contracts with AE Supply resulted from higher market prices associated with extreme weather and market conditions in January 2014.

Transmission revenue increased $67 million due to higher congestion and ancillary revenue associated with additional retail load.

Other revenue increased $6 million primarily due to higher lease revenues from additional repurchased equity interests in affiliated sale and leasebacks since the first quarter of 2013. FES earns lease revenue associated with the equity interests it purchased.

Operating Expenses -

Total operating expenses increased by $548 million in the first three months of 2014 compared to the same period of 2013.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2014 compared with the same period of 2013:

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	Source of Change
	Increase (Decrease)
Operating Expense	Volumes			Prices			Financially Settled Contracts			Capacity Expense		Total
	(In millions)
Fossil Fuel	$	16		$	(1	)	$	—		$	—	$	15
Nuclear Fuel	(7		)	11			—			—		4
Non-affiliated Purchased Power(1)	84			844			(453		)	48		523
Affiliated Purchased Power	4			(2		)	(70		)	—		(68		)

⁽¹⁾ Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power and are included within Gain on Settled Contracts.

Fuel costs increased$19 million primarily due to higher fossil generation volumes and nuclear prices from higher fuel costs, partially offset by lower nuclear generation volumes due to an increase in outages in the first quarter of 2014.

Non-affiliated purchased power costs increased $523 million due to increased prices ($844 million), higher volumes ($84 million) and higher capacity expenses ($48 million), partially offset by gains on financially settled contracts ($453 million). The increase in rate was primarily a result of higher on-peak prices from extreme weather and market conditions in January 2014, partially offset by gains on financially settled contract hedges. Higher purchased volumes were primarily due to increased sales volume requirements, planned outages, and the timing of unplanned outages and derates during on-peak hours. The increase in capacity expense was the result of higher capacity rates primarily in the MAAC zone and increased sales volumes.

Affiliated purchased power costs decreased $68 million as a result of net gains on financially settled contracts with AE Supply, partially offset by increased volume purchases from the Ohio Companies as a result of increased generation by Perry at slightly lower rates.

Other operating expenses increased$73 million in the first three months of 2014, compared to the same period of 2013 due to the following:

• Fossil operating costs decreased $12 million due primarily to fewer planned outage days in the first quarter of 2014 as compared to the same period of 2013.

• Nuclear operating costs increased $15 million as a result of higher contractor, materials and equipment costs associated with the refueling outage at Davis-Besse that began on February 1, 2014. In the same period of 2013, there was a single refueling outage at Perry that began on March 18, 2013.

• Transmission expenses increased $88million due primarily to higher operating reserve and market-based ancillary costs associated with the extreme weather and market conditions in January 2014. These ancillary charges from PJM were for system reliability and a portion of which are able to be passed through to commercial and industrial customers. Additionally, effective June 1, 2013, network expenses associated with POLR sales in Pennsylvania became the responsibility of suppliers.

• Other operating expenses decreased $18 million primarily due to a decrease in mark-to-market expense on commodity contract positions.

Other Expense -

Total other expense decreased $85 million in the first three months of 2014, compared to the same period of 2013, primarily due to a $66 million loss on debt redemptions in connection with senior notes that were repurchased in 2013, lower net interest expense of $18 million due to debt redemptions and higher investment income of $3 million on NDT investments.

Discontinued Operations -

Discontinued operations increased net income in the first quarter of 2014 compared to the same period of last year primarily due to a pre-tax gain of approximately $177 million associated with the sale of a hydro asset described above.

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.

98

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 March 31, 2014, 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 9, Regulatory Matters, and Note 10, 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 March 31, 2014, there were no material changes to the risk factors included in our Annual Report or Form 10-K for the year ended December 31, 2013.

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

None.

ITEM 3.        DEFAULTS UPON SENIOR SECURITIES

None

ITEM 4.        MINE SAFETY DISCLOSURES

Not Applicable

ITEM 5.        OTHER INFORMATION

None

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ITEM 6.        EXHIBITS

Exhibit Number
FirstEnergy
	10.1	Amendment, dated as of March 31, 2014, to the Credit Agreement, dated as of June 17, 2011, as amended as of May 8, 2012, May 8, 2013 and October 31, 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 (incorporated by reference to FE's Form 8-K filed April 4, 2014, Exhibit 10-1, File No. 333-21011).
	10.2	Amendment, dated as of March 31, 2014 to the Credit Agreement, dated as of May 8, 2012, and as amended as of May 8, 2013, among FirstEnergy Transmission, LLC, American Transmission Systems, Incorporated and Trans-Allegheny Interstate Line Company, as borrowers, and PNC Bank, National Association, as administrative agent, and the lending banks and fronting banks identified therein (incorporated by reference to FE's Form 8-K filed April 4, 2014, Exhibit 10-3, File No. 333-21011).
	10.3	Term Loan Credit Agreement, dated as of March 31, 2014, among FE, as borrower, the banks named therein and The Royal Bank of Scotland, plc, as administrative agent (incorporated by reference to FE's Form 8-K filed April 4, 2014, Exhibit 10.4, File No. 333-21011).
(A)	12	Fixed charge ratio
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2014, 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
	10.1(b)	Amendment, dated as of March 31, 2014, to the Credit Agreement, dated as of June 17, 2011, as amended as of October 3, 2011, May 8, 2012, May 8, 2013 and October 31, 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 (incorporated by reference to FES's Form 8-K filed April 4, 2014, Exhibit 10.2, File No. 000-53742).
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended March 31, 2014, 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.

100

SIGNATURES

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

May 6, 2014

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

/s/ K. Jon Taylor

K. Jon Taylor

Vice President, Controller

and Chief Accounting Officer 

101

EXHIBIT INDEX

Exhibit Number
FirstEnergy
	10.1	Amendment, dated as of March 31, 2014, to the Credit Agreement, dated as of June 17, 2011, as amended as of May 8, 2012, May 8, 2013 and October 31, 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 (incorporated by reference to FE's Form 8-K filed April 4, 2014, Exhibit 10-1, File No. 333-21011).
	10.2	Amendment, dated as of March 31, 2014 to the Credit Agreement, dated as of May 8, 2012, and as amended as of May 8, 2013, among FirstEnergy Transmission, LLC, American Transmission Systems, Incorporated and Trans-Allegheny Interstate Line Company, as borrowers, and PNC Bank, National Association, as administrative agent, and the lending banks and fronting banks identified therein (incorporated by reference to FE's Form 8-K filed April 4, 2014, Exhibit 10-3, File No. 333-21011).
	10.3	Term Loan Credit Agreement, dated as of March 31, 2014, among FE, as borrower, the banks named therein and The Royal Bank of Scotland, plc, as administrative agent (incorporated by reference to FE's Form 8-K filed April 4, 2014, Exhibit 10.4, File No. 333-21011).
(A)	12	Fixed charge ratio
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended March 31, 2014, 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
	10.1(b)	Amendment, dated as of March 31, 2014, to the Credit Agreement, dated as of June 17, 2011, as amended as of October 3, 2011, May 8, 2012, May 8, 2013 and October 31, 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 (incorporated by reference to FES's Form 8-K filed April 4, 2014, Exhibit 10.2, File No. 000-53742).
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a)
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a)
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Solutions Corp. for the period ended March 31, 2014, 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.

102

EX-12

EXHIBIT 12

FIRSTENERGY CORP.

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Three Months Ended March 31
	2014			2013
	(Dollars in millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Income from continuing operations	$	122		$	192
Interest and other charges, before reduction for amounts capitalized and deferred	265			258
Capitalized interest	(22		)	(15		)
Provision for income taxes	48			114
Interest element of rentals charged to income (1)	24			25
Earnings as defined	$	437		$	574
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	265		$	258
Interest element of rentals charged to income (1)	24			25
Fixed charges as defined	$	289		$	283
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES	1.51			2.03

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

103

EX-31.1

EXHIBIT 31.1

Certification

I, Anthony J. Alexander, certify that:

1. I have reviewed this report on Form 10-Q of FirstEnergy Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2014

/s/ Anthony J. Alexander

Anthony J. Alexander

Chief Executive Officer

104

EXHIBIT 31.1

Certification

I, Donald R. Schneider, certify that:

1. I have reviewed this report on Form 10-Q of FirstEnergy Solutions Corp.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2014

/s/ Donald R. Schneider

Donald R. Schneider

Chief Executive Officer

105

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: May 6, 2014

/s/ James F. Pearson

James F. Pearson

Chief Financial Officer

106

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: May 6, 2014

/s/ James F. Pearson

James F. Pearson

Chief Financial Officer

107

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Corp. (“Company”) on Form 10-Q for the period ending March 31, 2014 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: May 6, 2014

108

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Solutions Corp. (“Company”) on Form 10-Q for the period ending March 31, 2014 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: May 6, 2014

109

XML

Accumulated Other Comprehensive Income (Details 1) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ 1,182		$ 882
Interest expense	265		258
Investment income (loss)	(22)		(18)
Total before taxes	(170)		(306)
Income taxes (benefits)	48		114
Net of tax	(208)		(196)
Loss on debt redemptions	7		117
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	452		379
Investment income (loss)	(20)		(17)
Total before taxes	159		1
Income taxes (benefits)	(56)		0
Net of tax	(13)		(2)
Loss on debt redemptions	5		71
Reclassifications from AOCI | Long-term debt | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	0	[1]	2	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes	0	[1]	1	[1]
Income taxes (benefits)	0	[1]	0	[1]
Net of tax	0	[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	(2)	[1]	(1)	[1]
Income taxes (benefits)	1	[1]	0	[1]
Net of tax	(1)	[1]	(1)	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	(2)	[1]	(3)	[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	(2)	[1]	(3)	[1]
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest and Debt Expense and Losses (Gains) on Extinguishment of Debt	2	[1]	4	[1]
Interest expense	2		2
Loss on debt redemptions			2
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(14)	[1]	(19)	[1]
Income taxes (benefits)	5	[1]	7	[1]
Net of tax	(9)	[1]	(12)	[1]
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(14)	[1]	(16)	[1]
Income taxes (benefits)	5	[1]	6	[1]
Net of tax	(9)	[1]	(10)	[1]
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(42)	[1],[2]	(47)	[1],[2]
Income taxes (benefits)	16	[1]	19	[1]
Net of tax	(26)	[1]	(28)	[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]
Income taxes (benefits)	2	[1]	1	[1]
Net of tax	$ (3)	[1]	$ (4)	[1]

[1] Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

[2] These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.

XML

Derivative Instruments (Details 3) (Not Designated as Hedging Instrument, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
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	$ (39)	[1]	$ (17)	[2]
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	(436)	[3]	11	[4]
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	17	[5]	(7)	[6]
Realized Gain (Loss) Reclassified	7	[7]	9	[8]
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	(9)		1
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	13	[1]	(10)	[2]
Power Contracts | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	(436)	[3]	11	[4]
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	12	[5]	(5)	[6]
Realized Gain (Loss) Reclassified	0	[7]	0	[8]
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	(9)		1
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	(52)	[1]	(7)	[2]
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	[3]	0	[4]
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	5	[5]	(2)	[6]
Realized Gain (Loss) Reclassified	7	[7]	9	[8]
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
FES | 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	13		(10)
FES | 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	(436)		11
FES | 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	12		(5)
FES | 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	(51)		(6)
FES | 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	5		(1)
Realized Gain (Loss) Reclassified	7		8
FES | Wholesale Sales Contract [Member] | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	$ 321

[1] Represents losses on structured financial contracts. Includes ($13) million for commodity contracts and $51 million for FTRs associated with FES.

[2] Includes $10 million for commodity contracts and $6 million for FTRs associated with FES.

[3] Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power. Includes $436 million for commodity contracts associated with FES.

[4] Includes ($11) million for commodity contracts associated with FES.

[5] Includes $12 million for commodity contracts and $5 million for FTRs associated with FES.

[6] Includes ($5) million for commodity contracts and ($1) million for FTRs associated with FES.

[7] Includes ($7) million for FTRs associated with FES.

[8] Includes ($8) million for FTRs associated with FES.

XML

Fair Value Measurements (Details 5) (Debt Securities, USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Debt Securities
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 24	$ 33
Unrecognized Gains	8	2
Fair Value	$ 32	$ 35

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
	Mar. 31, 2014		Mar. 31, 2013
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	$ 31		$ 16
Realized Gain (Loss) on Derivative Instrument	(11)		22
NUGs
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	27		18
Realized Gain (Loss) on Derivative Instrument	(10)		23
LCAPP
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	0	[1]	(2)	[1]
Realized Gain (Loss) on Derivative Instrument	0	[1]	0	[1]
Regulated FTRs
Derivative [Line Items]
Unrealized Gain (Loss) on Derivative Instrument	4		0
Realized Gain (Loss) on Derivative Instrument	$ (1)		$ (1)

[1] During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

XML

Fair Value Measurements (Details 3) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,670	[1]	$ 1,881	[2]
Unrealized Gain	44	[1]	33	[2]
Fair Value	1,714	[1]	1,914	[2]
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	433	[1]	308	[2]
Unrealized Gains	31	[1]	9	[2]
Fair Value	464	[1]	317	[2]
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	698	[1]	918	[2]
Unrealized Gain	22	[1]	17	[2]
Fair Value	720	[1]	935	[2]
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	308	[1]	207	[2]
Unrealized Gains	19	[1]	0	[2]
Fair Value	$ 327	[1]	$ 207	[2]

[1] Excludes short-term cash investments: FE Consolidated - $324 million; FES - $276 million

[2] Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 million

XML

Commitments, Guarantees and Contingencies (Tables)

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations

The following table discloses the additional credit contingent contractual obligations as ofMarch 31, 2014:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	461	$	6	$	49	$	516
BB+/Ba1 Credit Ratings	$	497	$	6	$	49	$	552
Full impact of credit contingent contractual obligations	$	796	$	58	$	87	$	941

XML

Derivative Instruments (Details Textuals) (USD $)	3 Months Ended										3 Months Ended		3 Months Ended			3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014 Commodity contracts	Mar. 31, 2014 NUGs	Mar. 31, 2014 FTRs	Mar. 31, 2014 FES Commodity contracts	Mar. 31, 2014 FES FTRs	Mar. 31, 2014 JCP&L contracts	Oct. 22, 2013 JCP&L appeal	Mar. 31, 2014 Cash Flow Hedges agreements	Dec. 31, 2013 Cash Flow Hedges agreements	Mar. 31, 2014 Fair Value Hedging agreements	Mar. 31, 2013 Fair Value Hedging	Dec. 31, 2013 Fair Value Hedging agreements	Mar. 31, 2013 Interest Rate Swap
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 1,000,000		$ 2,000,000
Gain (loss) on cash flow hedge expected to be reclassified to earnings in next twelve months	9,000,000
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	57,000,000		59,000,000
Losses to be amortized to interest expenses during next twelve months											(9,000,000)		11,000,000
Interest expense	265,000,000	258,000,000														(2,000,000)
Number of fixed-for-floating interest rate swap agreements outstanding													0		0
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	41,000,000		44,000,000
Reclassifications from long-term debt													3,000,000	6,000,000
Number of outstanding commodity or interest rate derivatives													0		0
Net asset position under commodity derivative contracts				117,000,000
Collateral posted							85,000,000	4,000,000
Additional collateral related to commodity derivatives							11,000,000
Possible adverse change in quoted market prices of derivative instruments	10.00%
Possible decrease net income due to ten percent adverse change in commodity prices	40,000,000
Liability position					185,000,000	1,000,000		3,000,000
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

XML

Discontinued Operations

3 Months Ended

Mar. 31, 2014

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

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. The asset purchase agreement was entered into on August 23, 2013, and amended and restated as of September 4, 2013. On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $394 million (FES - $307 million). The carrying value of the assets sold was $235 million (FES - $122 million), including goodwill of $29 million (FES - $1 million) which was allocated to the hydroelectric plants to be sold.

Pre-tax income for the hydroelectric facilities of $155 million and $6 million (FES - $186 million and $5 million) for the three months ended March 31, 2014 and 2013, respectively, were reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations. Included in income from discontinued operations in the three months ended March 31, 2014, was a pre-tax gain on the sale of assets of $142 million (FES - $177 million). Revenues for the hydroelectric facilities of $5 million and $6 million (FES - $5 million and $6 million) for the three months ended March 31, 2014 and 2013, respectively, are reported in FirstEnergy's and FES' Consolidated Statement of Income as discontinued operations.

XML

Fair Value Measurements (Details Textuals) (USD $)	3 Months Ended			0 Months Ended	3 Months Ended			3 Months Ended			3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014 Revolving Credit Facility credit_facility	Mar. 31, 2014 NUG contracts	Mar. 31, 2014 FirstEnergy Revolving Credit Facility	Mar. 31, 2014 FE Revolving Credit Facility	Mar. 31, 2014 FES	Mar. 31, 2013 FES	Dec. 31, 2013 FES	Mar. 31, 2014 FES Revolving Credit Facility	Mar. 31, 2014 FES and AE Supply Revolving Credit Facility	Mar. 31, 2014 FET Revolving Credit Facility	Mar. 31, 2014 ATSI Revolving Credit Facility	Mar. 29, 2014 ATSI Revolving Credit Facility	Mar. 31, 2014 TrAIL Revolving Credit Facility	Mar. 29, 2014 TrAIL Revolving Credit Facility	Mar. 31, 2014 PCRB FG and NG	Mar. 31, 2014 PCRB FG	Mar. 31, 2014 PCRB NG	Apr. 02, 2014 PCRB PN Subsequent Event	Apr. 02, 2014 PCRB ME Subsequent Event	Mar. 31, 2014 Variable Rate Term Loan Due 2019 Term Loan FirstEnergy	Mar. 31, 2014 PRCB Put Date June 3, 2019 PCRB FG and NG	Mar. 31, 2014 PCRB Put Date December 3, 2018 PCRB FG and NG
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	$ 9,000,000		$ 10,000,000					$ 8,000,000		$ 9,000,000
Cash balance excluded from available for sale securities	324,000,000		204,000,000					276,000,000		135,000,000
Investments not required to be disclosed	635,000,000		636,000,000
Number of credit facilities extended				3
Increase (decrease) of maximum borrowing capacity						1,000,000,000	1,000,000,000					(1,000,000,000)
Line of Credit Facility, Maximum Borrowing Capacity						3,500,000,000.0	3,500,000,000.0					1,500,000,000.0	1,000,000,000	500,000,000	100,000,000	400,000,000	200,000,000
Loss on debt redemptions	7,000,000	117,000,000				5,000,000		5,000,000	71,000,000		3,000,000
Debt instrument, face amount																		417,000,000					1,000,000,000	182,000,000	235,000,000
Stated interest rate percentage																								4.00%	3.75%
Face amount of debt repurchased																			$ 197,000,000	$ 16,000,000	$ 45,000,000	$ 29,000,000

XML

Variable Interest Entities (Details Textuals) (USD $)	3 Months Ended					3 Months Ended		1 Months Ended	0 Months Ended	12 Months Ended
	Mar. 31, 2014 entities	Mar. 31, 2013	Mar. 31, 2014 Power Purchase Agreements agreements	Mar. 31, 2014 OE	Mar. 31, 2014 Other FE subsidiaries	Mar. 31, 2014 Other FE subsidiaries Power Purchase Agreements	Mar. 31, 2013 Other FE subsidiaries Power Purchase Agreements	Mar. 31, 2013 FGCO Bruce Mansfield Plant	Feb. 12, 2014 Nuclear Generation Corp Beaver Valley Unit 2	Dec. 31, 2013 Nuclear Generation Corp Beaver Valley Unit 2	Mar. 31, 2014 Path-WV	Mar. 31, 2014 Signal Peak Global Holding FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest					0.00%							33.33%
Equity interest by unaffiliated third party in PNBV	3.00%
Equity interest by OES Ventures in PNBV				3.00%
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			20
Number of contracts that may contain variable interest	2
Purchased power	$ 1,455,000,000	$ 946,000,000				$ 61,000,000	$ 49,000,000
Purchase of lessor equity interests in sale and leaseback, value								221,000,000	94,000,000	23,000,000
Net present value of FirstEnergy's consolidated sale and leaseback operating lease commitments	$ 1,100,000,000

XML

Pension and Other Postemployment Benefits (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	$ 42	$ 49
Interest costs	100	93
Expected return on plan assets	(115)	(125)
Amortization of prior service cost (credit)	2	3
Net periodic costs (credits)	29	20
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	2	3
Interest costs	10	9
Expected return on plan assets	(8)	(8)
Amortization of prior service cost (credit)	(44)	(50)
Net periodic costs (credits)	(40)	(46)
FirstEnergy | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	21	11
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	(27)	(30)
FES | Pensions
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	4	5
Net periodic benefit expense (credit)	4	3
FES | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	(5)	(5)
Net periodic benefit expense (credit)	$ (4)	$ (3)

XML

Derivative Instruments (Details 1) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Derivative Assets
Fair Value	$ 314	$ 239
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(189)	(110)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(4)	(9)
Net Fair Value	121	120
Derivative Liabilities
Fair Value	(383)	(347)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	189	110
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	3	12
Net Fair Value	(191)	(225)
Power Contracts
Derivative Assets
Fair Value	304	215
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(182)	(106)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(4)	(9)
Net Fair Value	118	100
Derivative Liabilities
Fair Value	(187)	(113)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	182	106
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	2	7
Net Fair Value	(3)	0
FTRs
Derivative Assets
Fair Value	7	4
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(7)	(4)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
Derivative Liabilities
Fair Value	(8)	(12)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	7	4
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	1	5
Net Fair Value	0	(3)
NUGs
Derivative Assets
Fair Value	3	20
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	3	20
Derivative Liabilities
Fair Value	(188)	(222)
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	$ (188)	$ (222)

