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, 2016

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 MARCH 31, 2016
FirstEnergy Corp., $0.10 par value	424,712,431
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 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 web site and recognize FirstEnergy’s 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 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 web site, Twitter® handle or Facebook® page, 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,” "forecast," "target," "will," "intend," “believe,” "project," “estimate," "plan" 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 successfully implement our sales strategy for the CES segment.

• The accomplishment of our regulatory and operational goals in connection with our transmission investment plan, including, but not limited to, the proposed transmission asset transfer to MAIT, and the effectiveness of our strategy to reflect a more regulated business profile.

• Changes in assumptions regarding economic conditions within our territories, assessment of the reliability of our transmission system, or the availability of capital or other resources supporting identified transmission investment opportunities.

• The impact of the regulatory process on the pending matters at the federal level and in the various states in which we do business including, but not limited to, matters related to rates and the ESP IV in Ohio, specifically related to a complaint filed at FERC against FES and the Ohio Companies that request FERC review the ESP IV PPA under Section 205 of the FPA, and other future complaints or challenges that could impact the ESP IV and the ESP IV PPA.

• The impact of the federal regulatory process on FERC-regulated entities and transactions, in particular FERC regulation of wholesale energy and capacity markets, including PJM markets and FERC-jurisdictional wholesale transactions; FERC regulation of cost-of-service rates, including FERC Opinion No. 531's revised ROE methodology for FERC-jurisdictional wholesale generation and transmission utility service; and FERC’s compliance and enforcement activity, including compliance and enforcement activity related to NERC’s mandatory reliability standards.

• 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 a polar vortex or other significant weather events, and all associated regulatory events or actions.

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

• 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, the effects of the EPA's CPP, CCR, CSAPR and MATS programs, including our estimated costs of compliance, CWA waste water effluent limitations for power plants, and CWA 316(b) water intake regulation.

• 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 initiatives or rulemakings 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 as it relates to the reliability of the transmission grid, the timing thereof.

• The impact of other future changes to the operational status or availability of our generating units and any capacity performance charges associated with unit unavailability.

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

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

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

• The impact of labor disruptions by our unionized workforce.

• 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 continue to reduce costs and to successfully execute our financial plans designed to improve our credit metrics and strengthen our balance sheet through, among other actions, our cash flow improvement plan and other proposed capital raising 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/or 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 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/or 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/or our major industrial and commercial customers, and other counterparties with which we do business, including fuel suppliers.

• 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 associated with cyber-attacks and other disruptions to our information technology system that may compromise our generation, transmission and/or distribution services and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information regarding our business, employees, shareholders, customers, suppliers, business partners and other individuals in our data centers and on our networks.

• 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 factors should not be construed as exhaustive and should be read in conjunction with the other cautionary statements and risks that are included in FirstEnergy's and FES' filings with the SEC, including but not limited to the most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on FirstEnergy's business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. The registrants expressly disclaim any current intention to update, except as required by law, any forward-looking statements contained herein as a result of new information, future events or otherwise.

TABLE OF CONTENTS
	Page
Part I. Financial Information
Glossary of Terms	ii
Item 1. Financial Statements
FirstEnergy Corp.
Consolidated Statements of Income	1
Consolidated Statements of Comprehensive Income	2
Consolidated Balance Sheets	3
Consolidated Statements of Cash Flows	4
FirstEnergy Solutions Corp.
Consolidated Statements of Income (Loss) and Comprehensive Income (Loss)	5
Consolidated Balance Sheets	6
Consolidated Statements of Cash Flows	7
Combined Notes To Consolidated Financial Statements	8
Item 2. Management's Discussion and Analysis of Registrant and Subsidiaries	48
FirstEnergy Corp. Management's Discussion and Analysis of Financial Condition and Results of Operations	48
Management's Narrative Analysis of Results of Operations
FirstEnergy Solutions Corp.	82
Item 3. Quantitative and Qualitative Disclosures About Market Risk	85
Item 4. Controls and Procedures	85
Part II. Other Information
Item 1. Legal Proceedings	85
Item 1A. Risk Factors	86
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	86
Item 3. Defaults Upon Senior Securities	86
Item 4. Mine Safety Disclosures	86
Item 5. Other Information	86
Item 6. Exhibits	87