XML

Supplemental Guarantor Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Condensed Financial Statements, Captions [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation	$ 69	$ 2
Consolidating Statements of Income
Revenues	2,739	2,388
OPERATING EXPENSES:
Fuel	617	630
Purchased power	1,455	946
Other operating expenses	1,182	882
Provision for depreciation	294	293
General taxes	271	265
Total operating expenses	3,791	3,075
OPERATING INCOME (LOSS)	398	648
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(7)	(117)
Investment income	22	18
Interest expense	(265)	(258)
Capitalized interest	22	15
Total other income (expense)	(228)	(342)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	170	306
INCOME TAXES (BENEFITS)	48	114
INCOME FROM CONTINUING OPERATIONS	122	192
Discontinued operations (Note 13)	86	4
NET INCOME (LOSS)	208	196
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	208	196
Pension and OPEB prior service costs	(42)	(46)
Amortized loss (gain) on derivative hedges	0	1
Change in unrealized gain on available-for-sale securities	21	5
Other comprehensive income (loss)	(21)	(40)
Income taxes (benefits) on other comprehensive income (loss)	(8)	(16)
Net other comprehensive income (loss)	(13)	(24)
COMPREHENSIVE INCOME (LOSS)	195	172
FES
Consolidating Statements of Income
Revenues	1,797	1,496
OPERATING EXPENSES:
Fuel	0	0
Other operating expenses	228	162
Provision for depreciation	2	1
General taxes	21	20
Total operating expenses	1,921	1,701
OPERATING INCOME (LOSS)	(124)	(205)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(3)	(71)
Investment income	1	1
Miscellaneous income, including net income from equity investees	103	192
Capitalized interest	0	0
Total other income (expense)	84	95
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(40)	(110)
INCOME TAXES (BENEFITS)	(52)	(112)
INCOME FROM CONTINUING OPERATIONS	12	2
Discontinued operations (Note 13)	0	0
NET INCOME (LOSS)	12	2
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	12	2
Pension and OPEB prior service costs	(5)	(6)
Amortized loss (gain) on derivative hedges	(2)	(1)
Change in unrealized gain on available-for-sale securities	19	5
Other comprehensive income (loss)	12	(2)
Income taxes (benefits) on other comprehensive income (loss)	4	(1)
Net other comprehensive income (loss)	8	(1)
COMPREHENSIVE INCOME (LOSS)	20	1
FES | Affiliates
OPERATING EXPENSES:
Purchased power	645	1,013
OTHER INCOME (EXPENSE):
Interest expense	(3)	(2)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	1,025	505
OTHER INCOME (EXPENSE):
Interest expense	(14)	(25)
FGCO
Condensed Financial Statements, Captions [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation	70	2
Consolidating Statements of Income
Revenues	315	531
OPERATING EXPENSES:
Fuel	272	247
Other operating expenses	62	74
Provision for depreciation	29	31
General taxes	11	11
Total operating expenses	378	364
OPERATING INCOME (LOSS)	(63)	167
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(1)	0
Investment income	1	0
Miscellaneous income, including net income from equity investees	0	1
Capitalized interest	1	0
Total other income (expense)	(24)	(28)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(87)	139
INCOME TAXES (BENEFITS)	(31)	51
INCOME FROM CONTINUING OPERATIONS	(56)	88
Discontinued operations (Note 13)	116	3
NET INCOME (LOSS)	60	91
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	60	91
Pension and OPEB prior service costs	(4)	(5)
Amortized loss (gain) on derivative hedges	0	0
Change in unrealized gain on available-for-sale securities	0	0
Other comprehensive income (loss)	(4)	(5)
Income taxes (benefits) on other comprehensive income (loss)	(2)	(2)
Net other comprehensive income (loss)	(2)	(3)
COMPREHENSIVE INCOME (LOSS)	58	88
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power	0	0
OTHER INCOME (EXPENSE):
Interest expense	(1)	(1)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power	4	1
OTHER INCOME (EXPENSE):
Interest expense	(24)	(28)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues	362	440
OPERATING EXPENSES:
Fuel	47	53
Other operating expenses	150	131
Provision for depreciation	43	44
General taxes	7	6
Total operating expenses	311	296
OPERATING INCOME (LOSS)	51	144
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(1)	0
Investment income	21	18
Miscellaneous income, including net income from equity investees	0	0
Capitalized interest	11	9
Total other income (expense)	17	11
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	68	155
INCOME TAXES (BENEFITS)	26	58
INCOME FROM CONTINUING OPERATIONS	42	97
Discontinued operations (Note 13)	0	0
NET INCOME (LOSS)	42	97
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	42	97
Pension and OPEB prior service costs	0	0
Amortized loss (gain) on derivative hedges	0	0
Change in unrealized gain on available-for-sale securities	19	5
Other comprehensive income (loss)	19	5
Income taxes (benefits) on other comprehensive income (loss)	7	2
Net other comprehensive income (loss)	12	3
COMPREHENSIVE INCOME (LOSS)	54	100
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power	64	62
OTHER INCOME (EXPENSE):
Interest expense	(1)	(1)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	0
OTHER INCOME (EXPENSE):
Interest expense	(13)	(15)
Eliminations
Consolidating Statements of Income
Revenues	(645)	(943)
OPERATING EXPENSES:
Fuel	0	0
Other operating expenses	12	12
Provision for depreciation	0	(1)
General taxes	0	0
Total operating expenses	(633)	(932)
OPERATING INCOME (LOSS)	(12)	(11)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	0	0
Investment income	(3)	(2)
Miscellaneous income, including net income from equity investees	(103)	(191)
Capitalized interest	0	0
Total other income (expense)	(88)	(174)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(100)	(185)
INCOME TAXES (BENEFITS)	1	3
INCOME FROM CONTINUING OPERATIONS	(101)	(188)
Discontinued operations (Note 13)	0	0
NET INCOME (LOSS)	(101)	(188)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	(101)	(188)
Pension and OPEB prior service costs	4	5
Amortized loss (gain) on derivative hedges	0	0
Change in unrealized gain on available-for-sale securities	(19)	(5)
Other comprehensive income (loss)	(15)	0
Income taxes (benefits) on other comprehensive income (loss)	(5)	0
Net other comprehensive income (loss)	(10)	0
COMPREHENSIVE INCOME (LOSS)	(111)	(188)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power	(645)	(943)
OTHER INCOME (EXPENSE):
Interest expense	3	3
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power	0	0
OTHER INCOME (EXPENSE):
Interest expense	15	16
FES
Condensed Financial Statements, Captions [Line Items]
Discontinued Operation, Tax Effect of Discontinued Operation	70	2
Consolidating Statements of Income
Revenues	1,829	1,524
OPERATING EXPENSES:
Fuel	319	300
Other operating expenses	452	379
Provision for depreciation	74	75
General taxes	39	37
Total operating expenses	1,977	1,429
OPERATING INCOME (LOSS)	(148)	95
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(5)	(71)
Investment income	20	17
Miscellaneous income, including net income from equity investees	0	2
Capitalized interest	12	9
Total other income (expense)	(11)	(96)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(159)	(1)
INCOME TAXES (BENEFITS)	(56)	0
INCOME FROM CONTINUING OPERATIONS	(103)	(1)
Discontinued operations (Note 13)	116	3
NET INCOME (LOSS)	13	2
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME	13	2
Pension and OPEB prior service costs	(5)	(6)
Amortized loss (gain) on derivative hedges	(2)	(1)
Change in unrealized gain on available-for-sale securities	19	5
Other comprehensive income (loss)	12	(2)
Income taxes (benefits) on other comprehensive income (loss)	4	(1)
Net other comprehensive income (loss)	8	(1)
COMPREHENSIVE INCOME (LOSS)	21	1
FES | Affiliates
OPERATING EXPENSES:
Purchased power	64	132
OTHER INCOME (EXPENSE):
Interest expense	(2)	(1)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power	1,029	506
OTHER INCOME (EXPENSE):
Interest expense	$ (36)	$ (52)

XML

Fair Value Measurements (Details 4) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
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	$ 621	$ 539
Realized Gains	28	24
Realized Losses	(16)	(6)
OTTI	(2)	(7)
Interest and Dividend Income	25	26
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	423	252
Realized Gains	19	20
Realized Losses	(5)	(3)
OTTI	(2)	(7)
Interest and Dividend Income	$ 15	$ 13

XML

Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Tax effect of discontinued operations	$ 69	$ 2
FES
Tax effect of discontinued operations	$ 70	$ 2

XML

Supplemental Guarantor Information (Details 1) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2013	Dec. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 109	$ 218	$ 67	$ 172
Receivables-
Customers	1,869	1,720
Other Receivables	218	198
Materials and supplies, at average cost	740	752
Derivatives	247	166
Collateral	580	155
Prepayments and other	199	212
Total current assets	4,577	4,013
PROPERTY, PLANT AND EQUIPMENT:
In service	44,782	44,228
Less - Accumulated provision for depreciation	13,555	13,280
Property, plant and equipment in service net of accumulated provision for depreciation	31,227	30,948
Construction work in progress	2,661	2,304
Total net property, plant and equipment	33,888	33,252
INVESTMENTS:
Nuclear plant decommissioning trusts	2,263	2,201
Other	898	903
Total other property and investments	3,161	3,104
ASSETS HELD FOR SALE	0	235
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418	6,447
Other	1,386	1,548
Total deferred charges and other assets	9,602	9,820
Total assets	51,228	50,424	50,424
CURRENT LIABILITIES:
Currently payable long-term debt	1,416	1,415
Accounts payable-
Accrued taxes	527	485
Derivatives	159	111
Other	863	621
Total current liabilities	7,737	7,637
CAPITALIZATION:
Total equity	12,602	12,692
Long-term debt and other long-term obligations	16,804	15,831
Total capitalization	29,409	28,526
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	850	858
Accumulated deferred income taxes	7,028	6,968
Asset retirement obligations	1,704	1,678
Retirement benefits	2,713	2,689
Other	1,532	1,778
Total noncurrent liabilities	14,082	14,261
Total liabilities and capitalization	51,228	50,424
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	583	539
Affiliated companies	278	938
Other Receivables	60	52
Notes receivable from affiliated companies	457	203
Materials and supplies, at average cost	63	76
Derivatives	244	165
Collateral	544	136
Prepayments and other	100	52
Total current assets	2,329	2,161
PROPERTY, PLANT AND EQUIPMENT:
In service	106	104
Less - Accumulated provision for depreciation	30	28
Property, plant and equipment in service net of accumulated provision for depreciation	76	76
Construction work in progress	26	23
Total net property, plant and equipment	102	99
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	5,891	5,801
Other	0	0
Total other property and investments	5,891	5,801
ASSETS HELD FOR SALE		0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	91	95
Goodwill	23	23
Property taxes	0	0
Unamortized sale and leaseback costs	0	0
Derivatives	65	53
Other	72	81
Total deferred charges and other assets	251	252
Total assets	8,573	8,313
CURRENT LIABILITIES:
Currently payable long-term debt	1	1
Short-term borrowings	550	0
Accounts payable-
Affiliated companies	373	741
Other	183	94
Accrued taxes	3	204
Derivatives	159	110
Other	51	70
Total current liabilities	1,956	2,197
CAPITALIZATION:
Total equity	5,807	5,312
Long-term debt and other long-term obligations	712	712
Total capitalization	6,519	6,024
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	11	32
Asset retirement obligations	0	0
Retirement benefits	22	22
Derivatives	36	14
Other	29	24
Total noncurrent liabilities	98	92
Total liabilities and capitalization	8,573	8,313
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	636	977
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	2	3	3
Receivables-
Customers	0	0
Affiliated companies	185	787
Other Receivables	18	12
Notes receivable from affiliated companies	449	23
Materials and supplies, at average cost	148	159
Derivatives	0	0
Collateral	0	0
Prepayments and other	79	50
Total current assets	881	1,033
PROPERTY, PLANT AND EQUIPMENT:
In service	6,148	6,105
Less - Accumulated provision for depreciation	1,978	1,953
Property, plant and equipment in service net of accumulated provision for depreciation	4,170	4,152
Construction work in progress	130	148
Total net property, plant and equipment	4,300	4,300
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	11	11
Total other property and investments	11	11
ASSETS HELD FOR SALE		122
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	105	131
Customer intangibles	0	0
Goodwill	0	0
Property taxes	11	15
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	223	228
Total deferred charges and other assets	339	374
Total assets	5,531	5,840
CURRENT LIABILITIES:
Currently payable long-term debt	120	367
Short-term borrowings	5	4
Accounts payable-
Affiliated companies	19	400
Other	112	196
Accrued taxes	68	23
Derivatives	0	0
Other	62	63
Total current liabilities	669	1,265
CAPITALIZATION:
Total equity	2,343	2,283
Long-term debt and other long-term obligations	2,094	1,860
Total capitalization	4,437	4,143
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	0	0
Asset retirement obligations	188	187
Retirement benefits	167	163
Derivatives	0	0
Other	70	82
Total noncurrent liabilities	425	432
Total liabilities and capitalization	5,531	5,840
FGCO | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	283	212
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	180	227
Other Receivables	73	17
Notes receivable from affiliated companies	230	683
Materials and supplies, at average cost	216	213
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	7
Total current assets	699	1,147
PROPERTY, PLANT AND EQUIPMENT:
In service	6,925	6,645
Less - Accumulated provision for depreciation	3,038	2,962
Property, plant and equipment in service net of accumulated provision for depreciation	3,887	3,683
Construction work in progress	1,200	1,137
Total net property, plant and equipment	5,087	4,820
INVESTMENTS:
Nuclear plant decommissioning trusts	1,323	1,276
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,323	1,276
ASSETS HELD FOR SALE		0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	19	26
Unamortized sale and leaseback costs	0	0
Derivatives	0	0
Other	9	18
Total deferred charges and other assets	28	44
Total assets	7,137	7,287
CURRENT LIABILITIES:
Currently payable long-term debt	366	547
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	240	362
Other	0	0
Accrued taxes	38	23
Derivatives	0	0
Other	21	18
Total current liabilities	665	1,101
CAPITALIZATION:
Total equity	3,548	3,493
Long-term debt and other long-term obligations	931	742
Total capitalization	4,479	4,235
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	763	736
Asset retirement obligations	841	828
Retirement benefits	0	0
Derivatives	0	0
Other	389	387
Total noncurrent liabilities	1,993	1,951
Total liabilities and capitalization	7,137	7,287
Nuclear Generation Corp | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	0	151
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(274)	(916)
Other Receivables	0	0
Notes receivable from affiliated companies	(921)	(909)
Materials and supplies, at average cost	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	(1,195)	(1,825)
PROPERTY, PLANT AND EQUIPMENT:
In service	(383)	(382)
Less - Accumulated provision for depreciation	(189)	(188)
Property, plant and equipment in service net of accumulated provision for depreciation	(194)	(194)
Construction work in progress	0	0
Total net property, plant and equipment	(194)	(194)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(5,891)	(5,801)
Other	0	0
Total other property and investments	(5,891)	(5,801)
ASSETS HELD FOR SALE		0
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(105)	(131)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Unamortized sale and leaseback costs	197	168
Derivatives	0	0
Other	(154)	(155)
Total deferred charges and other assets	(62)	(118)
Total assets	(7,342)	(7,938)
CURRENT LIABILITIES:
Currently payable long-term debt	(22)	(23)
Short-term borrowings	0	0
Accounts payable-
Affiliated companies	(305)	(738)
Other	0	0
Accrued taxes	(12)	(184)
Derivatives	0	0
Other	80	46
Total current liabilities	(1,178)	(1,808)
CAPITALIZATION:
Total equity	(5,865)	(5,776)
Long-term debt and other long-term obligations	(1,186)	(1,184)
Total capitalization	(7,051)	(6,960)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	850	858
Accumulated deferred income taxes	36	(27)
Asset retirement obligations	0	0
Retirement benefits	0	0
Derivatives	0	0
Other	1	(1)
Total noncurrent liabilities	887	830
Total liabilities and capitalization	(7,342)	(7,938)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	(919)	(909)
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2	3	3
Receivables-
Customers	583	539
Affiliated companies	369	1,036
Other Receivables	151	81
Notes receivable from affiliated companies	215	0
Materials and supplies, at average cost	427	448
Derivatives	244	165
Collateral	544	136
Prepayments and other	179	109
Total current assets	2,714	2,516
PROPERTY, PLANT AND EQUIPMENT:
In service	12,796	12,472
Less - Accumulated provision for depreciation	4,857	4,755
Property, plant and equipment in service net of accumulated provision for depreciation	7,939	7,717
Construction work in progress	1,356	1,308
Total net property, plant and equipment	9,295	9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	1,323	1,276
Investment in affiliated companies	0	0
Other	11	11
Total other property and investments	1,334	1,287
ASSETS HELD FOR SALE	0	122
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	91	95
Goodwill	23	23
Property taxes	30	41
Unamortized sale and leaseback costs	197	168
Derivatives	65	53
Other	150	172
Total deferred charges and other assets	556	552
Total assets	13,899	13,502
CURRENT LIABILITIES:
Currently payable long-term debt	465	892
Short-term borrowings	555	4
Accounts payable-
Affiliated companies	327	765
Other	295	290
Accrued taxes	97	66
Derivatives	159	110
Other	214	197
Total current liabilities	2,112	2,755
CAPITALIZATION:
Total equity	5,833	5,312
Long-term debt and other long-term obligations	2,551	2,130
Total capitalization	8,384	7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	850	858
Accumulated deferred income taxes	810	741
Asset retirement obligations	1,029	1,015
Retirement benefits	189	185
Derivatives	36	14
Other	489	492
Total noncurrent liabilities	3,403	3,305
Total liabilities and capitalization	13,899	13,502
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$ 0	$ 431

XML

Fair Value Measurements (Details) (Recurring, USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Assets
Fair value, assets	$ 2,877		$ 2,865
Liabilities
Fair value, liabilities	(383)		(347)
Net assets (liabilities)	2,494	[1]	2,518	[1]
FES
Assets
Fair value, assets	1,624		1,485
Liabilities
Fair value, liabilities	(195)		(124)
Net assets (liabilities)	1,429	[2]	1,361	[2]
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(187)		(113)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(187)		(113)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(8)		(12)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(8)		(11)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(188)	[3]	(222)	[3]
Corporate debt securities
Assets
Fair value, assets	1,168		1,365
Corporate debt securities | FES
Assets
Fair value, assets	586		792
Commodity contracts | Derivative Assets
Assets
Fair value, assets	304		215
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	305		215
FTRs | Derivative Assets
Assets
Fair value, assets	7		4
FTRs | Derivative Assets | FES
Assets
Fair value, assets	4		3
NUG contracts | Derivative Assets
Assets
Fair value, assets	3	[3]	20	[3]
Equity securities
Assets
Fair value, assets	464	[4]	317	[4]
Equity securities | FES
Assets
Fair value, assets	327	[4]	207	[4]
Foreign government debt securities
Assets
Fair value, assets	94		109
Foreign government debt securities | FES
Assets
Fair value, assets	55		65
U.S. government debt securities
Assets
Fair value, assets	167		165
U.S. government debt securities | FES
Assets
Fair value, assets	25		27
U.S. state debt securities
Assets
Fair value, assets	237		228
U.S. state debt securities | FES
Assets
Fair value, assets	3		0
Other
Assets
Fair value, assets	433	[5]	442	[5]
Other | FES
Assets
Fair value, assets	319	[5]	176	[5]
Level 1
Assets
Fair value, assets	529		511
Liabilities
Fair value, liabilities	(8)		(13)
Net assets (liabilities)	521	[1]	498	[1]
Level 1 | FES
Assets
Fair value, assets	338		214
Liabilities
Fair value, liabilities	(8)		(13)
Net assets (liabilities)	330	[2]	201	[2]
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(8)		(13)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(8)		(13)
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 | 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	11		7
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	11		7
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	464	[4]	317	[4]
Level 1 | Equity securities | FES
Assets
Fair value, assets	327	[4]	207	[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 | U.S. state debt securities | FES
Assets
Fair value, assets	0		0
Level 1 | Other
Assets
Fair value, assets	54	[5]	187	[5]
Level 1 | Other | FES
Assets
Fair value, assets	0	[5]	0	[5]
Level 2
Assets
Fair value, assets	2,338		2,330
Liabilities
Fair value, liabilities	(179)		(100)
Net assets (liabilities)	2,159	[1]	2,230	[1]
Level 2 | FES
Assets
Fair value, assets	1,282		1,268
Liabilities
Fair value, liabilities	(179)		(100)
Net assets (liabilities)	1,103	[2]	1,168	[2]
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(179)		(100)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(179)		(100)
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 | Corporate debt securities
Assets
Fair value, assets	1,168		1,365
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	586		792
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	293		208
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	294		208
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	94		109
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	55		65
Level 2 | U.S. government debt securities
Assets
Fair value, assets	167		165
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	25		27
Level 2 | U.S. state debt securities
Assets
Fair value, assets	237		228
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	3		0
Level 2 | Other
Assets
Fair value, assets	379	[5]	255	[5]
Level 2 | Other | FES
Assets
Fair value, assets	319	[5]	176	[5]
Level 3
Assets
Fair value, assets	10		24
Liabilities
Fair value, liabilities	(196)		(234)
Net assets (liabilities)	(186)	[1]	(210)	[1]
Level 3 | FES
Assets
Fair value, assets	4		3
Liabilities
Fair value, liabilities	(8)		(11)
Net assets (liabilities)	(4)	[2]	(8)	[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	(8)		(12)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(8)		(11)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(188)	[3]	(222)	[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	7		4
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	4		3
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	3	[3]	20	[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 | U.S. state debt securities | FES
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 $9 million and $10 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

[2] Excludes $8 million and $9 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

[3] NUG 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 (Tables)

3 Months Ended

Mar. 31, 2014

Statement of Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income

The changes in AOCI, net of tax, in the three months ended March 31, 2014 and 2013, 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 January 1, 2014	$	(36	)	$	9		$	311		$	284
Other comprehensive income before reclassifications	—			22			—			22
Amounts reclassified from AOCI	—			(9		)	(26		)	(35		)
Net other comprehensive income (loss)	—			13			(26		)	(13		)
AOCI Balance as of March 31, 2014	$	(36	)	$	22		$	285		$	271
AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
Other comprehensive income before reclassifications	—			15			—			15
Amounts reclassified from AOCI	1			(12		)	(28		)	(39		)
Net other comprehensive income (loss)	1			3			(28		)	(24		)
AOCI Balance as of March 31, 2013	$	(37	)	$	18		$	380		$	361
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, 2014	$	(1	)	$	8		$	47		$	54
Other comprehensive income before reclassifications	—			21			—			21
Amounts reclassified from AOCI	(1		)	(9		)	(3		)	(13		)
Net other comprehensive income (loss)	(1		)	12			(3		)	8
AOCI Balance as of March 31, 2014	$	(2	)	$	20		$	44		$	62
AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
Other comprehensive income before reclassifications	—			14			—			14
Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
Net other comprehensive income (loss)	(1		)	4			(4		)	(1		)
AOCI Balance as of March 31, 2013	$	2		$	17		$	52		$	71

Reclassification out of Accumulated Other Comprehensive Income

The following amounts were reclassified from AOCI in the three months ended March 31, 2014 and 2013:

FE	Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(2	)	$	(3	)	Other operating expenses
Long-term debt	2			4			Interest expense ($2) in 2014 and Interest expense ($2) and loss on debt redemptions ($2) in 2013
	—			1			Total before taxes
	—			—			Income taxes
	$	—		$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(14	)	$	(19	)	Investment income
	5			7			Income taxes
	$	(9	)	$	(12	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(42	)	$	(47	)	(a)
	16			19			Income taxes
	$	(26	)	$	(28	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
FES	Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(2	)	$	(3	)	Other operating expenses
Long-term debt	—			2			Loss on debt redemptions
	(2		)	(1		)	Total before taxes
	1			—			Income tax benefits
	$	(1	)	$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(14	)	$	(16	)	Investment income
	5			6			Income tax benefits
	$	(9	)	$	(10	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			1			Income tax benefits
	$	(3	)	$	(4	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

XML

Pension and Other Postemployment Benefits (Tables)

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Costs

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2014			2013			2014			2013
	(In millions)
Service costs	$	42		$	49		$	2		$	3
Interest costs	100			93			10			9
Expected return on plan assets	(115		)	(125		)	(8		)	(8		)
Amortization of prior service costs (credits)	2			3			(44		)	(50		)
Net periodic costs (credits)	$	29		$	20		$	(40	)	$	(46	)

Net Periodic Pension and OPEB Costs

FES' share of the net periodic pensions and OPEB costs (credits) were as follows:

	Pensions				OPEB
For the Three Months Ended March 31,	2014		2013		2014			2013
	(In millions)
Net Periodic Costs	$	4	$	5	$	(5	)	$	(5	)

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 March 31,	2014		2013		2014			2013
	(In millions)
FirstEnergy	$	21	$	11	$	(27	)	$	(30	)
FES	4		3		(4		)	(3		)

XML

Derivative Instruments (Details 5) (Not Designated as Hedging Instrument, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (202)		$ (398)
Additions/Change in value of existing contracts	31		16
Settled contracts	(11)		22
Outstanding net asset (liability), Ending Balance	(182)		(360)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(202)		(254)
Additions/Change in value of existing contracts	27		18
Settled contracts	(10)		23
Outstanding net asset (liability), Ending Balance	(185)		(213)
LCAPP
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	0	[1]	(144)	[1]
Additions/Change in value of existing contracts	0	[1]	(2)	[1]
Settled contracts	0	[1]	0	[1]
Outstanding net asset (liability), Ending Balance	0	[1]	(146)	[1]
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	0		0
Additions/Change in value of existing contracts	4		0
Settled contracts	(1)		(1)
Outstanding net asset (liability), Ending Balance	$ 3		$ (1)