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.
AESC	Allegheny Energy Service Corporation, a subsidiary of FirstEnergy Corp.
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC	Allegheny Generating Company, a generation subsidiary of AE Supply and equity method investee of MP.
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
CES	Competitive Energy Services, a reportable operating segment of FirstEnergy
FE	FirstEnergy Corp., a public utility holding company
FENOC	FirstEnergy Nuclear Operating Company, which operates nuclear generating facilities
FES	FirstEnergy Solutions Corp., which provides energy-related products and services
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET	FirstEnergy Transmission, LLC, formerly known as Allegheny Energy Transmission, LLC which is the parent of ATSI, TrAIL and MAIT, 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 wholly owned 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
MAIT	Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, formed to own and operate transmission facilities
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 and West Virginia 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:
AAA	American Arbitration Association
AEP	American Electric Power Company, Inc.
AFS	Available-for-sale
AFUDC	Allowance for Funds Used During Construction
ALJ	Administrative Law Judge
AOCI	Accumulated Other Comprehensive Income
Apple®	Apple®, iPad® and iPhone® are registered trademarks of Apple Inc.
ARO	Asset Retirement Obligation

ii

GLOSSARY OF TERMS, Continued
ARR	Auction Revenue Right
ASU	Accounting Standards Update
BGS	Basic Generation Service
BNSF	BNSF Railway Company
BRA	PJM RPM Base Residual Auction
CAA	Clean Air Act
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
CPP	EPA's Clean Power Plan
CSAPR	Cross-State Air Pollution Rule
CSX	CSX Transportation, Inc.
CTA	Consolidated Tax Adjustment
CWA	Clean Water Act
DCR	Delivery Capital Recovery
DR	Demand Response
DSIC	Distribution System Improvement Charge
DSP	Default Service Plan
EDC	Electric Distribution Company
EE&C	Energy Efficiency and Conservation
EGS	Electric Generation Supplier
ELPC	Environmental Law & Policy Center
EmPOWER Maryland	EmPower Maryland Energy Efficiency Act
ENEC	Expanded Net Energy Cost
EPA	United States Environmental Protection Agency
ERO	Electric Reliability Organization
ESP	Electric Security Plan
ESP IV PPA	Unit Power Agreement entered into on April 1, 2016 by and between the Ohio Companies and FES
ESP IV PPA Facilities	100% of the output of the W.H. Sammis plant, 100% of the output of the Davis-Besse Nuclear Power Station and FES' 4.85% entitlement in OVEC
Facebook®	Facebook is a registered trademark of Facebook, Inc.
FASB	Financial Accounting Standards Board
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.
IRS	Internal Revenue Service
ISO	Independent System Operator
kV	Kilovolt
KWH	Kilowatt-hour
LMP	Locational Marginal Price
LOC	Letter of Credit
LSE	Load Serving Entity
LTIIPs	Long-Term Infrastructure Improvement Plans

iii

GLOSSARY OF TERMS, Continued
MATS	Mercury and Air Toxics Standards
MDPSC	Maryland Public Service Commission
MISO	Midcontinent Independent System Operator, Inc.
MLP	Master Limited Partnership
mmBTU	One Million British Thermal Units
Moody’s	Moody’s Investors Service, Inc.
MOPR	Minimum Offer Price Rule
MVP	Multi-Value Project
MW	Megawatt
MWH	Megawatt-hour
NAAQS	National Ambient Air Quality Standards
NDT	Nuclear Decommissioning Trust
NERC	North American Electric Reliability Corporation
Ninth Circuit	United States Court of Appeals for the Ninth Circuit
NJBPU	New Jersey Board of Public Utilities
NMB	Non-Market Based
NOL	Net Operating Loss
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, Inc.
NYPSC	New York State Public Service Commission
OCC	Ohio Consumers' Counsel
OPEB	Other Post-Employment Benefits
OTTI	Other Than Temporary Impairments
OVEC	Ohio Valley Electric Corporation
PA DEP	Pennsylvania Department of Environmental Protection
PCRB	Pollution Control Revenue Bond
PJM	PJM Interconnection, L.L.C.
PJM Region	The aggregate of the zones within PJM
PJM Tariff	PJM Open Access Transmission Tariff
PM	Particulate Matter
POLR	Provider of Last Resort
POR	Purchase of Receivables
PPA	Purchase Power Agreement
PPB	Parts Per Billion
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
ROE	Return on Equity
RPM	Reliability Pricing Model