[1] During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

XML

Fair Value Measurements (Details 1) (Level 3, USD $) In Millions, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Non Utility Generation Contract
Fair Value, Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value Measurement With Unobservable Inputs Reconciliation,Recurring Basis, Asset, Terminations			$ 0	[1],[2]
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Liabilities, Terminations			0	[1],[2]
Fair Value Measurement With Unobservable Inputs, Reconciliation, Recurring Basis, Asset And Liability Terminations			0	[1],[2]
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	20	[2]	36	[2]
Beginning Balance, Derivative Liabilities	(222)	[2]	(290)	[2]
Beginning Balance, Net	(202)	[2]	(254)	[2]
Unrealized gain (loss), Derivative Assets	0	[2]	(8)	[2]
Unrealized gain (loss), Derivative Liabilities	27	[2]	(17)	[2]
Unrealized gain (loss), Net	27	[2]	(25)	[2]
Purchases, Derivative Assets			0	[2]
Purchases, Derivative Liabilities			0	[2]
Purchases, Net			0	[2]
Settlements, Derivative Assets	(17)	[2]	(8)	[2]
Settlements, Derivative Liabilities	7	[2]	85	[2]
Settlements, Net	(10)	[2]	77	[2]
Ending Balance, Derivative Assets	3	[2]	20	[2]
Ending Balance, Derivative Liabilities	(188)	[2]	(222)	[2]
Ending Balance, Net	(185)	[2]	(202)	[2]
LCAPP Contracts
Fair Value, Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value Measurement With Unobservable Inputs Reconciliation,Recurring Basis, Asset, Terminations			0	[1],[2]
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Liabilities, Terminations			166	[1],[2]
Fair Value Measurement With Unobservable Inputs, Reconciliation, Recurring Basis, Asset And Liability Terminations			166	[1],[2]
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	0	[2]	0	[2]
Beginning Balance, Derivative Liabilities	0	[2]	(144)	[2]
Beginning Balance, Net	0	[2]	(144)	[2]
Unrealized gain (loss), Derivative Assets	0	[2]	0	[2]
Unrealized gain (loss), Derivative Liabilities	0	[2]	(22)	[2]
Unrealized gain (loss), Net	0	[2]	(22)	[2]
Purchases, Derivative Assets			0	[2]
Purchases, Derivative Liabilities			0	[2]
Purchases, Net			0	[2]
Settlements, Derivative Assets	0	[2]	0	[2]
Settlements, Derivative Liabilities	0	[2]	0	[2]
Settlements, Net	0	[2]	0	[2]
Ending Balance, Derivative Assets	0	[2]	0	[2]
Ending Balance, Derivative Liabilities	0	[2]	0	[2]
Ending Balance, Net	0	[2]	0	[2]
FTRs
Fair Value, Assets and Liabilities Measured on Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value Measurement With Unobservable Inputs Reconciliation,Recurring Basis, Asset, Terminations			0	[1]
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Liabilities, Terminations			0	[1]
Fair Value Measurement With Unobservable Inputs, Reconciliation, Recurring Basis, Asset And Liability Terminations			0	[1]
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	4		8
Beginning Balance, Derivative Liabilities	(12)		(9)
Beginning Balance, Net	(8)		(1)
Unrealized gain (loss), Derivative Assets	6		3
Unrealized gain (loss), Derivative Liabilities	2		1
Unrealized gain (loss), Net	8		4
Purchases, Derivative Assets			6
Purchases, Derivative Liabilities			(15)
Purchases, Net			(9)
Settlements, Derivative Assets	(3)		(13)
Settlements, Derivative Liabilities	2		11
Settlements, Net	(1)		(2)
Ending Balance, Derivative Assets	7		4
Ending Balance, Derivative Liabilities	(8)		(12)
Ending Balance, Net	(1)		(8)
FTRs | FES
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	3		6
Beginning Balance, Derivative Liabilities	(11)		(6)
Beginning Balance, Net	(8)		0
Unrealized gain (loss), Derivative Assets	3		0
Unrealized gain (loss), Derivative Liabilities	1		(2)
Unrealized gain (loss), Net	4		(2)
Purchases, Derivative Assets			5
Purchases, Derivative Liabilities			(12)
Purchases, Net			(7)
Settlements, Derivative Assets	(2)		(8)
Settlements, Derivative Liabilities	2		9
Settlements, Net	0		1
Ending Balance, Derivative Assets	4		3
Ending Balance, Derivative Liabilities	(8)		(11)
Ending Balance, Net	$ (4)		$ (8)

[1] See Note 8, Derivative Instruments

[2] 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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Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2014

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 March 31, 2014:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,293	$	1,081	$	212
Other FE subsidiaries	716		495		221

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.1 billion.

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2014

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	March 31, 2014												December 31, 2013
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,168		$	—		$	1,168		$	—		$	1,365		$	—		$	1,365
Derivative assets - commodity contracts	11			293			—			304			7			208			—			215
Derivative assets - FTRs	—			—			7			7			—			—			4			4
Derivative assets - NUG contracts(1)	—			—			3			3			—			—			20			20
Equity securities(2)	464			—			—			464			317			—			—			317
Foreign government debt securities	—			94			—			94			—			109			—			109
U.S. government debt securities	—			167			—			167			—			165			—			165
U.S. state debt securities	—			237			—			237			—			228			—			228
Other(3)	54			379			—			433			187			255			—			442
Total assets	$	529		$	2,338		$	10		$	2,877		$	511		$	2,330		$	24		$	2,865
Liabilities
Derivative liabilities - commodity contracts	$	(8	)	$	(179	)	$	—		$	(187	)	$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—			—			(8		)	(8		)	—			—			(12		)	(12		)
Derivative liabilities - NUG contracts(1)	—			—			(188		)	(188		)	—			—			(222		)	(222		)
Total liabilities	$	(8	)	$	(179	)	$	(196	)	$	(383	)	$	(13	)	$	(100	)	$	(234	)	$	(347	)
Net assets (liabilities)(4)	$	521		$	2,159		$	(186	)	$	2,494		$	498		$	2,230		$	(210	)	$	2,518

⁽¹⁾  NUG 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 $9 million and $10 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

The following table provides a reconciliation of changes in the fair value of NUG contracts, LCAPP contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2014 and December 31, 2013:

	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, 2013 Balance	$	36		$	(290	)	$	(254	)	$	—	$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
Unrealized gain (loss)	(8		)	(17		)	(25		)	—		(22		)	(22		)	3			1			4
Purchases	—			—			—			—		—			—			6			(15		)	(9		)
Terminations(2)	—			—			—			—		166			166			—			—			—
Settlements	(8		)	85			77			—		—			—			(13		)	11			(2		)
December 31, 2013 Balance	$	20		$	(222	)	$	(202	)	$	—	$	—		$	—		$	4		$	(12	)	$	(8	)
Unrealized gain	—			27			27			—		—			—			6			2			8
Settlements	(17		)	7			(10		)	—		—			—			(3		)	2			(1		)
March 31, 2014 Balance	$	3		$	(188	)	$	(185	)	$	—	$	—		$	—		$	7		$	(8	)	$	(1	)

⁽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 and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(1	)	Model	RTO auction clearing prices	($4.20) to $7.60	$0.80	Dollars/MWH
NUG Contracts	$	(185	)	Model	Generation Electricity regional prices	600 to 5,422,000 $47.90 to $59.00	1,033,000 $53.50	MWH Dollars/MWH

Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities

The following table summarizes the amortized cost basis, unrealized gains (there were no unrealized losses) and fair values of investments held in NDT, nuclear fuel disposal and NUG trusts as of March 31, 2014 and December 31, 2013:

	March 31, 2014(1)						December 31, 2013(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,670	$	44	$	1,714	$	1,881	$	33	$	1,914
FES	698		22		720		918		17		935
Equity securities
FirstEnergy	$	433	$	31	$	464	$	308	$	9	$	317
FES	308		19		327		207		—		207

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $324 million; FES - $276 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 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 ended March 31, 2014 and 2013 were as follows:

Three Months Ended
March 31, 2014	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	621	$	28	$	(16	)	$	(2	)	$	25
FES	423		19		(5		)	(2		)	15
March 31, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	539	$	24	$	(6	)	$	(7	)	$	26
FES	252		20		(3		)	(7		)	13

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 March 31, 2014 and December 31, 2013:

	March 31, 2014						December 31, 2013
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	24	$	8	$	32	$	33	$	2	$	35

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:

	March 31, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	18,034	$	19,321	$	17,049	$	17,957
FES	2,996		3,098		3,001		3,073

FES

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FES
Recurring Fair Value Measurements	March 31, 2014												December 31, 2013
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	586		$	—		$	586		$	—		$	792		$	—		$	792
Derivative assets - commodity contracts	11			294			—			305			7			208			—			215
Derivative assets - FTRs	—			—			4			4			—			—			3			3
Equity securities(1)	327			—			—			327			207			—			—			207
Foreign government debt securities	—			55			—			55			—			65			—			65
U.S. government debt securities	—			25			—			25			—			27			—			27
U.S. state debt securities	—			3			—			3			—			—			—			—
Other(2)	—			319			—			319			—			176			—			176
Total assets	$	338		$	1,282		$	4		$	1,624		$	214		$	1,268		$	3		$	1,485
Liabilities
Derivative liabilities - commodity contracts	$	(8	)	$	(179	)	$	—		$	(187	)	$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—			—			(8		)	(8		)	—			—			(11		)	(11		)
Total liabilities	$	(8	)	$	(179	)	$	(8	)	$	(195	)	$	(13	)	$	(100	)	$	(11	)	$	(124	)
Net assets (liabilities)(3)	$	330		$	1,103		$	(4	)	$	1,429		$	201		$	1,168		$	(8	)	$	1,361

⁽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 $8 million and $9 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts

The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2014 and December 31, 2013:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2013 Balance	$	6		$	(6	)	$	—
Unrealized loss	—			(2		)	(2		)
Purchases	5			(12		)	(7		)
Settlements	(8		)	9			1
December 31, 2013 Balance	$	3		$	(11	)	$	(8	)
Unrealized gain	3			1			4
Settlements	(2		)	2			—
March 31, 2014 Balance	$	4		$	(8	)	$	(4	)

Quantitative information for level 3 valuation

The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(4	)	Model	RTO auction clearing prices	($4.20) to $7.60	$0.60	Dollars/MWH

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Consolidated Statements of Income and Comprehensive Income (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
REVENUES:
Electric sales	$ 1,450		$ 1,335
Total revenues	4,189	[1]	3,723	[1]
OPERATING EXPENSES:
Fuel	617		630
Purchased power	1,455		946
Other operating expenses	1,182		882
Provision for depreciation	294		293
General taxes	271		265
Total operating expenses	3,791		3,075
OPERATING INCOME (LOSS)	398		648
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(7)		(117)
Investment income	22		18
Interest expense	(265)		(258)
Capitalized interest	22		15
Total other income (expense)	(228)		(342)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	170		306
INCOME TAXES (BENEFITS)	48		114
INCOME FROM CONTINUING OPERATIONS	122		192
Discontinued operations (net of income taxes of $70 and $2, respectively) (Note 13)	86		4
NET INCOME (LOSS)	208		196
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	208		196
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(42)		(46)
Amortized loss (gain) on derivative hedges	0		1
Change in unrealized gain on available-for-sale securities	21		5
Other comprehensive income (loss)	(21)		(40)
Income taxes (benefits) on other comprehensive income (loss)	(8)		(16)
Net other comprehensive income (loss)	(13)		(24)
COMPREHENSIVE INCOME (LOSS)	195		172
FES
REVENUES:
Other	40		34
Total revenues	1,829		1,524
OPERATING EXPENSES:
Fuel	319		300
Other operating expenses	452		379
Provision for depreciation	74		75
General taxes	39		37
Total operating expenses	1,977		1,429
OPERATING INCOME (LOSS)	(148)		95
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(5)		(71)
Investment income	20		17
Miscellaneous income	0		2
Capitalized interest	12		9
Total other income (expense)	(11)		(96)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(159)		(1)
INCOME TAXES (BENEFITS)	(56)		0
INCOME FROM CONTINUING OPERATIONS	(103)		(1)
Discontinued operations (net of income taxes of $70 and $2, respectively) (Note 13)	116		3
NET INCOME (LOSS)	13		2
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	13		2
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(5)		(6)
Amortized loss (gain) on derivative hedges	(2)		(1)
Change in unrealized gain on available-for-sale securities	19		5
Other comprehensive income (loss)	12		(2)
Income taxes (benefits) on other comprehensive income (loss)	4		(1)
Net other comprehensive income (loss)	8		(1)
COMPREHENSIVE INCOME (LOSS)	21		1
FES | Affiliates
REVENUES:
Electric sales	349		156
OPERATING EXPENSES:
Purchased power	64		132
OTHER INCOME (EXPENSE):
Interest expense	(2)		(1)
FES | Non-Affiliates
REVENUES:
Electric sales	1,440		1,334
OPERATING EXPENSES:
Purchased power	1,029		506
OTHER INCOME (EXPENSE):
Interest expense	$ (36)		$ (52)

[1] Includes excise tax collections of $117 million and $122 million in the three months ended March 31, 2014 and 2013, respectively.

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2014

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
	March 31, 2014		December 31, 2013			March 31, 2014			December 31, 2013
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	240	$	162	Commodity Contracts	$	(154	)	$	(102	)
FTRs	7		4		FTRs	(5		)	(9		)
	247		166			(159		)	(111		)
					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs	(188		)	(222		)
Deferred Charges and Other Assets - Other					Noncurrent Liabilities - Other
Commodity Contracts	64		53		Commodity Contracts	(33		)	(11		)
NUGs	3		20		FTRs	(3		)	(3		)
	67		73			(224		)	(236		)
Derivative Assets	$	314	$	239	Derivative Liabilities	$	(383	)	$	(347	)

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
March 31, 2014	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	304		$	(182	)	$	(4	)	$	118
FTRs	7			(7		)	—			—
NUG contracts	3			—			—			3
	$	314		$	(189	)	$	(4	)	$	121
Derivative Liabilities
Commodity contracts	$	(187	)	$	182		$	2		$	(3	)
FTRs	(8		)	7			1			—
NUG contracts	(188		)	—			—			(188		)
	$	(383	)	$	189		$	3		$	(191	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2013	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	215		$	(106	)	$	(9	)	$	100
FTRs	4			(4		)	—			—
NUG contracts	20			—			—			20
	$	239		$	(110	)	$	(9	)	$	120
Derivative Liabilities
Commodity contracts	$	(113	)	$	106		$	7		$	—
FTRs	(12		)	4			5			(3		)
NUG contracts	(222		)	—			—			(222		)
	$	(347	)	$	110		$	12		$	(225	)

Volume of First Energy's outstanding derivative transactions

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2014:

	Purchases	Sales	Net	Units
	(In millions)
Power Contracts	41	38	3	MWH
FTRs	26	—	26	MWH
NUGs	7	—	7	MWH
Natural Gas	65	8	57	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 ended March 31, 2014 and 2013, are summarized in the following tables:

	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2014
Unrealized Gain Recognized in:
Other Operating Expense (1)		$12			$5			$17
Realized Gain (Loss) Reclassified to:
Revenues (2)		($13	)		$52			$39
Purchased Power Expense (3)	436			—			436
Other Operating Expense (4)	—			(7		)	(7		)
Fuel Expense	9			—			9
(1) Includes $12 million for commodity contracts and $5 million for FTRs associated with FES.
(2) Represents losses on structured financial contracts. Includes ($13) million for commodity contracts and $51 million for FTRs associated with FES.
(3) Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power. Includes $436 million for commodity contracts associated with FES.
(4) Includes ($7) million for FTRs associated with FES.
2013
Unrealized Loss Recognized in:
Other Operating Expense (5)		($5	)		($2	)		($7	)
Realized Gain (Loss) Reclassified to:
Revenues (6)		$10			$7			$17
Purchased Power Expense (7)	(11		)	—			(11		)
Other Operating Expense (8)	—			(9		)	(9		)
Fuel Expense	(1		)	—			(1		)
(5) Includes ($5) million for commodity contracts and ($1) million for FTRs associated with FES.
(6) Includes $10 million for commodity contracts and $6 million for FTRs associated with FES.
(7) Includes ($11) million for commodity contracts associated with FES.
(8) Includes ($8) million for FTRs associated with FES.

Derivative instruments subject to regulatory accounting

The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three months ended March 31, 2014 and 2013, are summarized in the following tables:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP(1)			Regulated FTRs			Total
	(In millions)
2014
Unrealized Gain on Derivative Instrument	$	27		$	—		$	4		$	31
Realized Loss on Derivative Instrument	(10		)	—			(1		)	(11		)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	18		$	(2	)	$	—		$	16
Realized Gain (Loss) on Derivative Instrument	23			—			(1		)	22

⁽¹⁾  During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

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 ended March 31, 2014 and 2013:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP(1)			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of January 1, 2014	$	(202	)	$	—		$	—		$	(202	)
Additions/Change in value of existing contracts	27			—			4			31
Settled contracts	(10		)	—			(1		)	(11		)
Outstanding net liability as of March 31, 2014	$	(185	)	$	—		$	3		$	(182	)
Outstanding net liability as of January 1, 2013	$	(254	)	$	(144	)	$	—		$	(398	)
Additions/Change in value of existing contracts	18			(2		)	—			16
Settled contracts	23			—			(1		)	22
Outstanding net liability as of March 31, 2013	$	(213	)	$	(146	)	$	(1	)	$	(360	)

⁽¹⁾  During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Income Taxes (Textuals) [Abstract]
Unrecognized tax benefits	$ 35
Accrued interest	$ 9		$ 9
Effective tax rate	28.20%	37.20%
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate	35.20%	24.80%

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Derivative Instruments (Details 2)	Mar. 31, 2014 MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	41,000,000
Sales (in MWH or mmBTUs)	38,000,000
Net (in MWH or mmBTUs)	3,000,000
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	26,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	26,000,000
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	7,000,000
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	7,000,000
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	65,000,000
Sales (in MWH or mmBTUs)	8,000,000
Net (in MWH or mmBTUs)	57,000,000

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Consolidated Statements of Income (FirstEnergy Corp.) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
REVENUES:
Electric utilities	$ 2,739		$ 2,388
Unregulated businesses	1,450		1,335
Total revenues	4,189	[1]	3,723	[1]
OPERATING EXPENSES:
Fuel	617		630
Purchased power	1,455		946
Other operating expenses	1,182		882
Provision for depreciation	294		293
Amortization (deferral) of regulatory assets, net	(28)		59
General taxes	271		265
Total operating expenses	3,791		3,075
OPERATING INCOME (LOSS)	398		648
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(7)		(117)
Investment income	22		18
Interest expense	(265)		(258)
Capitalized interest	22		15
Total other income (expense)	(228)		(342)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	170		306
INCOME TAXES	48		114
INCOME FROM CONTINUING OPERATIONS	122		192
Discontinued operations (net of income taxes of $69 and $2, respectively) (Note 13)	86		4
NET INCOME (LOSS)	$ 208		$ 196
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations, in dollars per share	$ 0.29		$ 0.46
Basic - Discontinued Operations (Note 13), in dollars per share	$ 0.21		$ 0.01
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.50		$ 0.47
Diluted - Continuing Operations, in dollars per share	$ 0.29		$ 0.46
Diluted - Discontinued Operations (Note 13), in dollars per share	$ 0.20		$ 0.01
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.49		$ 0.47
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares	419		418
Diluted, in shares	420		419
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share	$ 0.72	[2]	$ 0.55	[2]

[1] Includes excise tax collections of $117 million and $122 million in the three months ended March 31, 2014 and 2013, respectively.

[2] The three months ended March 31, 2014 includes a dividend declared of $0.36 per share on January 21, 2014, paid on March 1, 2014 and a dividend declared of $0.36 per share on March 18, 2014, payable June 1, 2014. The three months ended March 31, 2013 includes a dividend declared of $0.55

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Fair Value Measurements (Details 2) (Level 3, USD $) In Millions, unless otherwise specified																						3 Months Ended
	Mar. 31, 2014 FTRs	Dec. 31, 2013 FTRs	Dec. 31, 2012 FTRs	Mar. 31, 2014 FTRs FES	Dec. 31, 2013 FTRs FES	Dec. 31, 2012 FTRs FES	Mar. 31, 2014 Non Utility Generation Contract		Dec. 31, 2013 Non Utility Generation Contract		Dec. 31, 2012 Non Utility Generation Contract		Mar. 31, 2014 LCAPP Contracts		Dec. 31, 2013 LCAPP Contracts		Dec. 31, 2012 LCAPP Contracts		Mar. 31, 2014 Model FTRs	Mar. 31, 2014 Model FTRs FES	Mar. 31, 2014 Model Non Utility Generation Contract	Mar. 31, 2014 Model Minimum FTRs	Mar. 31, 2014 Model Minimum FTRs FES	Mar. 31, 2014 Model Minimum Non Utility Generation Contract MWh	Mar. 31, 2014 Model Maximum FTRs	Mar. 31, 2014 Model Maximum FTRs FES	Mar. 31, 2014 Model Maximum Non Utility Generation Contract MWh	Mar. 31, 2014 Model Weighted Average FTRs	Mar. 31, 2014 Model Weighted Average FTRs FES	Mar. 31, 2014 Model Weighted Average Non Utility Generation Contract MWh
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value	$ (1)	$ (8)	$ (1)	$ (4)	$ (8)	$ 0	$ (185)	[1]	$ (202)	[1]	$ (254)	[1]	$ 0	[1]	$ 0	[1]	$ (144)	[1]	$ (1)	$ (4)	$ (185)
Fair Value Inputs, RTO Auction Clearing Prices																						(4.20)	(4.20)		7.60	7.60		0.80	0.60
Fair Value Inputs, Power																								600			5,422,000			1,033,000
Fair Value Inputs, Power, Regional Prices																								47.90			59.00			53.50

[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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Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
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	419,837,287	418,628,559
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 55	$ 52
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

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Commitments, Guarantees and Contingencies (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 941
Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	516
BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	552
FES
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	796
FES | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	461
FES | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	497
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	87
Utilities | Split Rating (One rating agency's rating below investment grade)
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	49
Utilities | BB Plus/BA1 Credit Ratings
Guarantor Obligations [Line Items]
Maximum exposure under collateral provisions	$ 49

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

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)
March 31, 2014
External revenues	$	2,552	$	187	$	1,522		$	(35	)	$	(37	)	$	4,189
Internal revenues	—		—		249			—			(249		)	—
Total revenues	2,552		187		1,771			(35		)	(286		)	4,189
Depreciation, amortization and deferrals	131		33		91			11			—			266
Investment income	15		—		14			3			(10		)	22
Interest expense	151		25		46			43			—			265
Income taxes (benefits)	125		30		(73		)	(26		)	(8		)	48
Income (loss) from continuing operations	214		51		(124		)	(32		)	13			122
Discontinued operations, net of tax	—		—		86			—			—			86
Net income (loss)	214		51		(38		)	(32		)	13			208
Total assets	27,742		5,584		17,445			457			—			51,228
Total goodwill	5,092		526		800			—			—			6,418
Property additions	269		217		318			17			—			821
March 31, 2013
External revenues	$	2,212	$	176	$	1,414		$	(27	)	$	(52	)	$	3,723
Internal revenues	—		—		216			—			(216		)	—
Total revenues	2,212		176		1,630			(27		)	(268		)	3,723
Depreciation, amortization and deferrals	202		29		110			11			—			352
Investment income	18		—		10			1			(11		)	18
Interest expense	135		23		73			27			—			258
Income taxes (benefits)	126		31		(24		)	(19		)	—			114
Income (loss) from continuing operations	210		51		(42		)	(30		)	3			192
Discontinued operations, net of tax	—		—		4			—			—			4
Net income (loss)	210		51		(38		)	(30		)	3			196
Total assets	26,943		4,722		18,328			431			—			50,424
Total goodwill	5,025		526		896			—			—			6,447
Property additions	436		89		283			18			—			826

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Segment Information (Details Textuals)	3 Months Ended
	Mar. 31, 2014 Segments
Segment Reporting Information [Line Items]
Number of reportable operating segments	3
Regulated Distribution
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	3,780
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	14,000
Competitive Energy Services | Unregulated Plants Expected to be Closed by 9/1/2012
Segment Reporting Information [Line Items]
Megawatt capacity of plants expected to be closed	885

XML

Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2014

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 March 31, 2014, outstanding guarantees and other assurances aggregated approximately $4.0 billion, consisting of parental guarantees ($896 million), subsidiaries' guarantees ($2,207 million) and other guarantees ($891 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.This posted collateral is used to settle gains or losses on those bilateral agreements or derivatives.