iv

GLOSSARY OF TERMS, Continued
RRS	Retail Rate Stability
RSS	Rich Site Summary
RTEP	Regional Transmission Expansion Plan
RTO	Regional Transmission Organization
S&P	Standard & Poor’s Ratings Service
SB221	Amended Substitute Senate Bill No. 221
SB310	Substitute Senate Bill No. 310
SBC	Societal Benefits Charge
SEC	United States Securities and Exchange Commission
SEC Regulation FD	SEC Regulation Fair Disclosure
Seventh Circuit	United States Court of Appeals for the Seventh Circuit
SIP	State Implementation Plan(s) Under the Clean Air Act
SO2	Sulfur Dioxide
SOS	Standard Offer Service
SPE	Special Purpose Entity
SREC	Solar Renewable Energy Credit
SSO	Standard Service Offer
TDS	Total Dissolved Solid
Third Circuit	United States Court of Appeals for the Third Circuit
TMI-2	Three Mile Island Unit 2
TO	Transmission Owner
TTS	Temporary Transaction Surcharge
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
VIE	Variable Interest Entity
VSCC	Virginia State Corporation Commission
WVDEP	West Virginia Department of Environmental Protection
WVPSC	Public Service Commission of West Virginia

v

PART I. FINANCIAL INFORMATION

ITEM I.         Financial Statements

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	For the Three Months Ended March 31
(In millions, except per share amounts)	2016			2015
REVENUES:
Regulated Distribution	$	2,521		$	2,562
Regulated Transmission	275			238
Unregulated businesses	1,073			1,097
Total revenues*	3,869			3,897
OPERATING EXPENSES:
Fuel	381			513
Purchased power	1,124			1,113
Other operating expenses	918			1,057
Provision for depreciation	329			319
Amortization of regulatory assets, net	61			32
General taxes	280			269
Total operating expenses	3,093			3,303
OPERATING INCOME	776			594
OTHER INCOME (EXPENSE):
Investment income	28			17
Interest expense	(288		)	(279		)
Capitalized financing costs	25			34
Total other expense	(235		)	(228		)
INCOME BEFORE INCOME TAXES	541			366
INCOME TAXES	213			144
NET INCOME	$	328		$	222
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$	0.78		$	0.53
Diluted	$	0.77		$	0.53
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic	424			421
Diluted	426			423
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK	$	0.72		$	0.72

* Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

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

1

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

	For the Three Months Ended March 31
(In millions)	2016			2015
NET INCOME	$	328		$	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(18		)	(31		)
Amortized losses on derivative hedges	2			1
Change in unrealized gains on available-for-sale securities	28			4
Other comprehensive income (loss)	12			(26		)
Income taxes (benefits) on other comprehensive income (loss)	4			(10		)
Other comprehensive income (loss), net of tax	8			(16		)
COMPREHENSIVE INCOME	$	336		$	206

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, 2016		December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	146	$	131
Receivables-
Customers, net of allowance for uncollectible accounts of $64 in 2016 and $69 in 2015	1,432		1,415
Other, net of allowance for uncollectible accounts of $5 in 2016 and 2015	162		180
Materials and supplies	781		785
Prepaid taxes	267		135
Derivatives	207		157
Collateral	80		70
Other	155		167
	3,230		3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371		49,952
Less — Accumulated provision for depreciation	15,421		15,160
	34,950		34,792
Construction work in progress	2,694		2,422
	37,644		37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360		2,282
Other	526		506
	2,886		2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418		6,418
Regulatory assets	1,279		1,348
Other	1,238		1,286
	8,935		9,052
	$	52,695	$	52,094
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	1,355	$	1,166
Short-term borrowings	2,125		1,708
Accounts payable	1,000		1,075
Accrued taxes	513		519
Accrued compensation and benefits	309		334
Derivatives	117		106
Other	970		694
	6,389		5,602
CAPITALIZATION:
Common stockholders’ equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 424,712,431 and 423,560,397 shares outstanding as of March 31, 2016 and December 31, 2015, respectively	42		42
Other paid-in capital	9,963		9,952
Accumulated other comprehensive income	179		171
Retained earnings	2,279		2,256
Total common stockholders’ equity	12,463		12,421
Noncontrolling interest	1		1
Total equity	12,464		12,422
Long-term debt and other long-term obligations	18,878		19,099
	31,342		31,521
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,996		6,773
Retirement benefits	4,135		4,245
Asset retirement obligations	1,427		1,410
Deferred gain on sale and leaseback transaction	782		791
Adverse power contract liability	194		197
Other	1,430		1,555
	14,964		14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	52,695	$	52,094