Based on FES' power portfolio exposure as ofMarch 31, 2014, FES has posted collateral of$544 million and AE Supply has posted collateral of $8 million. The Regulated Distribution segment has posted collateral of$28 million.The collateral posted at FES primarily relates to the extreme weather and market conditions experienced in January of 2014. On April 16, 2014, approximately $275 million of cash collateral was returned to FES as a result of the PJM semi-annual peak market activity calculation reset.

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 ofMarch 31, 2014:

Collateral Provisions	FES		AE Supply		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	461	$	6	$	49	$	516
BB+/Ba1 Credit Ratings	$	497	$	6	$	49	$	552
Full impact of credit contingent contractual obligations	$	796	$	58	$	87	$	941

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 ofMarch 31, 2014, 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$111 millionand$1 million, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a syndicated three-year senior secured term loan facility dated October 18, 2011, as amended, that matures 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 FE, 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 guarantees of the obligations of Global Holding under the new facility.

In connection with the 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 as collateral.

FE, FEV and the other two co-owners of Global Holding, Pinesdale LLC, a Gunvor Group, Ltd. subsidiary, and WMB Marketing Ventures, LLC, have agreed, most recently as of August 14, 2013, to use their best efforts to refinance the facility no later than July 20, 2015, on a non-recourse basis so that FE's guaranty can be terminated and/or released.If that refinancing does not occur, FE may require each co-owner to lend to Global Holding, on a pro rata basis, funds sufficient to prepay the facility in full.In lieu of providing such funding, the co-owners, at FE's option, may provide their several guaranties of Global Holding's obligations under the facility.Since January 1, 2013, FE has received a fee for providing its guaranty.The fee is payable semiannually, and accrues at a rate of5%per annum on the average daily outstanding aggregate commitments under the facility for each 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 Keystone, Portland and Shawville coal-fired plants based on “modifications” dating back to the mid-1980s.JCP&L, as the former owner of 16.67% of the Keystone Station, ME, as a former owner and operator of the Portland Station, and PN as former owner and operator of the Shawville Station, are unable to predict the outcome of this matter or estimate the possible loss or 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.FirstEnergy 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, MP, PE and WP in the U.S. District Court for the Western District of Pennsylvania alleging, among other things, that AE performed major modifications in violation of the NSR 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.On February 6, 2014, the Court entered judgment for AE, AE Supply, MP, PE and WP finding they had not violated the CAA or the Pennsylvania Air Pollution Control Act.On March 10, 2014, New York, Connecticut, and Maryland filed an appeal with the U.S. Court of Appeals for the Third Circuit.This decision does not change the status of these plants which remain deactivated.

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 D.C. Circuit 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 D.C. Circuit and was ultimately vacated by the Court on August 21, 2012.The Court has ordered the EPA to continue administration of CAIR until it finalizes a valid replacement for CAIR.On April 29, 2014 the U.S. Supreme Court reversed the D.C Circuit decision vacating CSAPR and generally upheld the EPA's authority under the CAA to establish the regulatory structure underpinning CSAPR.Depending on the outcome of further proceedings in this matter and how the EPA and the states implement the final rules, 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 Bruce 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 was challenged in the U.S. Court of Appeals for the D.C. Circuit by various entities, including FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers, such as Bay Shore Unit 1.On April 15, 2014, MATS was upheld by the U.S. Court of Appeals for the D.C. Circuit, however, the Court refused to decide FirstEnergy's challenge of the PM emission limit imposed on petroleum coke boilers due to a January 2013 petition for reconsideration still pending but not addressed by EPA.Depending on the outcome of further appeals, if any, and how the MATS are ultimately implemented, FirstEnergy's total cost of compliance with MATS is currently estimated to be approximately$465 million(Competitive Energy Services segment of$240 millionand Regulated Distribution segment of$225 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.In February 2014, PJM notified FG that Eastlake Units 1-3 and Lake Shore Unit 18 will be released from RMR status as of September 15, 2014.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.FE and FES have asserted force majeure defenses for delivery shortfalls under certain agreements, and are in discussion with the applicable counterparties.As to two agreements, FE and FES have settled monetary claims for damages for the failure to take minimum quantities for the calendar year 2012 by the payment of approximately$70 million, and agreed to pay liquidated damages for delivery shortfalls for 2013 and 2014.FE and FES recorded $67 million in liquidated damages in the fourth quarter of 2013, associated with estimated 2013 delivery shortfalls, which were paid in the first quarter of 2014. Additionally, in January 2014, FE and FES reached an agreement in principle with Mepco Holdings LLC to terminate a contract for future coal deliveries to Hatfield for $18 million, which was approved by the United States Bankruptcy Court on February 26, 2014.If FE and FES fail to reach a resolution with applicable counterparties for coal transportation agreements associated with the deactivated plants or unresolved aspects of the transportation agreements and it were ultimately determined that, contrary to their 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.If that were to occur, FE and FES are unable to estimate the loss or range of loss.

Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level.Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies to reduce GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.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 goals to: (1) cut carbon pollution in America 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. GHG emissions have already been reduced by 10% between 2005 and 2012 according to an April, 2014 EPA Report. Due to plant deactivations and increased efficiencies, FirstEnergy anticipates its CO2 emissions will be reduced 25% below 2005 levels by 2016, exceeding the President’s Climate Action Plan goals both in terms of timing and reduction levels.

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 the 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.The memorandum further directed the EPA to propose by June 1, 2014 and complete by June 1, 2015, GHG emission standards for existing fossil fuel generating units.On September 20, 2013, the EPA proposed a new source performance standard, which would not apply to any existing, modified, or reconstructed fossil fuel generating units, 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 the 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?" Oral argument was held on February 24, 2014. 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.

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.In 1997, the U.S. Senate passed the Byrd-Hagel resolution by a unanimous vote of 95-0. The resolution stated that it is the sense of the Senate that the United States should not be a signatory to any protocol to, or other agreement regarding, the United Nations Framework Convention on Climate Change which would mandate new commitments to limit or reduce GHG emissions, unless the protocol or other agreement also mandates new specific scheduled commitments to limit or reduce GHG emissions for developing country parties within the same compliance period, or would not result in serious harm to the economy of the United States. 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.In November 2013, the U.N. Climate Change Conference in Warsaw, Poland advanced negotiations of a new global agreement to reduce GHG emissions by 2015. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂emissions, or litigation alleging damages from GHG emissions, could require significant capital and other expenditures or result in changes to its operations.The CO₂emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂emitting gas-fired and nuclear generators.

Clean Water Act

Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants.In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations.

In 2004, the EPA established new performance standards under Section 316(b) of the CWA for reducing impacts on fish and shellfish from cooling water intake structures at certain existing electric generating plants.The regulations call for reductions in impingement mortality (when aquatic organisms are pinned against screens or other parts of a cooling water intake system) and entrainment (which occurs when aquatic life is drawn into a facility's cooling water system).In 2007, the U.S. Court of Appeals for the Second Circuit invalidated portions of the Section 316(b) performance standards and the EPA has taken the position that until further rulemaking occurs, permitting authorities should continue the existing practice of applying their best professional judgment to minimize impacts on fish and shellfish from cooling water intake structures.In April 2009, the U.S. Supreme Court reversed one significant aspect of the Second Circuit's opinion and decided that Section 316(b) of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing adverse environmental impact at cooling water intake structures.On March 28, 2011, the EPA released a new proposed regulation under Section 316(b) of the CWA to reduce fish impingement to a12%annual average and determine site-specific controls, if any, to reduce entrainment of aquatic life following studies to be provided to permitting authorities.On April 16, 2014, counsel for EPA informed the United States District Court in which a settlement agreement with certain NGOs set April 17, 2014 as a deadline for finalizing the Section 316(b) regulation that an additional 29 days would be needed to finalize the Section 316(b) regulation by May 16, 2014.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 September 30, 2015, 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 ranging from$150 millionto$300 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.Based on the stringency of the TMDL, MP may incur significant costs to reduce sulfate discharges into the Monongahela River if the NPDES permit for the coal-fired Fort Martin plant in West Virginia is required to be modified or renewed to include more stringent effluent limitations for sulfate.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 CCRs produced by electric utilities pose significant financial risk to the industry.In May 2010, the EPA proposedtwooptions for additional regulation of CCRs, 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 CCRs.On April 19, 2013, the EPA stated it would "align" its proposed CCR 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.On January 29, 2014, EPA agreed to take final action by December 19, 2014 on whether or not to pursue the proposed non-hazardous waste option for regulating CCRs in a Consent Decree to be filed in pending litigation.Depending on the content of the EPA's final effluent limitations rule, the specifics of any "alignment", whether EPA chooses to pursue the non-hazardous or hazardous waste option and the potential enactment of legislation, 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 required 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.FG responded to the PA DEP on December 3, 2013, and as a result of the Closure Plan, FG increased its ARO for LBR by $163 million in 2013.On April 3, 2014, PA DEP issued a permit requiring FE to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizes FE to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCBs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met.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.In addition, 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 and December 5, 2013, complaints were filed on behalf of approximately50individuals against FE, FG and FES in the U.S. District Court for the Northern District of West Virginia and approximately 15 individuals against FG in the U.S. District Court for the Western District of Pennsylvania seeking damages for alleged property damage, bodily injury and emotional distress related to the LBR CCB Impoundment.The complaints state 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 the complaints, 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 CCR 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 ofMarch 31, 2014based 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$129 millionhave been accrued throughMarch 31, 2014. 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 ofMarch 31, 2014, FirstEnergy had approximately$2.3 billioninvested in external trusts to be used for the decommissioning and environmental remediation of Davis-Besse, Beaver Valley, Perry and TMI-2.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.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guaranty, as appropriate.By a letter dated March 28, 2013, FENOC informed the NRC that the nuclear decommissioning parental guarantee would be increased to $155 millionduring the second quarter of 2014.Moreover, a new parental guarantee for the Beaver Valley spent fuel storage facility of $9.5 millionwould also be put in place.

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.A 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.Other contentions proposed by the petitioners in this proceeding have been rejected by the ASLB. On February 18, 2014, Beyond Nuclear and Don't Waste Michigan, two of the petitioners in the Davis-Besse license renewal proceeding, requested that the NRC institute a rulemaking on the environmental impacts of high density spent fuel storage and mitigation alternatives. On February 27, 2014, these petitioners requested a suspension of the licensing decision in the Davis-Besse license renewal proceeding to allow the NRC to complete this rulemaking.On March 21, 2014, both FENOC and the NRC opposed the request for a suspension. On April 21, 2014, the Intervenors proposed an additional contention in the license renewal proceeding related to the shield building.

As part of routine inspections of the concrete shield building at Davis-Besse Nuclear Power Station in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011. The shield building is a 2 1/2-foot thick reinforced concrete structure that provides biological shielding, protection from natural phenomena including wind and tornadoes and additional shielding in the event of an accident. FENOC then expanded its sample size to include all of the existing core bores in the shield building. These inspections, which are now complete, identified additional subsurface cracking that was determined to be pre-existing, but only now identified with the aid of improved inspection technology. These inspections also revealed that the cracking condition has propagated a small amount in select areas. Preliminary analysis of the inspections results confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.

On February 1, 2014 the Davis-Besse Nuclear Power station entered an outage to install two new steam generators, replace about a third of the unit’s 177 fuel assemblies and perform numerous safety inspections and preventative maintenance activities. These activities, including amounts spent in prior years in preparation for this outage, represent an investment of approximately $600 million by FES at Davis Besse.During the preliminary stages of the outage an area of concrete that was not filled to the expected thickness within the shield building wall was discovered at the top of the temporary construction opening that was created as part of the 2011 outage.The 2011 temporary construction opening was created to install the new reactor head. FENOC has assessed the as-found condition of the concrete and has determined the shield building would have performed its design functions.This condition within the shield building wall was repaired to conform to its original design configuration.

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.A damages hearing is scheduled for May 13-14, 2014, and a ruling is expected in the fourth quarter of 2014.

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.The PPUC entered an Opinion and Order on January 9, 2014 approving the Settlement with limited modifications regarding the frequency of refresher training and reporting obligations.WP filed a letter on January 17, 2014 accepting those modifications and noting its intent to begin implementation of the settlement terms.

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 loss or range of loss in these matters is not expected to be material to FirstEnergy or its subsidiaries.The other potentially material items not otherwise discussed above are described under Note 9, 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.

XML

Earnings Per Share of Common Stock (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Earnings Per Share [Abstract]
Income from continuing operations	$ 122		$ 192
Discontinued operations (Note 13)	86		4
EARNINGS AVAILABLE TO FIRSTENERGY CORP.	$ 208		$ 196
Weighted average number of basic shares outstanding	419		418
Assumed exercise of dilutive stock options and awards	1	[1]	1	[1]
Weighted average number of diluted shares outstanding	420		419
Basic earnings per share:
Income from continuing operations, in dollars per share	$ 0.29		$ 0.46
Discontinued operations (Note 13), in dollars per share	$ 0.21		$ 0.01
Basic - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.50		$ 0.47
Diluted earnings per share:
Income from continuing operations, in dollars per share	$ 0.29		$ 0.46
Discontinued operations (Note 13), in dollars per share	$ 0.20		$ 0.01
Diluted - Earnings Available to FirstEnergy Corp., in dollars per share	$ 0.49		$ 0.47
Shares excluded from the calculation of diluted shares outstanding, in shares	2		0

[1] For the three months ended March 31, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the three months ended March 31, 2013.

XML

Segment Information

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

FirstEnergy continues to have three reportable operating segments - Regulated Distribution, Regulated Transmission and Competitive Energy Services. The external reporting is consistent with the internal financial reporting used by FirstEnergy’s Chief Executive Officer (its chief operating decision maker) to regularly assess the performance of the business and allocate resources.

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 3,780 MWs of generation capacity.

The Regulated Transmission segment transmits electricity through transmission facilities owned and operated by ATSI, TrAIL, and certain of FirstEnergy's utilities (JCP&L, ME, PN, MP, PE and WP) and the regulatory asset associated with the abandoned PATH project. 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 approximately14,000MWs of capacity, including885MWs of capacity subject to RMR arrangements with PJM.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 fuel, 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)
March 31, 2014
External revenues	$	2,552	$	187	$	1,522		$	(35	)	$	(37	)	$	4,189
Internal revenues	—		—		249			—			(249		)	—
Total revenues	2,552		187		1,771			(35		)	(286		)	4,189
Depreciation, amortization and deferrals	131		33		91			11			—			266
Investment income	15		—		14			3			(10		)	22
Interest expense	151		25		46			43			—			265
Income taxes (benefits)	125		30		(73		)	(26		)	(8		)	48
Income (loss) from continuing operations	214		51		(124		)	(32		)	13			122
Discontinued operations, net of tax	—		—		86			—			—			86
Net income (loss)	214		51		(38		)	(32		)	13			208
Total assets	27,742		5,584		17,445			457			—			51,228
Total goodwill	5,092		526		800			—			—			6,418
Property additions	269		217		318			17			—			821
March 31, 2013
External revenues	$	2,212	$	176	$	1,414		$	(27	)	$	(52	)	$	3,723
Internal revenues	—		—		216			—			(216		)	—
Total revenues	2,212		176		1,630			(27		)	(268		)	3,723
Depreciation, amortization and deferrals	202		29		110			11			—			352
Investment income	18		—		10			1			(11		)	18
Interest expense	135		23		73			27			—			258
Income taxes (benefits)	126		31		(24		)	(19		)	—			114
Income (loss) from continuing operations	210		51		(42		)	(30		)	3			192
Discontinued operations, net of tax	—		—		4			—			—			4
Net income (loss)	210		51		(38		)	(30		)	3			196
Total assets	26,943		4,722		18,328			431			—			50,424
Total goodwill	5,025		526		896			—			—			6,447
Property additions	436		89		283			18			—			826

XML

Consolidated Statements of Cash Flows (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 208	$ 196
Adjustments to reconcile net income to net cash from operating activities-
Provision for depreciation	294	293
Amortization of regulatory assets, net	(28)	59
Nuclear fuel amortization	48	53
Deferred purchased power and other costs	(34)	(25)
Deferred income taxes and investment tax credits, net	181	134
Deferred rents and lease market valuation liability	33	37
Retirement benefits	(20)	(64)
Commodity derivative transactions, net (Note 8)	(17)	4
Loss on debt redemptions	7	117
Income from discontinued operations (Note 13)	(86)	(4)
Changes in current assets and liabilities-
Receivables	(168)	(34)
Materials and supplies	12	26
Prepayments and other current assets	(29)	(159)
Accounts payable	200	(378)
Accrued taxes	(242)	(128)
Accrued interest	46	53
Accrued compensation and benefits	(118)	(91)
Cash collateral, net	(461)	(1)
Other	82	(38)
Net cash (used for) provided from operating activities	(92)	50
New Financing-
Long-term debt	1,467	1,800
Short-term borrowings, net	0	181
Redemptions and Repayments-
Long-term debt	(489)	(846)
Short-term borrowings, net	(319)	0
Tender premiums paid on debt redemptions	0	(110)
Common stock dividend payments	(151)	(230)
Other	(10)	(23)
Net cash provided from (used for) financing activities	498	772
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(821)	(826)
Nuclear fuel	(55)	(27)
Proceeds from asset sales	394	0
Sales of investment securities held in trusts	621	539
Purchases of investment securities held in trusts	(646)	(565)
Cash investments	28	6
Asset removal costs	(39)	(53)
Other	3	(1)
Net cash used for investing activities	(515)	(927)
Net change in cash and cash equivalents	(109)	(105)
Cash and cash equivalents at beginning of period	218	172
Cash and cash equivalents at end of period	$ 109	$ 67

XML

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 18, 2014	Jan. 21, 2014	Mar. 19, 2013
Income Statement [Abstract]
Tax effect of discontinued operations	$ 69	$ 2
Excise taxes collected	$ 117	$ 122
Dividends declared amount paid per declaration (in dollars per share)			$ 0.36	$ 0.36	$ 0.55

XML

Income Taxes

3 Months Ended

Mar. 31, 2014

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

FirstEnergy’s and FES’s interim effective tax rates reflect the estimated annual effective tax rates for 2014 and 2013, adjusted for tax expense associated with certain discrete items.

FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. Significant judgment is required in determining FirstEnergy's income taxes and in evaluating tax positions taken or expected to be taken on its tax returns. There were no material changes to FirstEnergy's unrecognized income tax benefits during the first three months of 2014 or 2013.

As of March 31, 2014, it is reasonably possible that approximately $35 million of unrecognized income tax benefits, including interest, may be resolved within the next twelve months as a result of the statute of limitations expiring, all of which 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 three months of 2014 and 2013, there were no material changes to the amount of accrued interest. The net amount of interest accrued as of March 31, 2014 and December 31, 2013 was approximately $9 million.

FirstEnergy’s effective tax rate from continuing operations for the three months ended March 31, 2014 and 2013 was 28.2% and 37.2%, respectively. The decrease in the effective tax rate is primarily due to an increase in AFUDC equity flow through, changes in state apportionment factors and the elimination of certain future tax liabilities associated with basis differences.

FES’s effective tax rate from continuing operations for the three months ended March 31, 2014 and 2013 was 35.2% and 24.8%, respectively. The increase in the effective tax rate is primarily related to the impact of permanent tax adjustments on estimated annual pretax earnings from continuing operations.

In April 2014, the Internal Revenue Service completed its examination of FE's 2011 and 2012 federal income tax returns and issued Revenue Agent Reports for these years.

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	0001031296
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		419,908,686
FES
Entity Information [Line Items]
Entity Registrant Name	FirstEnergy Solutions Corp.
Entity Central Index Key	0001407703
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding		7

XML

Variable Interest Entities

3 Months Ended

Mar. 31, 2014

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 trusts that were 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.

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.

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.

Ohio Securitization

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.

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 FirstEnergy 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 9, 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 at its Regulated Distribution segment 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 20 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 at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contracts that may contain a variable interest were $61 million and $49 million during the three months ended March 31, 2014 and 2013, 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.

In March of 2013, FG acquired the remaining interests in connection with the 1987 Bruce Mansfield Plant sale and leaseback transactions for approximately $221 million. Also during 2013, NG purchased lessor equity interests in OE's existing sale and leaseback of Beaver Valley Unit 2 for $23 million and in February 2014, NG purchased additional lessor equity interests for approximately $94 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 March 31, 2014:

	Maximum Exposure		Discounted Lease Payments, net(1)		Net Exposure
	(In millions)
FES	$	1,293	$	1,081	$	212
Other FE subsidiaries	716		495		221

⁽¹⁾  The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.1 billion.

XML

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 208	$ 196
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(42)	(46)
Amortized losses on derivative hedges	0	1
Change in unrealized gain on available-for-sale securities	21	5
Other comprehensive income (loss)	(21)	(40)
Income tax benefits on other comprehensive loss	(8)	(16)
Net other comprehensive income (loss)	(13)	(24)
COMPREHENSIVE INCOME (LOSS)	$ 195	$ 172

XML

Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 208	$ 196
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation	294	293
Nuclear fuel amortization	48	53
Deferred rents and lease market valuation liability	33	37
Deferred income taxes and investment tax credits, net	181	134
Commodity derivative transactions, net (Note 8)	(17)	4
Loss on debt redemptions	7	117
Income from discontinued operations (Note 13)	(86)	(4)
Changes in current assets and liabilities-
Receivables	(168)	(34)
Materials and supplies	12	26
Prepayments and other current assets	(29)	(159)
Accounts payable	200	(378)
Accrued taxes	(242)	(128)
Accrued compensation and benefits	(118)	(91)
Cash collateral, net	(461)	(1)
Other	82	(38)
Net cash (used for) provided from operating activities	(92)	50
New financing-
Long-term debt	1,467	1,800
Short-term borrowings, net	0	181
Redemptions and Repayments-
Long-term debt	(489)	(846)
Tender premiums paid on debt redemptions	0	(110)
Other	(10)	(23)
Net cash provided from (used for) financing activities	498	772
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(821)	(826)
Nuclear fuel	(55)	(27)
Proceeds from asset sales	394	0
Sales of investment securities held in trusts	621	539
Purchases of investment securities held in trusts	(646)	(565)
Other	3	(1)
Net cash used for investing activities	(515)	(927)
Net change in cash and cash equivalents	(109)	(105)
Cash and cash equivalents at beginning of period	218	172
Cash and cash equivalents at end of period	109	67
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	13	2
Adjustments to reconcile net income (loss) to net cash from operating activities-
Provision for depreciation	74	75
Nuclear fuel amortization	48	53
Deferred rents and lease market valuation liability	21	21
Deferred income taxes and investment tax credits, net	48	56
Commodity derivative transactions, net (Note 8)	(17)	3
Loss on debt redemptions	5	71
Income from discontinued operations (Note 13)	(116)	(3)
Changes in current assets and liabilities-
Receivables	553	(177)
Materials and supplies	21	28
Prepayments and other current assets	(48)	(55)
Accounts payable	(430)	(185)
Accrued taxes	(49)	(80)
Accrued compensation and benefits	(19)	(16)
Cash collateral, net	(420)	38
Other	4	(26)
Net cash (used for) provided from operating activities	(312)	(195)
New financing-
Long-term debt	417	0
Short-term borrowings, net	120	702
Equity contribution from parent	500	0
Redemptions and Repayments-
Long-term debt	(445)	(476)
Tender premiums paid on debt redemptions	0	(67)
Other	(4)	(1)
Net cash provided from (used for) financing activities	588	158
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(298)	(217)
Nuclear fuel	(55)	(27)
Proceeds from asset sales	307	17
Sales of investment securities held in trusts	423	252
Purchases of investment securities held in trusts	(438)	(265)
Loans to affiliated companies, net	(215)	276
Other	0	1
Net cash used for investing activities	(276)	37
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	3
Cash and cash equivalents at end of period	$ 2	$ 3

XML

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	419,837,287	418,628,559
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 55	$ 52
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	3	3
FES
Common stockholders' equity-
Common stock, no par value
Common stock, shares authorized	750	750
Common stock, shares outstanding	7	7
FES | Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	13	11
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

XML

Supplemental Guarantor Information

3 Months Ended

Mar. 31, 2014

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 for FES and FirstEnergy and as a financing lease for FG.