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)

	For the Three Months Ended March 31
(In millions)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income	$	328		$	222
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	455			425
Deferred purchased power and other costs	(10		)	(31		)
Deferred income taxes and investment tax credits, net	206			127
Deferred costs on sale leaseback transaction, net	12			12
Retirement benefits	16			(4		)
Pension trust contributions	(160		)	(143		)
Commodity derivative transactions, net (Note 8)	(64		)	2
Changes in current assets and liabilities-
Receivables	1			(97		)
Materials and supplies	4			30
Prepayments and other current assets	(82		)	(116		)
Accounts payable	25			(177		)
Accrued taxes	(110		)	(80		)
Accrued interest	47			44
Accrued compensation and benefits	(102		)	(80		)
Other current liabilities	19			11
Cash collateral, net	(6		)	(15		)
Other	59			63
Net cash provided from operating activities	638			193
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	425			760
Redemptions and Repayments-
Long-term debt	(31		)	(48		)
Common stock dividend payments	(152		)	(152		)
Net cash provided from financing activities	242			560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698		)	(668		)
Nuclear fuel	(149		)	(60		)
Sales of investment securities held in trusts	465			371
Purchases of investment securities held in trusts	(488		)	(394		)
Cash investments	30			21
Asset removal costs	(34		)	(28		)
Other	9			10
Net cash used for investing activities	(865		)	(748		)
Net change in cash and cash equivalents	15			5
Cash and cash equivalents at beginning of period	131			85
Cash and cash equivalents at end of period	$	146		$	90

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

4

FIRSTENERGY SOLUTIONS CORP.

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

(Unaudited)

	For the Three Months Ended March 31
(In millions)	2016			2015
STATEMENTS OF INCOME (LOSS)
REVENUES:
Electric sales to non-affiliates	$	1,007		$	1,075
Electric sales to affiliates	147			255
Other	45			47
Total revenues	1,199			1,377
OPERATING EXPENSES:
Fuel	165			230
Purchased power from affiliates	82			70
Purchased power from non-affiliates	377			543
Other operating expenses	240			413
Provision for depreciation	83			80
General taxes	26			29
Total operating expenses	973			1,365
OPERATING INCOME	226			12
OTHER INCOME (EXPENSE):
Investment income	15			13
Interest expense — affiliates	(2		)	(2		)
Interest expense — other	(36		)	(37		)
Capitalized interest	10			9
Total other expense	(13		)	(17		)
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)	213			(5		)
INCOME TAXES (BENEFITS)	82			(2		)
NET INCOME (LOSS)	$	131		$	(3	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	131		$	(3	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(4		)	(4		)
Amortized gains on derivative hedges	—			(1		)
Change in unrealized gain on available-for-sale securities	23			3
Other comprehensive income (loss)	19			(2		)
Income taxes (benefits) on other comprehensive income (loss)	7			(1		)
Other comprehensive income (loss), net of tax	12			(1		)
COMPREHENSIVE INCOME (LOSS)	$	143		$	(4	)

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, 2016		December 31, 2015
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2	$	2
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2016 and 2015	229		275
Affiliated companies	447		451
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	107		59
Notes receivable from affiliated companies	—		11
Materials and supplies	446		470
Derivatives	207		154
Collateral	80		70
Prepayments and other	80		66
	1,598		1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,376		14,311
Less — Accumulated provision for depreciation	5,874		5,765
	8,502		8,546
Construction work in progress	1,273		1,157
	9,775		9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372		1,327
Other	10		10
	1,382		1,337
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	57		61
Goodwill	23		23
Property taxes	30		40
Derivatives	89		79
Other	385		367
	584		570
	$	13,339	$	13,168
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	549	$	512
Short-term borrowings-
Affiliated companies	49		—
Other	—		8
Accounts payable-
Affiliated companies	362		542
Other	116		139
Accrued taxes	71		76
Derivatives	115		104
Other	241		181
	1,503		1,562
CAPITALIZATION:
Common stockholder's equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2016 and December 31, 2015	3,614		3,613
Accumulated other comprehensive income	58		46
Retained earnings	2,077		1,946
Total common stockholder's equity	5,749		5,605
Long-term debt and other long-term obligations	2,480		2,510
	8,229		8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782		791
Accumulated deferred income taxes	722		600
Retirement benefits	339		332
Asset retirement obligations	838		831
Derivatives	21		38
Other	905		899
	3,607		3,491
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	13,339	$	13,168

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)

	For the Three Months Ended March 31
(In millions)	2016			2015
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income (loss)	$	131		$	(3	)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel and customer intangible asset amortization	138			144
Deferred costs on sale and leaseback transaction, net	12			12
Deferred income taxes and investment tax credits, net	113			34
Investment impairments	8			6
Commodity derivative transactions, net (Note 8)	(64		)	1
Changes in current assets and liabilities-
Receivables	2			1
Materials and supplies	24			21
Prepayments and other current assets	(12		)	(18		)
Accounts payable	(103		)	(75		)
Accrued taxes	(15		)	(24		)
Accrued compensation and benefits	(11		)	(9		)
Other current liabilities	18			8
Cash collateral, net	(10		)	12
Other	(3		)	(5		)
Net cash provided from operating activities	228			105
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Short-term borrowings, net	49			150
Redemptions and repayments-
Long-term debt	—			(17		)
Other	(2		)	(2		)
Net cash provided from financing activities	47			131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(143		)	(119		)
Nuclear fuel	(149		)	(60		)
Sales of investment securities held in trusts	138			189
Purchases of investment securities held in trusts	(151		)	(202		)
Cash investments	10			—
Loans to affiliated companies, net	11			(44		)
Other	9			—
Net cash used for investing activities	(275		)	(236		)
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

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	10
3	Pension and Other Postemployment Benefits	11
4	Accumulated Other Comprehensive Income	12
5	Income Taxes	15
6	Variable Interest Entities	15
7	Fair Value Measurements	16
8	Derivative Instruments	22
9	Regulatory Matters	27
10	Commitments, Guarantees and Contingencies	34
11	Supplemental Guarantor Information	39
12	Segment Information	46

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. FE’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, FET and its principal subsidiaries (ATSI and TrAIL), and AESC. In addition, FE holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and Allegheny Ventures, Inc.

FirstEnergy and its subsidiaries are principally involved in the generation, transmission, and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving six million customers in the Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and two regional transmission operation centers.

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, 2015. These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES.

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 necessarily 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 as appropriate. 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 do not have a controlling financial interest, 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 of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.

For the three months ended March 31, 2016 and 2015, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $8 million and $16 million, respectively, of allowance for equity funds used during construction and $17 million and $18 million, respectively, of capitalized interest.

New Accounting Pronouncements

In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded.In August 2015, the FASB issued a final ASU deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date). In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)", clarifying the principal versus agent implementation guidance in the following areas: unit of account at which the principal/agent determination is made; applying the control principle to certain types of transactions and the control principle and principal/agent indicators.In April 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, clarifying the identification of performance obligations and the licensing implementation guidance.The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards.

In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated.A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments

9

retrospectively. FirstEnergy's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries. See Note 6, Variable Interest Entities, for additional information.

In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified$93 million and $17 millionof debt issuance costs included in Deferred Charges and Other Assets to Long-term Debt and Other Long-term Obligations. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset.

In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets.In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required.The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

Additionally, in March of 2016, the FASB issued the following ASUs:

• ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”,

• ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and

• ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”.

FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

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.

10

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

(In millions, except per share amounts)	For the Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2016		2015
Net income	$	328	$	222
Weighted average number of basic shares outstanding	424		421
Assumed exercise of dilutive stock options and awards(1)	2		2
Weighted average number of diluted shares outstanding	426		423
Basic earnings per share of common stock	$	0.78	$	0.53
Diluted earnings per share of common stock	$	0.77	$	0.53

⁽¹⁾  For both the three months ended March 31, 2016 and March 31, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

3. PENSION AND OTHER POSTEMPLOYMENT BENEFITS

In 2016, FirstEnergy has minimum required funding obligations of$381 millionto its qualified pension plan, of which$160 millionhas been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof, depending on, among other things, market conditions.