The Condensed Consolidating Statements of Income and Comprehensive Income for the three months ended March 31, 2014 and 2013, Condensed Consolidating Balance Sheets as of March 31, 2014 and December 31, 2013, and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2014 and 2013, 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 March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,797		$	315		$	362		$	(645	)	$	1,829
OPERATING EXPENSES:
Fuel	—			272			47			—			319
Purchased power from affiliates	645			—			64			(645		)	64
Purchased power from non-affiliates	1,025			4			—			—			1,029
Other operating expenses	228			62			150			12			452
Provision for depreciation	2			29			43			—			74
General taxes	21			11			7			—			39
Total operating expenses	1,921			378			311			(633		)	1,977
OPERATING INCOME (LOSS)	(124		)	(63		)	51			(12		)	(148		)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(3		)	(1		)	(1		)	—			(5		)
Investment income	1			1			21			(3		)	20
Miscellaneous income, including net income from equity investees	103			—			—			(103		)	—
Interest expense — affiliates	(3		)	(1		)	(1		)	3			(2		)
Interest expense — other	(14		)	(24		)	(13		)	15			(36		)
Capitalized interest	—			1			11			—			12
Total other income (expense)	84			(24		)	17			(88		)	(11		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(40		)	(87		)	68			(100		)	(159		)
INCOME TAXES (BENEFITS)	(52		)	(31		)	26			1			(56		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	12			(56		)	42			(101		)	(103		)
Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
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	19			—			19			(19		)	19
Other comprehensive income (loss)	12			(4		)	19			(15		)	12
Income taxes (benefits) on other comprehensive income (loss)	4			(2		)	7			(5		)	4
Other comprehensive income (loss), net of tax	8			(2		)	12			(10		)	8
COMPREHENSIVE INCOME	$	20		$	58		$	54		$	(111	)	$	21

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,496		$	531		$	440		$	(943	)	$	1,524
OPERATING EXPENSES:
Fuel	—			247			53			—			300
Purchased power from affiliates	1,013			—			62			(943		)	132
Purchased power from non-affiliates	505			1			—			—			506
Other operating expenses	162			74			131			12			379
Provision for depreciation	1			31			44			(1		)	75
General taxes	20			11			6			—			37
Total operating expenses	1,701			364			296			(932		)	1,429
OPERATING INCOME (LOSS)	(205		)	167			144			(11		)	95
OTHER INCOME (EXPENSE):
Loss on debt redemption	(71		)	—			—			—			(71		)
Investment income	1			—			18			(2		)	17
Miscellaneous income, including net income from equity investees	192			1			—			(191		)	2
Interest expense — affiliates	(2		)	(1		)	(1		)	3			(1		)
Interest expense — other	(25		)	(28		)	(15		)	16			(52		)
Capitalized interest	—			—			9			—			9
Total other income (expense)	95			(28		)	11			(174		)	(96		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(110		)	139			155			(185		)	(1		)
INCOME TAXES (BENEFITS)	(112		)	51			58			3			—
INCOME (LOSS) FROM CONTINUING OPERATIONS	2			88			97			(188		)	(1		)
Discontinued operations (net of income taxes of $2) (Note 13)	—			3			—			—			3
NET INCOME	$	2		$	91		$	97		$	(188	)	$	2
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	2		$	91		$	97		$	(188	)	$	2
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(6		)	(5		)	—			5			(6		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available for sale securities	5			—			5			(5		)	5
Other comprehensive income (loss)	(2		)	(5		)	5			—			(2		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(2		)	2			—			(1		)
Other comprehensive income (loss), net of tax	(1		)	(3		)	3			—			(1		)
COMPREHENSIVE INCOME	$	1		$	88		$	100		$	(188	)	$	1

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of March 31, 2014	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	583		—		—		—			583
Affiliated companies	278		185		180		(274		)	369
Other	60		18		73		—			151
Notes receivable from affiliated companies	457		449		230		(921		)	215
Materials and supplies	63		148		216		—			427
Derivatives	244		—		—		—			244
Collateral	544		—		—		—			544
Prepayments and other	100		79		—		—			179
	2,329		881		699		(1,195		)	2,714
PROPERTY, PLANT AND EQUIPMENT:
In service	106		6,148		6,925		(383		)	12,796
Less — Accumulated provision for depreciation	30		1,978		3,038		(189		)	4,857
	76		4,170		3,887		(194		)	7,939
Construction work in progress	26		130		1,200		—			1,356
	102		4,300		5,087		(194		)	9,295
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,323		—			1,323
Investment in affiliated companies	5,891		—		—		(5,891		)	—
Other	—		11		—		—			11
	5,891		11		1,323		(5,891		)	1,334
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		105		—		(105		)	—
Customer intangibles	91		—		—		—			91
Goodwill	23		—		—		—			23
Property taxes	—		11		19		—			30
Unamortized sale and leaseback costs	—		—		—		197			197
Derivatives	65		—		—		—			65
Other	72		223		9		(154		)	150
	251		339		28		(62		)	556
	$	8,573	$	5,531	$	7,137	$	(7,342	)	$	13,899
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	120	$	366	$	(22	)	$	465
Short-term borrowings-
Affiliated companies	636		283		—		(919		)	—
Other	550		5		—		—			555
Accounts payable-
Affiliated companies	373		19		240		(305		)	327
Other	183		112		—		—			295
Accrued taxes	3		68		38		(12		)	97
Derivatives	159		—		—		—			159
Other	51		62		21		80			214
	1,956		669		665		(1,178		)	2,112
CAPITALIZATION:
Total equity	5,807		2,343		3,548		(5,865		)	5,833
Long-term debt and other long-term obligations	712		2,094		931		(1,186		)	2,551
	6,519		4,437		4,479		(7,051		)	8,384
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		850			850
Accumulated deferred income taxes	11		—		763		36			810
Asset retirement obligations	—		188		841		—			1,029
Retirement benefits	22		167		—		—			189
Derivatives	36		—		—		—			36
Other	29		70		389		1			489
	98		425		1,993		887			3,403
	$	8,573	$	5,531	$	7,137	$	(7,342	)	$	13,899

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2013	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	539		—		—		—			539
Affiliated companies	938		787		227		(916		)	1,036
Other	52		12		17		—			81
Notes receivable from affiliated companies	203		23		683		(909		)	—
Materials and supplies	76		159		213		—			448
Derivatives	165		—		—		—			165
Collateral	136		—		—		—			136
Prepayments and other	52		50		7		—			109
	2,161		1,033		1,147		(1,825		)	2,516
PROPERTY, PLANT AND EQUIPMENT:
In service	104		6,105		6,645		(382		)	12,472
Less — Accumulated provision for depreciation	28		1,953		2,962		(188		)	4,755
	76		4,152		3,683		(194		)	7,717
Construction work in progress	23		148		1,137		—			1,308
	99		4,300		4,820		(194		)	9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,276		—			1,276
Investment in affiliated companies	5,801		—		—		(5,801		)	—
Other	—		11		—		—			11
	5,801		11		1,276		(5,801		)	1,287
ASSETS HELD FOR SALE	—		122		—		—			122
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		131		—		(131		)	—
Customer intangibles	95		—		—		—			95
Goodwill	23		—		—		—			23
Property taxes	—		15		26		—			41
Unamortized sale and leaseback costs	—		—		—		168			168
Derivatives	53		—		—		—			53
Other	81		228		18		(155		)	172
	252		374		44		(118		)	552
	$	8,313	$	5,840	$	7,287	$	(7,938	)	$	13,502
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	367	$	547	$	(23	)	$	892
Short-term borrowings-
Affiliated companies	977		212		151		(909		)	431
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	741		400		362		(738		)	765
Other	94		196		—		—			290
Accrued taxes	204		23		23		(184		)	66
Derivatives	110		—		—		—			110
Other	70		63		18		46			197
	2,197		1,265		1,101		(1,808		)	2,755
CAPITALIZATION:
Total equity	5,312		2,283		3,493		(5,776		)	5,312
Long-term debt and other long-term obligations	712		1,860		742		(1,184		)	2,130
	6,024		4,143		4,235		(6,960		)	7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		858			858
Accumulated deferred income taxes	32		—		736		(27		)	741
Asset retirement obligations	—		187		828		—			1,015
Retirement benefits	22		163		—		—			185
Derivatives	14		—		—		—			14
Other	24		82		387		(1		)	492
	92		432		1,951		830			3,305
	$	8,313	$	5,840	$	7,287	$	(7,938	)	$	13,502

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(450	)	$	87		$	51		$	—		$	(312	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			235			182			—			417
Short-term borrowings, net	209			72			—			(161		)	120
Equity contribution from parent	500			—			—			—			500
Redemptions and Repayments-
Long-term debt	—			(248		)	(197		)	—			(445		)
Short-term borrowings, net	—			—			(151		)	151			—
Other	(1		)	(2		)	(1		)	—			(4		)
Net cash provided from (used for) financing activities	708			57			(167		)	(10		)	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(28		)	(268		)	—			(298		)
Nuclear fuel	—			—			(55		)	—			(55		)
Proceeds from asset sales	—			307			—			—			307
Sales of investment securities held in trusts	—			—			423			—			423
Purchases of investment securities held in trusts	—			—			(438		)	—			(438		)
Loans to affiliated companies, net	(254		)	(425		)	454			10			(215		)
Other	(2		)	2			—			—			—
Net cash provided from (used for) investing activities	(258		)	(144		)	116			10			(276		)
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			2			—			—			2
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(529	)	$	298		$	36		$	—		$	(195	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	894			—			586			(778		)	702
Redemptions and Repayments-
Long-term debt	(369		)	(107		)	—			—			(476		)
Short-term borrowings, net	—			(76		)	—			76			—
Tender premiums	(67		)	—			—			—			(67		)
Other	—			(1		)	—			—			(1		)
Net cash provided from financing activities	458			(184		)	586			(702		)	158
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(138		)	(74		)	—			(217		)
Nuclear fuel	—			—			(27		)	—			(27		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			252			—			252
Purchases of investment securities held in trusts	—			—			(265		)	—			(265		)
Loans to affiliated companies, net	75			7			(508		)	702			276
Other	1			—			—			—			1
Net cash used for investing activities	71			(114		)	(622		)	702			37
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3

XML

Fair Value Measurements

3 Months Ended

Mar. 31, 2014

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 and NUGs are as follows:

FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term RTO auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are 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 8, 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.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of March 31, 2014, from those used as of December 31, 2013. 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 three months ended March 31, 2014. 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	March 31, 2014												December 31, 2013
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,168		$	—		$	1,168		$	—		$	1,365		$	—		$	1,365
Derivative assets - commodity contracts	11			293			—			304			7			208			—			215
Derivative assets - FTRs	—			—			7			7			—			—			4			4
Derivative assets - NUG contracts(1)	—			—			3			3			—			—			20			20
Equity securities(2)	464			—			—			464			317			—			—			317
Foreign government debt securities	—			94			—			94			—			109			—			109
U.S. government debt securities	—			167			—			167			—			165			—			165
U.S. state debt securities	—			237			—			237			—			228			—			228
Other(3)	54			379			—			433			187			255			—			442
Total assets	$	529		$	2,338		$	10		$	2,877		$	511		$	2,330		$	24		$	2,865
Liabilities
Derivative liabilities - commodity contracts	$	(8	)	$	(179	)	$	—		$	(187	)	$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—			—			(8		)	(8		)	—			—			(12		)	(12		)
Derivative liabilities - NUG contracts(1)	—			—			(188		)	(188		)	—			—			(222		)	(222		)
Total liabilities	$	(8	)	$	(179	)	$	(196	)	$	(383	)	$	(13	)	$	(100	)	$	(234	)	$	(347	)
Net assets (liabilities)(4)	$	521		$	2,159		$	(186	)	$	2,494		$	498		$	2,230		$	(210	)	$	2,518

⁽¹⁾  NUG 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 $9 million and $10 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of NUG contracts, LCAPP contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2014 and December 31, 2013:

	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, 2013 Balance	$	36		$	(290	)	$	(254	)	$	—	$	(144	)	$	(144	)	$	8		$	(9	)	$	(1	)
Unrealized gain (loss)	(8		)	(17		)	(25		)	—		(22		)	(22		)	3			1			4
Purchases	—			—			—			—		—			—			6			(15		)	(9		)
Terminations(2)	—			—			—			—		166			166			—			—			—
Settlements	(8		)	85			77			—		—			—			(13		)	11			(2		)
December 31, 2013 Balance	$	20		$	(222	)	$	(202	)	$	—	$	—		$	—		$	4		$	(12	)	$	(8	)
Unrealized gain	—			27			27			—		—			—			6			2			8
Settlements	(17		)	7			(10		)	—		—			—			(3		)	2			(1		)
March 31, 2014 Balance	$	3		$	(188	)	$	(185	)	$	—	$	—		$	—		$	7		$	(8	)	$	(1	)

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

⁽²⁾  See Note 8, Derivative Instruments

Level 3 Quantitative Information

The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(1	)	Model	RTO auction clearing prices	($4.20) to $7.60	$0.80	Dollars/MWH
NUG Contracts	$	(185	)	Model	Generation Electricity regional prices	600 to 5,422,000 $47.90 to $59.00	1,033,000 $53.50	MWH Dollars/MWH

FES
Recurring Fair Value Measurements	March 31, 2014												December 31, 2013
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	586		$	—		$	586		$	—		$	792		$	—		$	792
Derivative assets - commodity contracts	11			294			—			305			7			208			—			215
Derivative assets - FTRs	—			—			4			4			—			—			3			3
Equity securities(1)	327			—			—			327			207			—			—			207
Foreign government debt securities	—			55			—			55			—			65			—			65
U.S. government debt securities	—			25			—			25			—			27			—			27
U.S. state debt securities	—			3			—			3			—			—			—			—
Other(2)	—			319			—			319			—			176			—			176
Total assets	$	338		$	1,282		$	4		$	1,624		$	214		$	1,268		$	3		$	1,485
Liabilities
Derivative liabilities - commodity contracts	$	(8	)	$	(179	)	$	—		$	(187	)	$	(13	)	$	(100	)	$	—		$	(113	)
Derivative liabilities - FTRs	—			—			(8		)	(8		)	—			—			(11		)	(11		)
Total liabilities	$	(8	)	$	(179	)	$	(8	)	$	(195	)	$	(13	)	$	(100	)	$	(11	)	$	(124	)
Net assets (liabilities)(3)	$	330		$	1,103		$	(4	)	$	1,429		$	201		$	1,168		$	(8	)	$	1,361

⁽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 $8 million and $9 million as of March 31, 2014 and December 31, 2013, respectively, of receivables, payables, taxes and accrued income associated with the financial instruments reflected within the fair value table.

Rollforward of Level 3 Measurements

The following table provides a reconciliation of changes in the fair value of FTRs held by FES and classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2014 and December 31, 2013:

	Derivative Asset FTRs			Derivative Liability FTRs			Net FTRs
	(In millions)
January 1, 2013 Balance	$	6		$	(6	)	$	—
Unrealized loss	—			(2		)	(2		)
Purchases	5			(12		)	(7		)
Settlements	(8		)	9			1
December 31, 2013 Balance	$	3		$	(11	)	$	(8	)
Unrealized gain	3			1			4
Settlements	(2		)	2			—
March 31, 2014 Balance	$	4		$	(8	)	$	(4	)

Level 3 Quantitative Information

The following table provides quantitative information for FTRs held by FES that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2014:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(4	)	Model	RTO auction clearing prices	($4.20) to $7.60	$0.60	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, OE and TE 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 March 31, 2014 and December 31, 2013:

	March 31, 2014(1)						December 31, 2013(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,670	$	44	$	1,714	$	1,881	$	33	$	1,914
FES	698		22		720		918		17		935
Equity securities
FirstEnergy	$	433	$	31	$	464	$	308	$	9	$	317
FES	308		19		327		207		—		207

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $324 million; FES - $276 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $204 million; FES - $135 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 ended March 31, 2014 and 2013 were as follows:

Three Months Ended
March 31, 2014	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	621	$	28	$	(16	)	$	(2	)	$	25
FES	423		19		(5		)	(2		)	15
March 31, 2013	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	539	$	24	$	(6	)	$	(7	)	$	26
FES	252		20		(3		)	(7		)	13

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 March 31, 2014 and December 31, 2013:

	March 31, 2014						December 31, 2013
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	24	$	8	$	32	$	33	$	2	$	35

Investments in employee benefit trusts and cost and equity method investments, including FirstEnergy's investment in Global Holding, totaling $635 million as of March 31, 2014, and $636 million as of December 31, 2013, 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:

	March 31, 2014				December 31, 2013
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	18,034	$	19,321	$	17,049	$	17,957
FES	2,996		3,098		3,001		3,073

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 March 31, 2014 and December 31, 2013.

On March 31, 2014, FE, FES, AE Supply, FET and FE's other borrower subsidiaries entered into extensions and amendments to thethreeexisting multi-year syndicated revolving credit facilities.Each facility was extended until March 31, 2019.The FE facility was amended to increase the lending banks' commitments under the facility by $1 billion to a total of $3.5 billionand to increase the individual borrower sublimit for FE by $1 billionto a total of $3.5 billion. The FES/AE Supply facility was amended to decrease the lending banks' commitments by $1 billion to a total of $1.5 billion. The lending banks' commitments under the FET facility remain at $1 billion and that facilitywas amended to increase ATSI's individual borrower sublimit to $500 millionfrom $100 millionand TrAIL's individual borrower sublimit to $400 millionfrom $200 million. FirstEnergy expensed approximately $5 million(FES - $3 million)of unamortized debt expense as a result of the amendments.The amount was included in Loss on Debt Redemptions in the Consolidated Statement of Income in the first quarter of 2014.

On March 31, 2014, FE executed, and fully utilized, a new $1 billionvariable rate term loan credit agreement with a maturity date of March 31, 2019.The initial borrowing under the term loan, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances.

During the first quarter of 2014, FG and NG remarketed approximately $417 millionof PCRBs previously held by the companies.Of the total, $182 million was remarketed with a fixed interest rate of4%per annum with a mandatory put date of June 3, 2019 and $235 millionwas remarketed with a fixed interest rate of3.75%per annum with a mandatory put date of December 3, 2018.

In addition, in the first quarter of 2014, FG and NG repurchased approximately $197million and $16 millionof PCRBs, respectively, which were subject to a mandatory tender. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

On April 1, 2014, PN and ME repurchased approximately $45 million and $29 millionof PCRBs, respectively, which were subject to a mandatory put on such date. The companies are currently holding the PCRB's for remarketing subject to future market and other conditions.

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Pension and Other Postemployment Benefits

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

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

Components of Net Periodic Benefit Costs (Credits)	Pensions						OPEB
For the Three Months Ended March 31,	2014			2013			2014			2013
	(In millions)
Service costs	$	42		$	49		$	2		$	3
Interest costs	100			93			10			9
Expected return on plan assets	(115		)	(125		)	(8		)	(8		)
Amortization of prior service costs (credits)	2			3			(44		)	(50		)
Net periodic costs (credits)	$	29		$	20		$	(40	)	$	(46	)

FES' share of the net periodic pensions and OPEB costs (credits) were as follows:

	Pensions				OPEB
For the Three Months Ended March 31,	2014		2013		2014			2013
	(In millions)
Net Periodic Costs	$	4	$	5	$	(5	)	$	(5	)

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 March 31,	2014		2013		2014			2013
	(In millions)
FirstEnergy	$	21	$	11	$	(27	)	$	(30	)
FES	4		3		(4		)	(3		)

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Commitments, Guarantees and Contingencies (Details Textuals) (USD $)	3 Months Ended				3 Months Ended		12 Months Ended			0 Months Ended				3 Months Ended	0 Months Ended	1 Months Ended	3 Months Ended						3 Months Ended						3 Months Ended					3 Months Ended			0 Months Ended		3 Months Ended				3 Months Ended				3 Months Ended			0 Months Ended	3 Months Ended					0 Months Ended				3 Months Ended				3 Months Ended		3 Months Ended	12 Months Ended	1 Months Ended		12 Months Ended		0 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Jan. 31, 2009	Jun. 30, 2013 ICG Litigation	Mar. 31, 2014 Clean Water Act	Dec. 31, 2013 Clean Water Act	Apr. 19, 2013 Clean Water Act options	Apr. 30, 2009 Clean Water Act aspect_of_opinion	Apr. 16, 2014 Clean Water Act Subsequent Event	Oct. 10, 2013 Regulation of Waste Disposal IndividualsInAComplaint	Oct. 03, 2013 Regulation of Waste Disposal deficiency	Mar. 28, 2013 Regulation of Waste Disposal	Mar. 31, 2014 Regulation of Waste Disposal options	Apr. 03, 2014 Regulation of Waste Disposal Subsequent Event	May 31, 2013 Nuclear Plant Matters petitioners	Mar. 31, 2014 Nuclear Plant Matters	Mar. 31, 2014 Caa Compliance ElectricGenerationUnits CoalFiredPlants	Mar. 31, 2014 National Ambient Air Quality Standards T	Mar. 31, 2014 National Ambient Air Quality Standards CAIR phases	Mar. 31, 2014 National Ambient Air Quality Standards CSAPR phases	Mar. 31, 2014 Hazardous Air Pollutant Emissions	Mar. 31, 2014 Climate Change celsius	Jun. 30, 2013 Climate Change	Apr. 13, 2012 Climate Change lb	Jan. 02, 2011 Climate Change T	Jun. 30, 2013 Climate Change Year 2016	Jun. 30, 2013 Climate Change Year 2020	Mar. 31, 2014 Climate Change Year 2020 Increase in funding	Mar. 31, 2014 Senior Secured Term Loan Senior Loans	Mar. 31, 2014 Regulated Distribution	Mar. 31, 2014 Regulated Distribution Hazardous Air Pollutant Emissions	Mar. 31, 2014 Competitive Energy Services Hazardous Air Pollutant Emissions	Mar. 31, 2014 FES	Mar. 31, 2013 FES	Dec. 31, 2013 FES	Apr. 16, 2014 FES Subsequent Event	Mar. 31, 2014 AE Supply	Mar. 31, 2014 AE Supply ICG Litigation	Mar. 31, 2014 Global Holding	Mar. 31, 2014 Global Holding Senior Secured Term Loan Senior Loans	Mar. 31, 2014 Global Holding Senior Secured Term Loan Senior Loans Signal Peak, Global Rail and Affiliates	Mar. 31, 2014 Signal Peak and Global Rail	Mar. 31, 2014 Signal Peak and Global Rail Senior Secured Term Loan Senior Loans	Mar. 31, 2014 FEV Senior Secured Term Loan Senior Loans Signal Peak Global Holding	Mar. 31, 2014 WMB Marketing Ventures, LLC Senior Secured Term Loan Senior Loans Signal Peak Global Holding	Mar. 31, 2014 FGCO	Mar. 31, 2013 FGCO	Dec. 31, 2013 FGCO	Dec. 05, 2013 FGCO Regulation of Waste Disposal IndividualsInAComplaint	Mar. 31, 2014 FGCO Caa Compliance Complaints	Mar. 31, 2014 FGCO Caa Compliance Claim One IndividualsInAComplaint Complaints	Mar. 31, 2014 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	Mar. 31, 2014 Parental Guarantees	Mar. 31, 2014 Subsidiaries' Guarantees	Mar. 31, 2014 Other Guarantees	Mar. 31, 2014 State and Local Agencies Hazardous Air Pollutant Emissions	Mar. 31, 2014 Environmental Protection Agency Hazardous Air Pollutant Emissions	Mar. 31, 2014 Minimum Clean Water Act	Apr. 13, 2012 Minimum Climate Change	Mar. 31, 2014 Maximum Clean Water Act	Apr. 13, 2012 Maximum Climate Change	Dec. 31, 2013 Transportation Commitment Hazardous Air Pollutant Emissions	Dec. 31, 2012 Transportation Commitment Hazardous Air Pollutant Emissions contracts	Jan. 31, 2014 Mepco Holdings,LLC Hazardous Air Pollutant Emissions	Mar. 31, 2014 Beaver Valley Unit 1 and Perry Nuclear Plant Matters	Dec. 31, 2013 Little Blue Run Regulation of Waste Disposal	Feb. 01, 2014 Davis-Besse Nuclear Power Station fuel_assembly stream_generator	Feb. 01, 2014 Davis-Besse Nuclear Power Station FES
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	$ 4,000,000,000																																																								$ 896,000,000	$ 2,207,000,000	$ 891,000,000
Company posted collateral related to net liability positions																															28,000,000			544,000,000				8,000,000
Proceeds from return of collateral																																					275,000,000
Potential collateral posted related to net liability positions																																		111,000,000				1,000,000
New syndicated senior secured term loan facility																																									350,000,000
Repayments of senior secured term loan facility	489,000,000	846,000,000																																445,000,000	476,000,000									350,000,000			248,000,000	107,000,000
Senior secured term loan facility, term																																								3 years			2 years
Investment ownership percentage																																										69.99%			33.33%	33.33%
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																																							15		21
Number of named plaintiffs as class representatives																																																					8
Jointly owned utility plant, proportionate ownership share				16.67%
Reduction in air emissions and compliance																																																															25.00%		40.00%
Additional Regulation Finalization Period										29 days
Number of treatment options								8
Number of preferred treatment options								4
Waste water discharge permit renewal cycle							5 years
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										225,000,000	240,000,000
Loss Contingency, Settlement Agreement, Consideration																																																																		67,000,000	70,000,000	18,000,000
Percent reduction in GHG Emissions Between 2005 And 2012																								10.00%
Anticipated Reduction in CO2 Emissions (Percent)																											25.00%
Proposed Executive Action, Reduction in Power Plants Carbon Pollution, Percentage																												17.00%
Proposed emissions standard of large natural gas fired units																									1,000
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, Other Natural Gas Fired Units																									1,100
Commitment, Proposed Emissions Standard, Fossil Fuel Fired Units																									1,100
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		300,000,000
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												9 years	15 years
Bond Closure and Post Closure Period												45 years
Asset Retirement Obligation, Period Increase (Decrease)																																																																						163,000,000
Permit to Provide Bonding for Closure and Post-Closure Activities															45 years
Period to Complete Closure															12 years
Accrual for Environmental Loss Contingencies														129,000,000
Environmental Liabilities Former Gas Facilities														82,000,000
Decommissioning Fund Investments	2,263,000,000		2,201,000,000														2,300,000,000																	1,323,000,000		1,276,000,000											0		0
Parental guarantee associated with the funding of decommissioning costs																	125,000,000																																																				9,500,000
Parental Guarantee Associated With Funding Of Decommissioning Costs, Additions																	11,000,000
Parental Guarantee Associated With Funding Of Decommissioning Costs, Next Fiscal Quarter																	155,000,000
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
Loss Contingency, Claims Settled Number																																																																			2
Gain contingency, damages denied					15,500,000
Number of Petitioners																2
Number of Steam Generators to Be Installed																																																																							2
Number of Fuel Assemblies to Be Replaced, Percent																																																																							33.33%
Number of Fuel Assemblies																																																																							177
Utilities Operating Expense, Maintenance, Operations, and Other Costs and Expenses																																																																								$ 600,000,000

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Organization and Basis of Presentation

3 Months Ended

Mar. 31, 2014

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.