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

Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended March 31	2016			2015			2016			2015
	(In millions)
Service costs	$	48		$	48		$	1		$	1
Interest costs	100			96			7			7
Expected return on plan assets	(97		)	(111		)	(8		)	(8		)
Amortization of prior service costs (credits)	2			2			(20		)	(33		)
Net periodic costs (credits)	$	53		$	35		$	(20	)	$	(33	)

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

	Pension				OPEB
	2016		2015		2016			2015
	(In millions)
For the Three Months Ended March 31	$	6	$	4	$	(4	)	$	(5	)

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

Net Periodic Benefit Expense (Credit)	Pension				OPEB
For the Three Months Ended March 31	2016		2015		2016			2015
	(In millions)
FirstEnergy	$	37	$	25	$	(15	)	$	(23	)
FES	6		4		(4		)	(4		)

11

4. ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, in the three months ended March 31, 2016 and 2015, for FirstEnergy are included 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, 2016	$	(33	)	$	18		$	186		$	171
Other comprehensive income before reclassifications	—			41			—			41
Amounts reclassified from AOCI	2			(13		)	(18		)	(29		)
Other comprehensive income (loss)	2			28			(18		)	12
Income tax (benefits) on other comprehensive income (loss)	1			10			(7		)	4
Other comprehensive income (loss), net of tax	1			18			(11		)	8
AOCI Balance as of March 31, 2016	$	(32	)	$	36		$	175		$	179
AOCI Balance as of January 1, 2015	$	(37	)	$	25		$	258		$	246
Other comprehensive income before reclassifications	—			14			—			14
Amounts reclassified from AOCI	1			(10		)	(31		)	(40		)
Other comprehensive income (loss)	1			4			(31		)	(26		)
Income tax (benefits) on other comprehensive income (loss)	—			1			(11		)	(10		)
Other comprehensive income (loss), net of tax	1			3			(20		)	(16		)
AOCI Balance as of March 31, 2015	$	(36	)	$	28		$	238		$	230

The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2016 and 2015:

12

		For the Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (2)		2016			2015
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts		$	—		$	(1	)	Other operating expenses
Long-term debt		2			2			Interest expense
		2			1			Total before taxes
		(1		)	—			Income taxes
		$	1		$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities		$	(13	)	$	(10	)	Investment income
		5			4			Income taxes
		$	(8	)	$	(6	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs		$	(18	)	$	(31	)	(1)
		7			11			Income taxes
		$	(11	)	$	(20	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.

The changes in AOCI, net of tax, in the three months ended March 31, 2016 and 2015, for FES are included in the following tables:

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, 2016	$	(9	)	$	16		$	39		$	46
Other comprehensive income before reclassifications	—			36			—			36
Amounts reclassified from AOCI	—			(13		)	(4		)	(17		)
Other comprehensive income (loss)	—			23			(4		)	19
Income tax (benefits) on other comprehensive income (loss)	—			9			(2		)	7
Other comprehensive income (loss), net of tax	—			14			(2		)	12
AOCI Balance as of March 31, 2016	$	(9	)	$	30		$	37		$	58
AOCI Balance as of January 1, 2015	$	(7	)	$	21		$	43		$	57
Other comprehensive income before reclassifications	—			13			—			13
Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
Other comprehensive income (loss)	(1		)	3			(4		)	(2		)
Income tax (benefits) on other comprehensive income (loss)	—			—			(1		)	(1		)
Other comprehensive income (loss), net of tax	(1		)	3			(3		)	(1		)
AOCI Balance as of March 31, 2015	$	(8	)	$	24		$	40		$	56

The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2016 and 2015:

13

		For the Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income (Loss)
Reclassifications from AOCI (2)		2016			2015
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts		$	—		$	(1	)	Other operating expenses
		—			—			Income taxes (benefits)
		$	—		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities		$	(13	)	$	(10	)	Investment income
		5			4			Income taxes (benefits)
		$	(8	)	$	(6	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs		$	(4	)	$	(4	)	(1)
		2			1			Income taxes (benefits)
		$	(2	)	$	(3	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

14

5. INCOME TAXES

FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2016 and 2015. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period.