FirstEnergy Corp. was organized under the laws of the State of Ohio in 1996. FirstEnergy’s principal business is the holding, directly or indirectly, of all of the outstanding common stock of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, FES and its principal subsidiaries (FG and NG), AE Supply, MP, PE, WP and FET. In addition, FirstEnergy holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., and GPU Nuclear, Inc.

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, 2013.

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 6, 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. These reclassifications include, but are not limited to, the classification of discontinued operations associated with our sale of hydro assets discussed in additional detail in Note 13, Discontinued Operations.

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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Earnings Per Share of Common Stock

3 Months Ended

Mar. 31, 2014

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:

(In millions, except per share amounts)	Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2014		2013
Income from continuing operations	$	122	$	192
Discontinued operations (Note 13)	86		4
Net income	$	208	$	196
Weighted average number of basic shares outstanding	419		418
Assumed exercise of dilutive stock options and awards(1)	1		1
Weighted average number of diluted shares outstanding	420		419
Earnings per share:
Basic earnings per share:
Income from continuing operations	$	0.29	$	0.46
Discontinued operations (Note 13)	0.21		0.01
Net earnings per basic share	$	0.50	$	0.47
Diluted earnings per share:
Income from continuing operations	$	0.29	$	0.46
Discontinued operations (Note 13)	0.20		0.01
Net earnings per diluted share	$	0.49	$	0.47

⁽¹⁾  For the three months ended March 31, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the three months ended March 31, 2013.

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Accumulated Other Comprehensive Income

3 Months Ended

Mar. 31, 2014

Statement of Comprehensive Income [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, in the three months ended March 31, 2014 and 2013, 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 January 1, 2014	$	(36	)	$	9		$	311		$	284
Other comprehensive income before reclassifications	—			22			—			22
Amounts reclassified from AOCI	—			(9		)	(26		)	(35		)
Net other comprehensive income (loss)	—			13			(26		)	(13		)
AOCI Balance as of March 31, 2014	$	(36	)	$	22		$	285		$	271
AOCI Balance as of January 1, 2013	$	(38	)	$	15		$	408		$	385
Other comprehensive income before reclassifications	—			15			—			15
Amounts reclassified from AOCI	1			(12		)	(28		)	(39		)
Net other comprehensive income (loss)	1			3			(28		)	(24		)
AOCI Balance as of March 31, 2013	$	(37	)	$	18		$	380		$	361
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, 2014	$	(1	)	$	8		$	47		$	54
Other comprehensive income before reclassifications	—			21			—			21
Amounts reclassified from AOCI	(1		)	(9		)	(3		)	(13		)
Net other comprehensive income (loss)	(1		)	12			(3		)	8
AOCI Balance as of March 31, 2014	$	(2	)	$	20		$	44		$	62
AOCI Balance as of January 1, 2013	$	3		$	13		$	56		$	72
Other comprehensive income before reclassifications	—			14			—			14
Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
Net other comprehensive income (loss)	(1		)	4			(4		)	(1		)
AOCI Balance as of March 31, 2013	$	2		$	17		$	52		$	71

The following amounts were reclassified from AOCI in the three months ended March 31, 2014 and 2013:

FE	Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(2	)	$	(3	)	Other operating expenses
Long-term debt	2			4			Interest expense ($2) in 2014 and Interest expense ($2) and loss on debt redemptions ($2) in 2013
	—			1			Total before taxes
	—			—			Income taxes
	$	—		$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(14	)	$	(19	)	Investment income
	5			7			Income taxes
	$	(9	)	$	(12	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(42	)	$	(47	)	(a)
	16			19			Income taxes
	$	(26	)	$	(28	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.
FES	Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (b)	2014			2013
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	(2	)	$	(3	)	Other operating expenses
Long-term debt	—			2			Loss on debt redemptions
	(2		)	(1		)	Total before taxes
	1			—			Income tax benefits
	$	(1	)	$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	(14	)	$	(16	)	Investment income
	5			6			Income tax benefits
	$	(9	)	$	(10	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(5	)	$	(5	)	(a)
	2			1			Income tax benefits
	$	(3	)	$	(4	)	Net of tax
(a) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pensions and Other Postemployment Benefits for additional details.
(b) Parenthesis represent credits to the Consolidated Statements of Income from AOCI.

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Segment Financial Information
Revenues	$ 4,189		$ 3,723
Total revenues	4,189	[1]	3,723	[1]
Depreciation and amortization	266		352
Investment income	22		18
Interest expense	265		258
Income taxes (benefits)	48		114
Income from continuing operations	122		192
Discontinued operations (Note 13)	86		4
NET INCOME (LOSS)	208		196
Total assets	51,228		50,424		50,424
Total goodwill	6,418		6,447		6,418
Property additions	821		826
Intersegment Eliminations [Member]
Segment Financial Information
Revenues	0		0
Operating Segments [Member]
Segment Financial Information
Total revenues	4,189		3,723
Regulated Distribution
Segment Financial Information
Revenues	2,552		2,212
Depreciation and amortization	131		202
Investment income	15		18
Interest expense	151		135
Income taxes (benefits)	125		126
Income from continuing operations	214		210
Discontinued operations (Note 13)	0		0
NET INCOME (LOSS)	214		210
Total assets	27,742		26,943
Total goodwill	5,092		5,025
Property additions	269		436
Regulated Distribution | Intersegment Eliminations [Member]
Segment Financial Information
Revenues	0		0
Regulated Distribution | Operating Segments [Member]
Segment Financial Information
Total revenues	2,552		2,212
Regulated Transmission
Segment Financial Information
Revenues	187		176
Depreciation and amortization	33		29
Investment income	0		0
Interest expense	25		23
Income taxes (benefits)	30		31
Income from continuing operations	51		51
Discontinued operations (Note 13)	0		0
NET INCOME (LOSS)	51		51
Total assets	5,584		4,722
Total goodwill	526		526
Property additions	217		89
Regulated Transmission | Intersegment Eliminations [Member]
Segment Financial Information
Revenues	0		0
Regulated Transmission | Operating Segments [Member]
Segment Financial Information
Total revenues	187		176
Competitive Energy Services
Segment Financial Information
Revenues	1,522		1,414
Depreciation and amortization	91		110
Investment income	14		10
Interest expense	46		73
Income taxes (benefits)	(73)		(24)
Income from continuing operations	(124)		(42)
Discontinued operations (Note 13)	86		4
NET INCOME (LOSS)	(38)		(38)
Total assets	17,445		18,328
Total goodwill	800		896
Property additions	318		283
Competitive Energy Services | Intersegment Eliminations [Member]
Segment Financial Information
Revenues	249		216
Competitive Energy Services | Operating Segments [Member]
Segment Financial Information
Total revenues	1,771		1,630
Other/Corporate
Segment Financial Information
Revenues	(35)		(27)
Depreciation and amortization	11		11
Investment income	3		1
Interest expense	43		27
Income taxes (benefits)	(26)		(19)
Income from continuing operations	(32)		(30)
Discontinued operations (Note 13)	0		0
NET INCOME (LOSS)	(32)		(30)
Total assets	457		431
Total goodwill	0		0
Property additions	17		18
Other/Corporate | Intersegment Eliminations [Member]
Segment Financial Information
Revenues	0		0
Other/Corporate | Operating Segments [Member]
Segment Financial Information
Total revenues	(35)		(27)
Reconciling Adjustments
Segment Financial Information
Revenues	(37)		(52)
Depreciation and amortization	0		0
Investment income	(10)		(11)
Interest expense	0		0
Income taxes (benefits)	(8)		0
Income from continuing operations	13		3
Discontinued operations (Note 13)	0		0
NET INCOME (LOSS)	13		3
Total assets	0		0
Total goodwill	0		0
Property additions	0		0
Reconciling Adjustments | Intersegment Eliminations [Member]
Segment Financial Information
Revenues	(249)		(216)
Reconciling Adjustments | Operating Segments [Member]
Segment Financial Information
Total revenues	$ (286)		$ (268)

[1] Includes excise tax collections of $117 million and $122 million in the three months ended March 31, 2014 and 2013, respectively.

XML

Discontinued Operations (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Feb. 12, 2014
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	$ 394	$ 0
Carrying value of assets sold			235
Discontinued operations, goodwill			29
Pre-tax income from discontinued operation	155	6
Pre-tax gain on sale of assets	142
Revenues from discontinued operations	5	6
FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales	307	17
Carrying value of assets sold			122
Discontinued operations, goodwill			1
Pre-tax income from discontinued operation	186	5
Pre-tax gain on sale of assets	177
Revenues from discontinued operations	$ 5	$ 6

XML

Supplemental Guarantor Information (Details 2) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	$ (92)	$ 50
New Financing-
Long-term debt	1,467	1,800
Short-term borrowings, net	0	181
Redemptions and Repayments-
Long-term debt	(489)	(846)
Short-term borrowings, net	(319)	0
Tender premiums	0	(110)
Other	(10)	(23)
Net cash provided from (used for) financing activities	498	772
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(821)	(826)
Nuclear fuel	(55)	(27)
Proceeds from asset sales	394	0
Sales of investment securities held in trusts	621	539
Purchases of investment securities held in trusts	(646)	(565)
Other	3	(1)
Net cash used for investing activities	(515)	(927)
Net change in cash and cash equivalents	(109)	(105)
Cash and cash equivalents at beginning of period	218	172
Cash and cash equivalents at end of period	109	67
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	(450)	(529)
New Financing-
Long-term debt	0
Short-term borrowings, net	209	894
Equity contribution from parent	500
Redemptions and Repayments-
Long-term debt	0	(369)
Short-term borrowings, net	0	0
Tender premiums		(67)
Other	(1)	0
Net cash provided from (used for) financing activities	708	458
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2)	(5)
Nuclear fuel	0	0
Proceeds from asset sales	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	(254)	75
Other	(2)	1
Net cash used for investing activities	(258)	71
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FGCO
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	87	298
New Financing-
Long-term debt	235
Short-term borrowings, net	72	0
Equity contribution from parent	0
Redemptions and Repayments-
Long-term debt	(248)	(107)
Short-term borrowings, net	0	(76)
Tender premiums		0
Other	(2)	(1)
Net cash provided from (used for) financing activities	57	(184)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(28)	(138)
Nuclear fuel	0	0
Proceeds from asset sales	307	17
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	(425)	7
Other	2	0
Net cash used for investing activities	(144)	(114)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	3
Cash and cash equivalents at end of period	2	3
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	51	36
New Financing-
Long-term debt	182
Short-term borrowings, net	0	586
Equity contribution from parent	0
Redemptions and Repayments-
Long-term debt	(197)	0
Short-term borrowings, net	(151)	0
Tender premiums		0
Other	(1)	0
Net cash provided from (used for) financing activities	(167)	586
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(268)	(74)
Nuclear fuel	(55)	(27)
Proceeds from asset sales	0	0
Sales of investment securities held in trusts	423	252
Purchases of investment securities held in trusts	(438)	(265)
Loans to affiliated companies, net	454	(508)
Other	0	0
Net cash used for investing activities	116	(622)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
Eliminations
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	0	0
New Financing-
Long-term debt	0
Short-term borrowings, net	(161)	(778)
Equity contribution from parent	0
Redemptions and Repayments-
Long-term debt	0	0
Short-term borrowings, net	151	76
Tender premiums		0
Other		0
Net cash provided from (used for) financing activities	(10)	(702)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	0	0
Nuclear fuel	0	0
Proceeds from asset sales	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Loans to affiliated companies, net	10	702
Other	0	0
Net cash used for investing activities	10	702
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	0	0
Cash and cash equivalents at end of period	0	0
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	(312)	(195)
New Financing-
Long-term debt	417	0
Short-term borrowings, net	120	702
Equity contribution from parent	500	0
Redemptions and Repayments-
Long-term debt	(445)	(476)
Short-term borrowings, net	0	0
Tender premiums	0	(67)
Other	(4)	(1)
Net cash provided from (used for) financing activities	588	158
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(298)	(217)
Nuclear fuel	(55)	(27)
Proceeds from asset sales	307	17
Sales of investment securities held in trusts	423	252
Purchases of investment securities held in trusts	(438)	(265)
Loans to affiliated companies, net	(215)	276
Other	0	1
Net cash used for investing activities	(276)	37
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	3
Cash and cash equivalents at end of period	$ 2	$ 3

XML

Supplemental Guarantor Information (Tables)

3 Months Ended

Mar. 31, 2014

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Statements of Income and Comprehensive Income

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,797		$	315		$	362		$	(645	)	$	1,829
OPERATING EXPENSES:
Fuel	—			272			47			—			319
Purchased power from affiliates	645			—			64			(645		)	64
Purchased power from non-affiliates	1,025			4			—			—			1,029
Other operating expenses	228			62			150			12			452
Provision for depreciation	2			29			43			—			74
General taxes	21			11			7			—			39
Total operating expenses	1,921			378			311			(633		)	1,977
OPERATING INCOME (LOSS)	(124		)	(63		)	51			(12		)	(148		)
OTHER INCOME (EXPENSE):
Loss on debt redemptions	(3		)	(1		)	(1		)	—			(5		)
Investment income	1			1			21			(3		)	20
Miscellaneous income, including net income from equity investees	103			—			—			(103		)	—
Interest expense — affiliates	(3		)	(1		)	(1		)	3			(2		)
Interest expense — other	(14		)	(24		)	(13		)	15			(36		)
Capitalized interest	—			1			11			—			12
Total other income (expense)	84			(24		)	17			(88		)	(11		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(40		)	(87		)	68			(100		)	(159		)
INCOME TAXES (BENEFITS)	(52		)	(31		)	26			1			(56		)
INCOME (LOSS) FROM CONTINUING OPERATIONS	12			(56		)	42			(101		)	(103		)
Discontinued operations (net of income taxes of $70) (Note 13)	—			116			—			—			116
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	12		$	60		$	42		$	(101	)	$	13
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	19			—			19			(19		)	19
Other comprehensive income (loss)	12			(4		)	19			(15		)	12
Income taxes (benefits) on other comprehensive income (loss)	4			(2		)	7			(5		)	4
Other comprehensive income (loss), net of tax	8			(2		)	12			(10		)	8
COMPREHENSIVE INCOME	$	20		$	58		$	54		$	(111	)	$	21

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(Unaudited)

For the Three Months Ended March 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,496		$	531		$	440		$	(943	)	$	1,524
OPERATING EXPENSES:
Fuel	—			247			53			—			300
Purchased power from affiliates	1,013			—			62			(943		)	132
Purchased power from non-affiliates	505			1			—			—			506
Other operating expenses	162			74			131			12			379
Provision for depreciation	1			31			44			(1		)	75
General taxes	20			11			6			—			37
Total operating expenses	1,701			364			296			(932		)	1,429
OPERATING INCOME (LOSS)	(205		)	167			144			(11		)	95
OTHER INCOME (EXPENSE):
Loss on debt redemption	(71		)	—			—			—			(71		)
Investment income	1			—			18			(2		)	17
Miscellaneous income, including net income from equity investees	192			1			—			(191		)	2
Interest expense — affiliates	(2		)	(1		)	(1		)	3			(1		)
Interest expense — other	(25		)	(28		)	(15		)	16			(52		)
Capitalized interest	—			—			9			—			9
Total other income (expense)	95			(28		)	11			(174		)	(96		)
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(110		)	139			155			(185		)	(1		)
INCOME TAXES (BENEFITS)	(112		)	51			58			3			—
INCOME (LOSS) FROM CONTINUING OPERATIONS	2			88			97			(188		)	(1		)
Discontinued operations (net of income taxes of $2) (Note 13)	—			3			—			—			3
NET INCOME	$	2		$	91		$	97		$	(188	)	$	2
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	2		$	91		$	97		$	(188	)	$	2
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(6		)	(5		)	—			5			(6		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available for sale securities	5			—			5			(5		)	5
Other comprehensive income (loss)	(2		)	(5		)	5			—			(2		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(2		)	2			—			(1		)
Other comprehensive income (loss), net of tax	(1		)	(3		)	3			—			(1		)
COMPREHENSIVE INCOME	$	1		$	88		$	100		$	(188	)	$	1

Condensed Consolidating Balance Sheets

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of March 31, 2014	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	583		—		—		—			583
Affiliated companies	278		185		180		(274		)	369
Other	60		18		73		—			151
Notes receivable from affiliated companies	457		449		230		(921		)	215
Materials and supplies	63		148		216		—			427
Derivatives	244		—		—		—			244
Collateral	544		—		—		—			544
Prepayments and other	100		79		—		—			179
	2,329		881		699		(1,195		)	2,714
PROPERTY, PLANT AND EQUIPMENT:
In service	106		6,148		6,925		(383		)	12,796
Less — Accumulated provision for depreciation	30		1,978		3,038		(189		)	4,857
	76		4,170		3,887		(194		)	7,939
Construction work in progress	26		130		1,200		—			1,356
	102		4,300		5,087		(194		)	9,295
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,323		—			1,323
Investment in affiliated companies	5,891		—		—		(5,891		)	—
Other	—		11		—		—			11
	5,891		11		1,323		(5,891		)	1,334
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		105		—		(105		)	—
Customer intangibles	91		—		—		—			91
Goodwill	23		—		—		—			23
Property taxes	—		11		19		—			30
Unamortized sale and leaseback costs	—		—		—		197			197
Derivatives	65		—		—		—			65
Other	72		223		9		(154		)	150
	251		339		28		(62		)	556
	$	8,573	$	5,531	$	7,137	$	(7,342	)	$	13,899
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	120	$	366	$	(22	)	$	465
Short-term borrowings-
Affiliated companies	636		283		—		(919		)	—
Other	550		5		—		—			555
Accounts payable-
Affiliated companies	373		19		240		(305		)	327
Other	183		112		—		—			295
Accrued taxes	3		68		38		(12		)	97
Derivatives	159		—		—		—			159
Other	51		62		21		80			214
	1,956		669		665		(1,178		)	2,112
CAPITALIZATION:
Total equity	5,807		2,343		3,548		(5,865		)	5,833
Long-term debt and other long-term obligations	712		2,094		931		(1,186		)	2,551
	6,519		4,437		4,479		(7,051		)	8,384
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		850			850
Accumulated deferred income taxes	11		—		763		36			810
Asset retirement obligations	—		188		841		—			1,029
Retirement benefits	22		167		—		—			189
Derivatives	36		—		—		—			36
Other	29		70		389		1			489
	98		425		1,993		887			3,403
	$	8,573	$	5,531	$	7,137	$	(7,342	)	$	13,899

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

(Unaudited)

As of December 31, 2013	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	539		—		—		—			539
Affiliated companies	938		787		227		(916		)	1,036
Other	52		12		17		—			81
Notes receivable from affiliated companies	203		23		683		(909		)	—
Materials and supplies	76		159		213		—			448
Derivatives	165		—		—		—			165
Collateral	136		—		—		—			136
Prepayments and other	52		50		7		—			109
	2,161		1,033		1,147		(1,825		)	2,516
PROPERTY, PLANT AND EQUIPMENT:
In service	104		6,105		6,645		(382		)	12,472
Less — Accumulated provision for depreciation	28		1,953		2,962		(188		)	4,755
	76		4,152		3,683		(194		)	7,717
Construction work in progress	23		148		1,137		—			1,308
	99		4,300		4,820		(194		)	9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,276		—			1,276
Investment in affiliated companies	5,801		—		—		(5,801		)	—
Other	—		11		—		—			11
	5,801		11		1,276		(5,801		)	1,287
ASSETS HELD FOR SALE	—		122		—		—			122
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	—		131		—		(131		)	—
Customer intangibles	95		—		—		—			95
Goodwill	23		—		—		—			23
Property taxes	—		15		26		—			41
Unamortized sale and leaseback costs	—		—		—		168			168
Derivatives	53		—		—		—			53
Other	81		228		18		(155		)	172
	252		374		44		(118		)	552
	$	8,313	$	5,840	$	7,287	$	(7,938	)	$	13,502
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1	$	367	$	547	$	(23	)	$	892
Short-term borrowings-
Affiliated companies	977		212		151		(909		)	431
Other	—		4		—		—			4
Accounts payable-
Affiliated companies	741		400		362		(738		)	765
Other	94		196		—		—			290
Accrued taxes	204		23		23		(184		)	66
Derivatives	110		—		—		—			110
Other	70		63		18		46			197
	2,197		1,265		1,101		(1,808		)	2,755
CAPITALIZATION:
Total equity	5,312		2,283		3,493		(5,776		)	5,312
Long-term debt and other long-term obligations	712		1,860		742		(1,184		)	2,130
	6,024		4,143		4,235		(6,960		)	7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		858			858
Accumulated deferred income taxes	32		—		736		(27		)	741
Asset retirement obligations	—		187		828		—			1,015
Retirement benefits	22		163		—		—			185
Derivatives	14		—		—		—			14
Other	24		82		387		(1		)	492
	92		432		1,951		830			3,305
	$	8,313	$	5,840	$	7,287	$	(7,938	)	$	13,502

Condensed Consolidating Statements of Cash Flows

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2014	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(450	)	$	87		$	51		$	—		$	(312	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	—			235			182			—			417
Short-term borrowings, net	209			72			—			(161		)	120
Equity contribution from parent	500			—			—			—			500
Redemptions and Repayments-
Long-term debt	—			(248		)	(197		)	—			(445		)
Short-term borrowings, net	—			—			(151		)	151			—
Other	(1		)	(2		)	(1		)	—			(4		)
Net cash provided from (used for) financing activities	708			57			(167		)	(10		)	588
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2		)	(28		)	(268		)	—			(298		)
Nuclear fuel	—			—			(55		)	—			(55		)
Proceeds from asset sales	—			307			—			—			307
Sales of investment securities held in trusts	—			—			423			—			423
Purchases of investment securities held in trusts	—			—			(438		)	—			(438		)
Loans to affiliated companies, net	(254		)	(425		)	454			10			(215		)
Other	(2		)	2			—			—			—
Net cash provided from (used for) investing activities	(258		)	(144		)	116			10			(276		)
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			2			—			—			2
Cash and cash equivalents at end of period	$	—		$	2		$	—		$	—		$	2

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

(Unaudited)

For the Three Months Ended March 31, 2013	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(529	)	$	298		$	36		$	—		$	(195	)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	894			—			586			(778		)	702
Redemptions and Repayments-
Long-term debt	(369		)	(107		)	—			—			(476		)
Short-term borrowings, net	—			(76		)	—			76			—
Tender premiums	(67		)	—			—			—			(67		)
Other	—			(1		)	—			—			(1		)
Net cash provided from financing activities	458			(184		)	586			(702		)	158
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(5		)	(138		)	(74		)	—			(217		)
Nuclear fuel	—			—			(27		)	—			(27		)
Proceeds from asset sales	—			17			—			—			17
Sales of investment securities held in trusts	—			—			252			—			252
Purchases of investment securities held in trusts	—			—			(265		)	—			(265		)
Loans to affiliated companies, net	75			7			(508		)	702			276
Other	1			—			—			—			1
Net cash used for investing activities	71			(114		)	(622		)	702			37
Net change in cash and cash equivalents	—			—			—			—			—
Cash and cash equivalents at beginning of period	—			3			—			—			3
Cash and cash equivalents at end of period	$	—		$	3		$	—		$	—		$	3

XML

Derivative Instruments (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Fair value of commodity derivatives
Derivative Assets	$ 314	$ 239
Derivative Liabilities	(383)	(347)
Current Assets
Fair value of commodity derivatives
Derivative Assets	247	166
Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	67	73
Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(159)	(111)
Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(224)	(236)
Power Contracts | Current Assets
Fair value of commodity derivatives
Derivative Assets	240	162
Power Contracts | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	64	53
Power Contracts | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(154)	(102)
Power Contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(33)	(11)
FTRs | Current Assets
Fair value of commodity derivatives
Derivative Assets	7	4
FTRs | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(5)	(9)
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(3)	(3)
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	3	20
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	$ (188)	$ (222)

XML

Regulatory Matters

3 Months Ended

Mar. 31, 2014

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 any of the FirstEnergy affiliates were to engage in the construction of significant new transmission or generation facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission or generation facility.

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.PE filed its second annual report on March 27, 2014.

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; selective increased investment in system hardening; 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 July 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 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 concluded.In the initial briefs of the parties filed on January 27, 2014, the Division of Rate Counsel recommended that base rate revenues be reduced by $214.9 million while the NJBPU Staff recommended a $207.4 million reduction (such amounts do not address the revenue requirements associated with the major storm events of 2011 and 2012).Reply briefs were filed on February 24, 2014. The matter is pending before the ALJ.

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 February 24, 2014, a Stipulation was filed with the NJBPU by JCP&L, the Division of Rate Counsel and NJBPU Staff which will allow recovery of $736 million of JCP&L's $744 million of costs related to the significant weather events of 2011 and 2012.As a result, FirstEnergy recorded a regulatory asset impairment charge of approximately $8 million (pre-tax) as of December 31, 2013.By its Order of March 19, 2014, the NJBPU approved the Stipulation of Settlement and on March 25, 2014, transmitted a copy of that Order to the Office of Administrative Law so that “actual recovery of the 2011 costs can be determined in relation to the pending base rate case.”Recovery of 2011 storm costs will be addressed in the pending base rate case; recovery of 2012 storm costs will be determined by the NJBPU.

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 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 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.While briefing has been completed, 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 provides 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 SB221, the Ohio Companies are required to implement energy efficiency programs that 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, on July 31, 2012 the Ohio Companies filed their three-year portfolio plan for the period January 1, 2013 through December 31, 2015.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 denied the Ohio Companies' application for rehearing, in part, but authorized 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.The motion is still pending and additional briefing has followed.While briefing has been completed, the matter has not been scheduled for oral argument.

SB221 requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage amount through 2024.The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet the renewable energy requirements established under SB221.In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs and selected auditors to perform a financial and management audit.Final audit reports filed with the PUCO generally supported the Ohio Companies' approach to procurement of RECs, but also recommended the PUCO examine, for possible disallowance, certain costs associated with the procurement of in-state renewable obligations that the auditor characterized as excessive.Following the hearing, the PUCO issued an Opinion and Order on August 7, 2013 approving the Ohio Companies' acquisition process and their purchases of RECs 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, and to file tariff schedules reflecting the refund and interest costs 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 December 18, 2013, the PUCO denied all of the applications for rehearing. Based on the PUCO ruling a regulatory charge of approximately $51 million, including interest, was recorded in the fourth quarter of 2013.On December 24, 2013, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio.On February 10, 2014, the Supreme Court of Ohio granted the Ohio Companies' motion for stay, which went into effect on February 14, 2014.On February 18, 2014, the Office of Consumers' Counsel and the ELPC also filed appeals of the PUCO's order.The Ohio Companies filed their merit brief with the Supreme Court of Ohio on March 6, 2014.On April 15, 2014, the Supreme Court of Ohio stayed the briefing schedule pending the court's resolution of the Ohio Companies' motion to seal certain confidential portions of the appendix and supplement to their merit brief.

The Ohio Companies conducted an RFP in 2013 to cover their all-state SREC and their in-state and all-state REC compliance obligations.On April 15, 2014, the Ohio Companies reported that they met all of their annual renewable energy resource requirements for reporting year 2013.

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 comment 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.On June 5, 2013, the PUCO requested additional comments and reply comments on the topics of market design and corporate separation, which the Ohio Companies timely filed on July 8, 2013 and July 22, 2013, respectively.The PUCO held a series of workshops throughout 2013, which included an en banc workshop on December 11, 2013.The PUCO Staff filed a report on January 16, 2014, which contained a limited discussion of the workshops and the PUCO Staff's recommendations.The Ohio Companies submitted comments on February 6, 2014 and Reply Comments on February 20, 2014.The PUCO issued its Order in this matter on March 26, 2014, which included a wide range of issues such as, maintaining SSO service in its current form, requiring corporate separation audits of all EDUs, establishing a market development working group, and ordering changes to the bill format.The Ohio Companies filed their Application for Rehearing on April 25, 2014.The Ohio Companies filed their memorandum contra applications for rehearing of other stakeholders on May 5, 2014.

On April 9, 2014, the PUCO initiated a generic investigation of marketing practices in the competitive retail electric service market, with a focus on the marketing of fixed-price or guaranteed percent-off SSO rate contracts where there is a provision that permits the pass-through of new or additional charges.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2015, 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 4, 2013, the Pennsylvania Companies filed a DSP 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 SRECs for ME, PN, and Penn.The Pennsylvania Companies have reached a settlement with all parties on all issues raised in the case with the exception of the treatment of NITS charges. On May 6, 2014, the ALJ issued a Recommended Decision recommending adoption of the settlement without modification and the denial of several parties’ request for non-bypassable treatment of NITS charges. A final order is expected from the PPUC by August 2014.

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.On appeal, the Commonwealth Court affirmed 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 and the Supreme Court of the United States denied ME's and PN's Petition for Writ of Certiorari.ME and PN also filed a complaint in the U.S. District Court for the Eastern District of Pennsylvania to obtain 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.On September 30, 2013, the U.S. District Court granted the PPUC’s motion to dismiss.As a result of the U.S. District Court's decision, FirstEnergy recorded a regulatory asset impairment charge of approximately $254 million (pre-tax) in the quarter ended September 30, 2013. The balance of marginal transmission losses was fully refunded to customers by the second quarter of 2013.On October 29, 2013, ME and PN filed a Notice of Appeal of the U.S. District Court's decision to dismiss the complaint with the United States Court of Appeals for the Third Circuit.Oral argument was held on April 8, 2014, and, at the end of the argument, the Third Circuit directed ME and PN, and the PPUC, each to submit a brief on April 16, 2014 on the question of whether it is possible to waive the preemptive effect of FERC’s classification of line loss charges as transmission charges.On April 16, 2014, ME and PN, the PPUC, and the Pennsylvania Industrials each submitted briefs on the Third Circuit's questions.

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 a 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 between $1 and$20 million.On November 15, 2013, the Pennsylvania Companies submitted their energy efficiency and peak demand reduction report for the period ending May 31, 2013, in which they indicated that all of the Pennsylvania Companies met their statutory requirements.On March 20, 2014, the PPUC issued an Order initially determining that ME, PN and Penn achieved the 2011 and 2013 statutory energy efficiency benchmarks. The PPUC also initially determined that WP is not in compliance with the 2011 statutory energy efficiency benchmarks but is in compliance with the 2013 energy efficiency benchmarks.As such, the PPUC, with regards to WP’s compliance with the 2011 statutory benchmarks, referred the matter to the PPUC Bureau of Investigation and Enforcement for the initiation of an appropriate proceeding no later than May 30, 2014 to investigate whether WP is in compliance with the 2011 statutory benchmarks and whether WP is subject to statutory penalties.The PPUC also ordered that the initial determination will be deemed final unless any petitions challenging its initial determination are filed within 20 days of the Order.On April 9, 2014, WP filed its petition challenging the PPUC’s initial determination arguing, among other things, that the May 2011 target was not mandatory and WP is in compliance because it achieved its May 2013 targets.On April 21, 2014, WP filed an appeal with the Commonwealth Court of Pennsylvania in which it challenged the PPUC's initial finding of a violation of Act 129 on due process grounds.On that same day, the Bureau of Investigation and Enforcement, consistent with the PPUC's March 20, 2014 Order, initiated a proceeding by filing a Complaint against WP in which it alleges that WP violated Act 129 and recommends a penalty in the amount of $11.4 million.The Pennsylvania Companies have 20 days in which to respond to the Complaint.A prehearing conference is scheduled for May 9, 2014 at which time a procedural schedule for this matter is expected to be established.

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.Based upon information received, the PPUC has not included a peak demand reduction requirement in the Phase II plans.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 requested 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 were held and briefs were submitted by the Pennsylvania Companies and the OCA.On November 8, 2013, the ALJ issued a Recommended Decision recommending that the Pennsylvania Companies' Deployment Plan be adopted with certain modifications, including, among other things, that the Pennsylvania Companies perform further benchmarking analyses on their costs and hire an independent consultant to perform further analyses on potential savings.On December 2, 2013, the Pennsylvania Companies submitted exceptions in which they challenged, among other things, certain recommendations in the ALJ's decision, and requested approval of a modification to the deployment schedule so as to allow the entire Penn smart meter system (170,000 meters) to be built by the end of 2015, instead of the original proposed installation of 60,000 meters by the end of 2016.The OCA took exception to one issue and both parties filed replies to exceptions on December 12, 2013.In its March 6, 2014 Opinion and Order, the PPUC rejected the OCA's exception and many of the ALJ's recommendations, including the recommendation to hire an independent consultant and the disallowance of $5.1 million of customer information system costs, and affirmed the ALJ's recommendation on the accounting treatment for legacy meter costs.The PPUC also directed the Pennsylvania Companies to file an amendment to the Deployment Plan within thirty days of the Order with sufficient supporting documentation for proper evaluation if the Pennsylvania Companies intend to pursue an accelerated deployment schedule, and the PPUC indicated that it would establish an expedited procedural schedule and rule on the filing within 90 days of the March 6, 2014 Order.The Pennsylvania Companies filed an amended Deployment Plan on March 19, 2014, to which, the OCA filed exceptions arguing that the amended plan failed to: 1) list certain potential cost savings categories that are to be considered by the Pennsylvania Companies; and 2) follow proper procedure. On April 7, 2014, the Pennsylvania Companies filed a reply to OCA’s exceptions explaining why they should be rejected.A prehearing conference was held on April 25, 2014, and a procedural schedule was established that is expected to allow the PPUC to issue an order by June 5, 2014.

In the PPUC Order approving the FirstEnergy and AE 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.On March 24, 2014, the PPUC issued a letter withdrawing the Proposed Rulemaking.

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.

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.A hearing was held on December 3, 2013, and briefing followed.The WVPSC issued an order on April 14, 2014 approving the plan, stating rate recovery will be addressed in the base rate case filed on April 30, 2014. In the interim, MP and PE are authorized to defer all costs associated with the plan.

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 filed a Petition for approval of a Generation Resource Transaction with the WVPSC in November 2012 that proposed a net ownership transfer of1,476MW of coal-fired generation capacity to MP.The proposed transfer involved 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.FERC authorized the transfers on April 23, 2013 and the financing on May 13, 2013.A Joint Settlement Agreement was filed by the majority of parties on August 21, 2013.On October 7, 2013, the WVPSC authorized the transaction, with certain conditions, and on October 9, 2013, the transaction closed resulting in MP recording a pre-tax impairment charge of approximately$322 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.Concurrently, MP recognized a regulatory liability of approximately$23 millionrepresenting 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 billionand MP's assumption of a$73.5 millionpollution control note.The$1.1 billionnet consideration was originally financed by MP through an equity infusion from FE of approximately$527 millionand a note payable to AE Supply of approximately$573 million.The note payable to AE Supply was paid in the fourth quarter of 2013.The settlement also required MP and PE to file a base rate case by April 30, 2014.On November 6, 2013, the WVCAG petitioned for appeal with the Supreme Court of Appeals of West Virginia.MP and PE filed their response to the WVCAG petition on December 27, 2013 and WVCAG filed its reply on January 16, 2014.The Supreme Court of Appeals of West Virginia held oral arguments on March 5, 2014.On April 23, 2014 the Supreme Court of Appeals of West Virginia delivered an Opinion affirming the WVPSC order approving the Generation Resource Transaction.

On April 30, 2014, MP and PE filed a rate case requesting a base rate increase of approximately $96 million, or 9.3%. The filing also included a surcharge to recover costs of MP's and PE's vegetation management program in the amount of approximately $48 million. The proposed total rate increase request, including the cost of the vegetation management program, is approximately $144 million, or 14%. MP and PE anticipate a decision from the WVPSC in February 2015.

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 Rates

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 a Petition for Review with the U.S. Court of Appeals for the Seventh Circuit, and the case subsequently was consolidated with several other cases before that court for briefing and disposition.Briefing is complete, oral argument was held on April 22, 2014, and a decision is 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 again accepted the hybrid method.Certain parties 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 NYISO region and; (2) the PJM region and the FERC-jurisdictional members of the SERTP 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.On December 30, 2013, FERC conditionally accepted the PJM/SERTP cross-border project cost allocation filing, subject to refund and future orders in PJM's and SERTP's related Order No. 1000 interregional compliance proceedings.The PJM/NYISO and PJM/MISO cross-border project cost allocation filings remain pending before FERC.On January 16, 2014, FERC issued an order regarding the effective date of PJM's separate Order No. 1000 regional transmission planning and cost allocation compliance filing, noting that it would address the merits of the comments on and protests to that filing and related compliance filings in a future order.

Numerous parties, including ATSI, FES, TrAIL, OE, CEI, TE, Penn, JCP&L, ME, MP, PN, WP and PE, sought judicial review of Order No. 1000 before the U.S. Court of Appeals for the D.C. Circuit.Briefing is complete and oral argument was held on March 20, 2014.

The outcome of these proceedings and their impact, if any, on FirstEnergy cannot be predicted at this time.

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 many of the matters involved with the move have been resolved, FERC denied recovery by means of ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately$78.8 millionuntil such time as ATSI submits a cost/benefit analysis that demonstrates net benefits to customers from the move.On December 21, 2012, ATSI and other parties filed a proposed settlement agreement with FERC to resolve the exit fee and transmission cost allocation issues.However, FERC subsequently rejected that settlement, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges.On October 21, 2013, FirstEnergy filed a request for rehearing of FERC's order.

Separately, the question of ATSI's responsibility for certain costs for the “Michigan Thumb” transmission project continues to be disputed.Potential responsibility arises under the MISO MVP tariff, which has been litigated in complex proceedings in front of FERC and certain U.S. appellate courts.The MISO and its allied parties assert that the benefits to the ATSI zone of the Michigan Thumb project are roughly commensurate with the costs that MISO desires to charge to the ATSI zone, estimated to be as much as $16 million per year.ATSI has submitted evidence that the Michigan Thumb project provides no electric benefits to the ATSI zone and, on that basis, opposes the MISO’s efforts to impose these costs on the ATSI zone loads.The MISO and its allied parties also assert that certain language in the MISO Transmission Owners Agreement requires ATSI to pay these charges.In the event of a final non-appealable order that rules that ATSI must pay these charges, ATSI will seek recovery of these charges through its formula rate.While FERC proceedings regarding whether the MISO can charge ATSI for MVP costs remain pending, on February 24, 2014, the U.S. Supreme Court declined to hear appeals filed by FirstEnergy and other parties of the Seventh Circuit's June 2013 decision upholding FERC's acceptance of the MISO's generic MVP cost allocation proposal.

In addition, in a 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.ATSI subsequently filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit.Briefing is complete, oral argument was held on 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 cannot be predicted at this time.

California Claims Matters

In October 2006, several California governmental and utility parties presented AE Supply with a settlement proposal to resolve alleged overcharges for power sales by AE Supply to the California Energy Resource Scheduling division of the 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%for 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. PATH, 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 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.

On March 20, 2014, the settlement judge declared an impasse in efforts to achieve settlement. On March 24, 2014, the Chief ALJ terminated settlement judge procedures and appointed an ALJ to preside over the hearing phase of the case.The hearing is scheduled to commence on November 5, 2014.The issues set for hearing include the prudence of the costs, the base return on equity and the period of recovery.Depending on the outcome of the hearing, PATH-Allegheny and PATH-WV may be required to refund certain amounts that have been collected under their formula rate.

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).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.On February 12, 2014, the sale of the hydroelectric power plants to LS Power closed for approximately $394 million.See Note 13, Discontinued Operations for additional information regarding the assets sold.

MISO Capacity Portability

On June 11, 2012, in response to certain arguments advanced by MISO, 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.FirstEnergy and other parties have 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.On December 19, 2013, FERC issued an order directing that FERC staff are to attend the "joint and common market" stakeholder meetings for the purpose of monitoring progress on the initiatives described in the September 26, 2013 joint informational filing and establishing a new proceeding to reflect the broadened scope of issues contemplated by that filing and the RTOs' 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 publicly-available data 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.

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 2010, FES and AE Supply have lost more than$87 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 re-filed 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,FESC, on behalf of FES and AE Supply, filed a request for rehearing of FERC's order.That request for rehearing, and all subsequent filings in the docket, are pending before FERC.

PJM RPM Tariff Amendments

In November 2013, PJM began to submit a series of amendments to its RPM capacity tariff in order to address certain problems that have been observed in recent auctions.These problems can be grouped into four categories: (i) Demand Response (DR); (ii) imports; (iii) modeling of transmission upgrades in calculating geographic clearing prices; and (iv) arbitrage/capacity replacement.The purpose of PJM’s tariff amendments is to ensure that resources that clear in the RPM auctions are available as physical resources in the delivery year and that the rules implement comparable obligations for different types of resources.In each of the relevant dockets, FirstEnergy submitted comments as part of a coalition of utilities (generally including an affiliate of AEP, Duke and Dayton).The FirstEnergy/coalition position was that all of the PJM proposals should be accepted as proposed, and that the FERC should order PJM to take additional steps that should have the effect of eliminating additional distortions and flaws in the RPM market.PJM made two filings regarding DR; FERC accepted one as proposed on January 30, 2014, and issued a deficiency letter regarding the other on March 6, 2014. FERC also issued deficiency letters requesting additional information from PJM regarding the modeling filing on January 17, 2014 and regarding the imports filing on January 28, 2014.On February 18 and 21, 2014, respectively, PJM filed its responses to FERC's deficiency letters regarding the modeling filing and the imports filing.On April 18, 2014, FERC conditionally accepted PJM's modeling filing, as supplemented, subject to PJM's submission of a compliance filing. On April 22, 2014, FERC accepted PJM's imports filing, as supplemented.The second DR filing, which relates to the rules applicable to DR performance obligations, the arbitrage/capacity replacement filing and related filings in those dockets, and a request for rehearing of the January 30, 2014 order on the first DR filing, are pending before FERC.PJM requested FERC action on the DR performance obligations filing by April 11, 2014, and prior to the May 2014 BRA for the arbitrage/capacity replacement filing.Although FirstEnergy believes that these filings (and the associated tariff changes) should have positive implications for RPM clearing prices, generally there can be no assurance as to their ultimate impact on FirstEnergy.

PJM RPM Auctions - Calculation of Unit-Specific Offer Caps

The PJM RPM capacity tariff describes the rules for calculating the “offer cap” for each unit that offers into the RPM auctions. In summary, the offer cap is calculated by identifying certain going-forward costs, including the going-forward capital requirements, for a given unit, and then subtracting the projected energy and ancillary services revenues, net of marginal costs, from the going-forward costs.The remainder becomes the offer cap. FES learned that the PJM Market Monitor’s practice for calculating the forecast energy and ancillary services revenues has been to use the lower of the unit’s economic or cost-based offers into the PJM energy market.The Market Monitor engages in this practice based on his interpretation of certain provisions of the PJM capacity tariff. However, review of the relevant tariff language suggests that only the cost-based offer data should be used.FES determined that the Market Monitor’s use of the lower of cost-based or economic offer data has the effect of suppressing the offer cap, which can distort the price signal that is intended to come out of the RPM auction process.On April 7, 2014, FES submitted a Petition for Declaratory Order to FERC, asking for an interpretation of the relevant provisions of the PJM capacity tariff.Specifically, FES identified the difference of opinion between FES and the Market Monitor regarding interpretation of the relevant provision and asked FERC to rule on the question of whether the tariff language permits the Market Monitor’s use of the lower of cost-based or economic offer data or requires use of the cost-based offer data.FES asked FERC to rule on the petition by May 9, 2014.On April 18, 2014, the Market Monitor and other parties filed protests to FES's petition, arguing that the PJM capacity tariff allows the Market Monitor to use market-based energy offers instead of cost-based energy offers in calculating RPM auction offer caps and asking FERC to delay action on the petition until after the May 2014 BRA.FES' petition, the protest, and related filings are pending before FERC. The timing of FERC action and the outcome of this proceeding cannot be predicted at this time.

Market-Based Rate Authority, Triennial Update

OE, CEI, TE, Penn, JCP&L, ME, PN, MP, WP, PE, AE Supply, FES, FG, NG, FirstEnergy Generation Mansfield Unit 1 Corp., Buchanan Generation, LLC, and Green Valley Hydro, LLC each hold authority from FERC to sell electricity at market-based rates.One condition for retaining this authority is that every three years each entity must file an update with the FERC that demonstrates that each entity continues to meet FERC’s requirements for holding market-based rate authority.On December 20, 2013, FESC submitted to FERC the most recent triennial market power analysis filing for each market-based rate holder for the current cycle of this filing requirement.That filing is pending before FERC.

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Organization and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

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.

Consolidation Policy

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 6, 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.

Reclassification Policy

Certain prior year amounts have been reclassified to conform to the current year presentation. These reclassifications include, but are not limited to, the classification of discontinued operations associated with our sale of hydro assets discussed in additional detail in Note 13, Discontinued Operations.

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

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.

Investment Policy

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.