FirstEnergy’s effective tax rate from continuing operations for the three months ended March 31, 2016 and 2015 was 39.4% and 39.3%, respectively. FES’ effective tax rate from continuing operations for the three months ended March 31, 2016 and 2015 was 38.5% and 40.0%, respectively.

During the three months ended March 31, 2016, FirstEnergy recorded unrecognized tax benefits of $69 million primarily related to protective refund claims filed with the state of Pennsylvania as a result of a recent ruling by the Commonwealth Court citing the state’s NOL carryover limitation violated the uniformity clause and was unconstitutional. The state of Pennsylvania has appealed this ruling to the Pennsylvania Supreme Court.

As of March 31, 2016, it is reasonably possible that approximately $54 million of unrecognized tax benefits may be resolved within the next twelve months as a result of the statute of limitations expiring and an expected decision at the appeals level with respect to certain claims, of which approximately $16 million would affect FirstEnergy's effective tax rate.

In February 2016, the IRS completed its examination of FirstEnergy’s 2014 federal income tax return and issued a full acceptance letter with no adjustments.

6. VARIABLE INTEREST ENTITIES

FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) 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.

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 categories based on similar risk characteristics and significance.

Consolidated VIEs

VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements):

• PNBV Trust - PNBV, a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties.

• Ohio Securitization- In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2016 and December 31, 2015, $350 million and $362 million of the phase-in recovery bonds were outstanding, respectively.

• JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of March 31, 2016 and December 31, 2015, $118 million and $128 million of the transition bonds were outstanding, respectively.

• MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West

Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of March 31, 2016 and December 31, 2015, $419 million and $429 million of the environmental control bonds were outstanding, respectively.

Unconsolidated VIEs

FirstEnergy is not the primary beneficiary of the following VIEs:

• Global Holding - 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 with coal sales in U.S. and international markets. 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.

As discussed in Note 10, Commitments, Guarantees and Contingencies, FE is the guarantor under Global Holding's $300 million term loan facility. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

• 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 FE 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 PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting.

• 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 14 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 one of these NUG entities, it does not have a variable interest in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; 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 during the three months ended March 31, 2016 and 2015 were $31 million.

• Sale and Leaseback Transactions - 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. 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. As of March 31, 2016, FirstEnergy's leasehold interest was3.75%of Perry Unit 1,93.83%of Bruce Mansfield Unit 1 and2.60%of Beaver Valley Unit 2.

On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at Perry Unit 1 and Beaver Valley Unit 2.

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, 2016:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(In millions)
FirstEnergy	$	1,228	$	967	$	261
FES	1,171		949		222

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7. FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy 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 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 PJM 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 PJM 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, 2016, from those used as of December 31, 2015. 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, 2016. 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, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,264		$	—		$	1,264		$	—		$	1,245		$	—		$	1,245
Derivative assets - commodity contracts	3			290			—			293			4			224			—			228
Derivative assets - FTRs	—			—			3			3			—			—			8			8
Derivative assets - NUG contracts(1)	—			—			1			1			—			—			1			1
Equity securities(2)	628			—			—			628			576			—			—			576
Foreign government debt securities	—			73			—			73			—			75			—			75
U.S. government debt securities	—			188			—			188			—			180			—			180
U.S. state debt securities	—			245			—			245			—			246			—			246
Other(3)	146			232			—			378			105			212			—			317
Total assets	$	777		$	2,292		$	4		$	3,073		$	685		$	2,182		$	9		$	2,876
Liabilities
Derivative liabilities - commodity contracts	$	(7	)	$	(122	)	$	—		$	(129	)	$	(9	)	$	(122	)	$	—		$	(131	)
Derivative liabilities - FTRs	—			—			(9		)	(9		)	—			—			(13		)	(13		)
Derivative liabilities - NUG contracts(1)	—			—			(136		)	(136		)	—			—			(137		)	(137		)
Total liabilities	$	(7	)	$	(122	)	$	(145	)	$	(274	)	$	(9	)	$	(122	)	$	(150	)	$	(281	)
Net assets (liabilities)(4)	$	770		$	2,170		$	(141	)	$	2,799		$	676		$	2,060		$	(141	)	$	2,595