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Fair Value Measurements (Details 6) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 18,034	$ 17,049
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	19,321	17,957
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	2,996	3,001
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	$ 3,098	$ 3,073

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Variable Interest Entities (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,293
Discounted Lease Payments, net	1,081	[1]
Net Exposure	212
Other FE subsidiaries
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	716
Discounted Lease Payments, net	495	[1]
Net Exposure	$ 221

[1] The net present value of FirstEnergy’s consolidated sale and leaseback operating lease commitments is $1.1 billion.

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Consolidated Balance Sheets (FirstEnergy Corp.) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 109	$ 218
Receivables-
Customers, net of allowance for uncollectible accounts of $55 in 2014 and $52 in 2013	1,869	1,720
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	218	198
Materials and supplies, at average cost	740	752
Prepaid taxes	240	226
Derivatives	247	166
Accumulated deferred income taxes	375	366
Collateral	580	155
Other	199	212
Total current assets	4,577	4,013
PROPERTY, PLANT AND EQUIPMENT:
In service	44,782	44,228
Less - Accumulated provision for depreciation	13,555	13,280
Property, plant and equipment in service net of accumulated provision for depreciation	31,227	30,948
Construction work in progress	2,661	2,304
Total net property, plant and equipment	33,888	33,252
INVESTMENTS:
Nuclear plant decommissioning trusts	2,263	2,201
Other	898	903
Total other property and investments	3,161	3,104
ASSETS HELD FOR SALE	0	235
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Regulatory assets	1,798	1,854
Other	1,386	1,548
Total deferred charges and other assets	9,602	9,820
Total assets	51,228	50,424
CURRENT LIABILITIES:
Currently payable long-term debt	1,416	1,415
Short-term borrowings	3,085	3,404
Accounts payable	1,455	1,250
Accrued taxes	527	485
Accrued compensation and benefits	232	351
Derivatives	159	111
Other	863	621
Total current liabilities	7,737	7,637
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 419,837,287 shares and 418,628,559 shares outstanding as of March 31, 2014 and December 31, 2013, respectively	42	42
Other paid-in capital	9,793	9,776
Accumulated other comprehensive income	271	284
Retained earnings	2,496	2,590
Total common stockholders' equity	12,602	12,692
Noncontrolling interest	3	3
Total equity	12,605	12,695
Long-term debt and other long-term obligations	16,804	15,831
Total capitalization	29,409	28,526
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	7,028	6,968
Retirement benefits	2,713	2,689
Asset retirement obligations	1,704	1,678
Deferred gain on sale and leaseback transaction	850	858
Adverse power contract liability	255	290
Other	1,532	1,778
Total noncurrent liabilities	14,082	14,261
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
Total liabilities and capitalization	$ 51,228	$ 50,424

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Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 109	$ 218
Receivables-
Customers, net of allowance for uncollectible accounts of $13 in 2014 and $11 in 2013	1,869	1,720
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	218	198
Materials and supplies	740	752
Derivatives	247	166
Collateral	580	155
Prepayments and other	199	212
Total current assets	4,577	4,013
PROPERTY, PLANT AND EQUIPMENT:
In service	44,782	44,228
Less - Accumulated provision for depreciation	13,555	13,280
Property, plant and equipment in service net of accumulated provision for depreciation	31,227	30,948
Construction work in progress	2,661	2,304
Total net property, plant and equipment	33,888	33,252
INVESTMENTS:
Nuclear plant decommissioning trusts	2,263	2,201
Other	898	903
Total other property and investments	3,161	3,104
ASSETS HELD FOR SALE	0	235
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Other	1,386	1,548
Total deferred charges and other assets	9,602	9,820
Total assets	51,228	50,424
CURRENT LIABILITIES:
Currently payable long-term debt	1,416	1,415
Other	3,085	3,404
Accounts payable-
Accrued taxes	527	485
Derivatives	159	111
Other	863	621
Total current liabilities	7,737	7,637
Common stockholders' equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of March 31, 2014 and December 31, 2013	42	42
Accumulated other comprehensive income	271	284
Retained earnings	2,496	2,590
Total common stockholders' equity	12,602	12,692
Long-term debt and other long-term obligations	16,804	15,831
Total capitalization	29,409	28,526
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	850	858
Accumulated deferred income taxes	7,028	6,968
Asset retirement obligations	1,704	1,678
Retirement benefits	2,713	2,689
Other	1,532	1,778
Total noncurrent liabilities	14,082	14,261
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
Total liabilities and capitalization	51,228	50,424
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $13 in 2014 and $11 in 2013	583	539
Affiliated companies	369	1,036
Other, net of allowance for uncollectible accounts of $3 in 2014 and 2013	151	81
Notes receivable from affiliated companies	215	0
Materials and supplies	427	448
Derivatives	244	165
Collateral	544	136
Prepayments and other	179	109
Total current assets	2,714	2,516
PROPERTY, PLANT AND EQUIPMENT:
In service	12,796	12,472
Less - Accumulated provision for depreciation	4,857	4,755
Property, plant and equipment in service net of accumulated provision for depreciation	7,939	7,717
Construction work in progress	1,356	1,308
Total net property, plant and equipment	9,295	9,025
INVESTMENTS:
Nuclear plant decommissioning trusts	1,323	1,276
Other	11	11
Total other property and investments	1,334	1,287
ASSETS HELD FOR SALE	0	122
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	91	95
Goodwill	23	23
Property taxes	30	41
Unamortized sale and leaseback costs	197	168
Derivatives	65	53
Other	150	172
Total deferred charges and other assets	556	552
Total assets	13,899	13,502
CURRENT LIABILITIES:
Currently payable long-term debt	465	892
Affiliated companies	555	4
Other	555	4
Accounts payable-
Affiliated companies	327	765
Other	295	290
Accrued taxes	97	66
Derivatives	159	110
Other	214	197
Total current liabilities	2,112	2,755
Common stockholders' equity-
Common stock, without par value, authorized 750 shares- 7 shares outstanding as of March 31, 2014 and December 31, 2013	3,580	3,080
Accumulated other comprehensive income	62	54
Retained earnings	2,191	2,178
Total common stockholders' equity	5,833	5,312
Long-term debt and other long-term obligations	2,551	2,130
Total capitalization	8,384	7,442
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	850	858
Accumulated deferred income taxes	810	741
Asset retirement obligations	1,029	1,015
Retirement benefits	189	185
Derivatives	36	14
Other	489	492
Total noncurrent liabilities	3,403	3,305
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
Total liabilities and capitalization	13,899	13,502
Affiliated Entity [Member] | FES
CURRENT LIABILITIES:
Affiliated companies	$ 0	$ 431

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Regulatory Matters (Details) (USD $)	3 Months Ended						0 Months Ended	1 Months Ended	12 Months Ended				1 Months Ended			0 Months Ended	3 Months Ended	0 Months Ended			3 Months Ended	0 Months Ended		3 Months Ended			0 Months Ended				0 Months Ended			3 Months Ended	12 Months Ended		3 Months Ended					0 Months Ended	3 Months Ended		12 Months Ended									0 Months Ended							0 Months Ended				1 Months Ended		3 Months Ended		0 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended	3 Months Ended		0 Months Ended		0 Months Ended
	Mar. 31, 2014 entities	Mar. 31, 2013	Mar. 31, 2014 FES	Mar. 31, 2013 FES	Dec. 31, 2013 AE Supply	Dec. 31, 2013 M P	Apr. 30, 2014 MP and PE Subsequent Event	Apr. 30, 2007 FERC kv	Dec. 31, 2013 FERC	Mar. 31, 2014 FERC	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	Mar. 31, 2014 FERC PJM	Aug. 24, 2012 FERC PATH	Mar. 31, 2014 FERC PATH kv	Aug. 24, 2012 FERC PATH-Allegheny	Aug. 24, 2012 FERC Path-WV	Sep. 28, 2012 FERC Path-WV challenge	Mar. 31, 2014 FERC FES and AE Supply FTR Underfunding Complaint Minimum	Sep. 03, 2013 MARYLAND	Dec. 22, 2011 MARYLAND	Mar. 31, 2014 MARYLAND	Aug. 31, 2011 MARYLAND	Oct. 06, 2009 MARYLAND	Jun. 14, 2013 NEW JERSEY	Mar. 31, 2014 NEW JERSEY bgs component	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	Mar. 31, 2014 OHIO plan	Dec. 31, 2009 OHIO	Dec. 12, 2012 OHIO questions	Mar. 31, 2014 OHIO Year 2012 MWh	Mar. 31, 2014 OHIO Year 2013 MWh	Mar. 31, 2014 OHIO Year 2014 MWh	Mar. 31, 2014 OHIO Annually Through 2025 MWh	Mar. 31, 2014 OHIO Annually Through 2018	Oct. 10, 2013 PENNSYLVANIA proposals	Mar. 31, 2014 PENNSYLVANIA	Sep. 30, 2013 PENNSYLVANIA	Dec. 31, 2010 PENNSYLVANIA	Dec. 12, 2013 PENNSYLVANIA issues	Dec. 02, 2013 PENNSYLVANIA smart_meter	Feb. 15, 2013 PENNSYLVANIA workgroup comment	Jan. 16, 2013 PENNSYLVANIA issues Party	May 31, 2011 PENNSYLVANIA	Apr. 29, 2011 PENNSYLVANIA questions	Mar. 31, 2014 PENNSYLVANIA Pennsylvania Companies	Mar. 31, 2014 PENNSYLVANIA Year 2013	Oct. 10, 2013 PENNSYLVANIA Three Month Period	Oct. 10, 2013 PENNSYLVANIA Twelve Month Period	Oct. 10, 2013 PENNSYLVANIA Twenty-Four Month Period	Oct. 10, 2013 PENNSYLVANIA Forty-Eight Month Period	Mar. 31, 2014 PENNSYLVANIA Unfavorable Regulatory Action	Dec. 31, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Feb. 06, 2013 PENNSYLVANIA Unfavorable Regulatory Action	Apr. 21, 2014 PENNSYLVANIA Unfavorable Regulatory Action WP Subsequent Event	Mar. 06, 2014 PENNSYLVANIA Unfavorable Regulatory Action Pennsylvania Companies	Apr. 21, 2014 PENNSYLVANIA Unfavorable Regulatory Action Pennsylvania Companies Subsequent Event	Apr. 30, 2014 WEST VIRGINIA	Oct. 31, 2013 WEST VIRGINIA	Apr. 30, 2010 WEST VIRGINIA	Mar. 31, 2014 WEST VIRGINIA MW	Oct. 22, 2012 WEST VIRGINIA hearing	Apr. 30, 2014 WEST VIRGINIA MP and PE Subsequent Event	Oct. 31, 2006 California Claims Matters FERC Proceedings	Mar. 31, 2014 California Claims Matters FERC	Jan. 27, 2014 Division Of Rate Counsel NEW JERSEY JCP&L	Dec. 31, 2013 Public Utilities Commission Of Ohio OHIO	Aug. 07, 2013 Public Utilities Commission Of Ohio OHIO auctions	Jan. 27, 2014 Board Of Public Utilities NEW JERSEY JCP&L	Feb. 24, 2014 Board Of Public Utilities NEW JERSEY JCP&L	Feb. 12, 2014 Hydroelectric Power Plant Projects
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
Public Utilities, Requested Recovery of Deferred Costs, Allowed Amount																																																																												736,000,000
Public Utilities, Requested Recovery of Deferred Costs																																																																												744,000,000
Public Utilities, Requested Recovery Costs, Disallowed Amount																																																																											8,000,000
Public Utilities, Renewable Energy Auctions																																																																										1
Amortization (deferral) of regulatory assets, net	(28,000,000)	59,000,000																																																																							51,000,000
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
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%
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																																												254,000,000																					322,000,000
Regulatory Liabilities																																																																			23,000,000
Cash Consideration received in Asset Swap Transaction					1,100,000,000
Minimum reduction in Utilities reduce energy consumption																																																		1.00%			3.00%
Minimum reduction in Utilities peak demand																																																					4.50%
Maximum range of possible loss																																																										20,000,000		234,000,000
Number of parties not settled																																																	1
Number of issues not settled																																														1			1
Public Utilities, Requested Rate Increase (Decrease), Percentage							14.00%																																																									14.00%					9.30%
Public Utilities, Requested Surcharge, Amount																																																																					48,000,000
Public Utilities, Requested Rate Increase (Decrease), Total Amount																																																																					144
Energy Contract, Term																																																						3 months	12 months	24 months	48 months
Number of Requests For Proposal																																										1
Request for Proposal, Project Term																																										2 years
Loss Contingency, Damages Sought, Value																																																													11,400,000	5,100,000
Period to File Amendment to the Deployment Plan																																																														30 days
Expedited Procedural Schedule to Rule on Filing																																																														90 days
Period to Respond to Complaint																																																															20 days
Loss Contingency, Range of Possible Loss, Minimum																																																											1,000,000
Number Of Smart Meters Requested To Be Installed																																															170,000
Number Of Smart Meters Originally Proposed To Be Installed																																															60,000
Annualized base rate increase																																																																		40,000,000
Storm Restoration Deferral Period																																																																		5 years
Number of public hearings held																																																																				2
Public Utilities, Requested Rate Increase (Decrease), Amount																																																																					96,000,000
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																																									214,900,000			207,400,000
Decrease in ENEC rates																																																																		20,000,000
Noncash or Part Noncash Acquisition, Debt Assumed					73,500,000
Equity contribution from parent			500,000,000	0		527,000,000
Loans to affiliated companies, net			(215,000,000)	276,000,000		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
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
Proceeds from Divestiture of Businesses																																																																													394,000,000
Auctioned Energy Price													59
Application to Sell Power Plant Projects, Number												11
Application to Sell Power Plant Projects, Combined Power												527
Number of Exemptions Added														2
Percent of Meters to be Installed																																																				98.50%
Expected Cost of Meter Installations																																																				1,250,000,000
Directed Questions for Investigation																																				22															11
Number of Workgroups Established																																																5
Number of Comments Established																																																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																					$ 87,000,000
Resource Plan, Proposed Transfer																																																																			1,476
Compliance Filing, Hybrid Methodology, Postage Stamp Cost Allocation															50.00%
Regional Enforcement Entities	8
Requirement to File Update with FERC Showing Market-Based Rate Authority Requirements Met, Period	3 years

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Earnings Per Share of Common Stock (Tables)

3 Months Ended

Mar. 31, 2014

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:

(In millions, except per share amounts)	Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2014		2013
Income from continuing operations	$	122	$	192
Discontinued operations (Note 13)	86		4
Net income	$	208	$	196
Weighted average number of basic shares outstanding	419		418
Assumed exercise of dilutive stock options and awards(1)	1		1
Weighted average number of diluted shares outstanding	420		419
Earnings per share:
Basic earnings per share:
Income from continuing operations	$	0.29	$	0.46
Discontinued operations (Note 13)	0.21		0.01
Net earnings per basic share	$	0.50	$	0.47
Diluted earnings per share:
Income from continuing operations	$	0.29	$	0.46
Discontinued operations (Note 13)	0.20		0.01
Net earnings per diluted share	$	0.49	$	0.47

⁽¹⁾  For the three months ended March 31, 2014, 2 million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.The number of potentially dilutive securities not included in the calculation of diluted shares outstanding due to their antidilutive effect was not significant for the three months ended March 31, 2013.

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Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 284	$ 385
Other comprehensive income (loss) before reclassifications	22	15
Amounts reclassified from AOCI	(35)	(39)
Net other comprehensive income (loss)	(13)	(24)
AOCI Ending Balance	271	361
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	54	72
Other comprehensive income (loss) before reclassifications	21	14
Amounts reclassified from AOCI	(13)	(15)
Net other comprehensive income (loss)	8	(1)
AOCI Ending Balance	62	71
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(36)	(38)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	0	1
Net other comprehensive income (loss)	0	1
AOCI Ending Balance	(36)	(37)
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(1)	3
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(1)	(1)
Net other comprehensive income (loss)	(1)	(1)
AOCI Ending Balance	(2)	2
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	9	15
Other comprehensive income (loss) before reclassifications	22	15
Amounts reclassified from AOCI	(9)	(12)
Net other comprehensive income (loss)	13	3
AOCI Ending Balance	22	18
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	8	13
Other comprehensive income (loss) before reclassifications	21	14
Amounts reclassified from AOCI	(9)	(10)
Net other comprehensive income (loss)	12	4
AOCI Ending Balance	20	17
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	311	408
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(26)	(28)
Net other comprehensive income (loss)	(26)	(28)
AOCI Ending Balance	285	380
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	47	56
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(3)	(4)
Net other comprehensive income (loss)	(3)	(4)
AOCI Ending Balance	$ 44	$ 52

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Derivative Instruments

3 Months Ended

Mar. 31, 2014

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 2020.

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 less than $1 million and $2 million as of March 31, 2014 and December 31, 2013, respectively. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Approximately $9 million is expected to be amortized to income during the next twelve months.

FirstEnergy has used forward starting swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were treated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. No forward starting swap agreements accounted for as a cash flow hedge were outstanding as of March 31, 2014 or December 31, 2013. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $57 million and $59 million as of March 31, 2014 and December 31, 2013, respectively. Based on current estimates, approximately $9 million will be amortized to interest expense during the next twelve months.

In connection with certain debt redemptions, FirstEnergy recorded interest expense related to deferred losses on terminated interest rate swaps of approximately $2 million for the three months ended March 31, 2013.

As of March 31, 2014 and December 31, 2013, no commodity or interest rate derivatives were designated as cash flow hedges.

Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three months ended March 31, 2014 and 2013.

Fair Value Hedges

FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. These derivative instruments were treated as fair value hedges of fixed-rate, long-term debt issues, protecting against the risk of changes in the fair value of fixed-rate debt instruments due to lower interest rates. As of March 31, 2014 and December 31, 2013, 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 $41 million and $44 million as of March 31, 2014 and December 31, 2013, respectively. Based on current estimates, approximately $11 million will be amortized to interest expense during the next twelve months. Reclassifications from long-term debt into interest expense totaled approximately $3 million and $6 million during the three months ended March 31, 2014 and 2013, respectively.

As of March 31, 2014 and December 31, 2013, no commodity or interest rate derivatives were designated as fair value hedges.

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 March 31, 2014, FirstEnergy’s net asset position under commodity derivative contracts was $117 million, which related to FES positions. Under these commodity derivative contracts, FES posted $85 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $11 million of additional collateral if the credit rating for its debt were to fall below investment grade.

Based on commodity derivative contracts held as of March 31, 2014, an adverse change of 10% in commodity prices would decrease net income by approximately $40 million during the next twelve months.

NUGs

As of March 31, 2014, FirstEnergy's net liability position under NUG contracts was $185 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 maintained two LCAPP contracts, which were financially settled agreements that allowed 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 expected 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 were considered derivative liabilities with a corresponding regulatory asset. Since the LCAPP contracts were subject to regulatory accounting, changes in their fair value did not impact earnings. On October 11, 2013, the U.S. District Court for the District of New Jersey declared that the LCAPP was 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. The parties filed an appeal with the U.S. Court of Appeals for the Third Circuit and briefing by the parties was completed by March 5, 2014. Consistent with the provisions of the LCAPP contracts, the U.S. District Court's ruling was a termination event. During the fourth quarter of 2013, JCP&L issued termination notices to the counterparties and reversed the derivative liability and corresponding regulatory asset on its Consolidated Balance Sheet.

FTRs

As of March 31, 2014, FirstEnergy's and FES's net liability position under FTRs was $1 million and $3 million, respectively, and FES posted $4 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
	March 31, 2014		December 31, 2013			March 31, 2014			December 31, 2013
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	240	$	162	Commodity Contracts	$	(154	)	$	(102	)
FTRs	7		4		FTRs	(5		)	(9		)
	247		166			(159		)	(111		)
					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs	(188		)	(222		)
Deferred Charges and Other Assets - Other					Noncurrent Liabilities - Other
Commodity Contracts	64		53		Commodity Contracts	(33		)	(11		)
NUGs	3		20		FTRs	(3		)	(3		)
	67		73			(224		)	(236		)
Derivative Assets	$	314	$	239	Derivative Liabilities	$	(383	)	$	(347	)

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
March 31, 2014	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	304		$	(182	)	$	(4	)	$	118
FTRs	7			(7		)	—			—
NUG contracts	3			—			—			3
	$	314		$	(189	)	$	(4	)	$	121
Derivative Liabilities
Commodity contracts	$	(187	)	$	182		$	2		$	(3	)
FTRs	(8		)	7			1			—
NUG contracts	(188		)	—			—			(188		)
	$	(383	)	$	189		$	3		$	(191	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2013	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	215		$	(106	)	$	(9	)	$	100
FTRs	4			(4		)	—			—
NUG contracts	20			—			—			20
	$	239		$	(110	)	$	(9	)	$	120
Derivative Liabilities
Commodity contracts	$	(113	)	$	106		$	7		$	—
FTRs	(12		)	4			5			(3		)
NUG contracts	(222		)	—			—			(222		)
	$	(347	)	$	110		$	12		$	(225	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2014:

	Purchases	Sales	Net	Units
	(In millions)
Power Contracts	41	38	3	MWH
FTRs	26	—	26	MWH
NUGs	7	—	7	MWH
Natural Gas	65	8	57	mmBTU

The effect of derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2014 and 2013, are summarized in the following tables:

	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2014
Unrealized Gain Recognized in:
Other Operating Expense (1)		$12			$5			$17
Realized Gain (Loss) Reclassified to:
Revenues (2)		($13	)		$52			$39
Purchased Power Expense (3)	436			—			436
Other Operating Expense (4)	—			(7		)	(7		)
Fuel Expense	9			—			9
(1) Includes $12 million for commodity contracts and $5 million for FTRs associated with FES.
(2) Represents losses on structured financial contracts. Includes ($13) million for commodity contracts and $51 million for FTRs associated with FES.
(3) Realized losses on financially settled wholesale sales contracts of $321 million resulting from higher market prices were netted in purchased power. Includes $436 million for commodity contracts associated with FES.
(4) Includes ($7) million for FTRs associated with FES.
2013
Unrealized Loss Recognized in:
Other Operating Expense (5)		($5	)		($2	)		($7	)
Realized Gain (Loss) Reclassified to:
Revenues (6)		$10			$7			$17
Purchased Power Expense (7)	(11		)	—			(11		)
Other Operating Expense (8)	—			(9		)	(9		)
Fuel Expense	(1		)	—			(1		)
(5) Includes ($5) million for commodity contracts and ($1) million for FTRs associated with FES.
(6) Includes $10 million for commodity contracts and $6 million for FTRs associated with FES.
(7) Includes ($11) million for commodity contracts associated with FES.
(8) Includes ($8) million for FTRs associated with FES.

The unrealized and realized gains (losses) on FirstEnergy’s derivative instruments subject to regulatory accounting during the three months ended March 31, 2014 and 2013, are summarized in the following tables:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP(1)			Regulated FTRs			Total
	(In millions)
2014
Unrealized Gain on Derivative Instrument	$	27		$	—		$	4		$	31
Realized Loss on Derivative Instrument	(10		)	—			(1		)	(11		)
2013
Unrealized Gain (Loss) on Derivative Instrument	$	18		$	(2	)	$	—		$	16
Realized Gain (Loss) on Derivative Instrument	23			—			(1		)	22

⁽¹⁾  During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.

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 ended March 31, 2014 and 2013:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			LCAPP(1)			Regulated FTRs			Total
	(In millions)
Outstanding net liability as of January 1, 2014	$	(202	)	$	—		$	—		$	(202	)
Additions/Change in value of existing contracts	27			—			4			31
Settled contracts	(10		)	—			(1		)	(11		)
Outstanding net liability as of March 31, 2014	$	(185	)	$	—		$	3		$	(182	)
Outstanding net liability as of January 1, 2013	$	(254	)	$	(144	)	$	—		$	(398	)
Additions/Change in value of existing contracts	18			(2		)	—			16
Settled contracts	23			—			(1		)	22
Outstanding net liability as of March 31, 2013	$	(213	)	$	(146	)	$	(1	)	$	(360	)

⁽¹⁾  During the fourth quarter of 2013, all LCAPP contracts were terminated as discussed above.