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

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽⁴⁾  Excludes $(6) million and $7 million as of March 31, 2016 and December 31, 2015, 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 and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2016 and December 31, 2015:

	NUG Contracts(1)									FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2015 Balance	$	2		$	(153	)	$	(151	)	$	39		$	(14	)	$	25
Unrealized gain (loss)	2			(49		)	(47		)	(5		)	(7		)	(12		)
Purchases	—			—			—			22			(11		)	11
Settlements	(3		)	65			62			(48		)	19			(29		)
December 31, 2015 Balance	$	1		$	(137	)	$	(136	)	$	8		$	(13	)	$	(5	)
Unrealized loss	—			(12		)	(12		)	—			(1		)	(1		)
Settlements	—			13			13			(5		)	5			—
March 31, 2016 Balance	$	1		$	(136	)	$	(135	)	$	3		$	(9	)	$	(6	)

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

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, 2016:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(6	)	Model	RTO auction clearing prices	($4.60) to $3.70	$0.60	Dollars/MWH
NUG Contracts	$	(135	)	Model	Generation	400 to 3,651,000	777,000	MWH
					Regional electricity prices	$37.30 to $45.60	$39.60	Dollars/MWH

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FES
Recurring Fair Value Measurements	March 31, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	715		$	—		$	715		$	—		$	678		$	—		$	678
Derivative assets - commodity contracts	3			290			—			293			4			224			—			228
Derivative assets - FTRs	—			—			3			3			—			—			5			5
Equity securities(1)	408			—			—			408			378			—			—			378
Foreign government debt securities	—			58			—			58			—			59			—			59
U.S. government debt securities	—			25			—			25			—			23			—			23
U.S. state debt securities	—			4			—			4			—			4			—			4
Other(2)	—			170			—			170			—			184			—			184
Total assets	$	411		$	1,262		$	3		$	1,676		$	382		$	1,172		$	5		$	1,559
Liabilities
Derivative liabilities - commodity contracts	$	(7	)	$	(122	)	$	—		$	(129	)	$	(9	)	$	(122	)	$	—		$	(131	)
Derivative liabilities - FTRs	—			—			(7		)	(7		)	—			—			(11		)	(11		)
Total liabilities	$	(7	)	$	(122	)	$	(7	)	$	(136	)	$	(9	)	$	(122	)	$	(11	)	$	(142	)
Net assets (liabilities)(3)	$	404		$	1,140		$	(4	)	$	1,540		$	373		$	1,050		$	(6	)	$	1,417

⁽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 $1 million as of March 31, 2016 and December 31, 2015, 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, 2016 and December 31, 2015:

	Derivative Asset			Derivative Liability			Net Asset (Liability)
	(In millions)
January 1, 2015 Balance	$	27		$	(13	)	$	14
Unrealized gain (loss)	2			(5		)	(3		)
Purchases	9			(10		)	(1		)
Settlements	(33		)	17			(16		)
December 31, 2015 Balance	$	5		$	(11	)	$	(6	)
Unrealized loss	—			(1		)	(1		)
Settlements	(2		)	5			3
March 31, 2016 Balance	$	3		$	(7	)	$	(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, 2016:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(4	)	Model	RTO auction clearing prices	($4.60) to $3.70	$0.50	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 and AFS securities.

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 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 NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets.

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, 2016 and December 31, 2015:

	March 31, 2016(1)						December 31, 2015(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,776	$	44	$	1,820	$	1,778	$	16	$	1,794
FES	825		26		851		801		9		810
Equity securities
FirstEnergy	$	576	$	52	$	628	$	542	$	34	$	576
FES	372		36		408		354		24		378

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $161 million; FES - $113 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $157 million; FES - $139 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, 2016 and 2015 were as follows:

Three Months Ended
March 31, 2016	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	465	$	61	$	(50	)	$	(9	)	$	23
FES	138		42		(29		)	(8		)	13
March 31, 2015	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	371	$	60	$	(50	)	$	(7	)	$	25
FES	189		38		(28		)	(6		)	14

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, 2016 and December 31, 2015:

	March 31, 2016						December 31, 2015
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	6	$	1	$	7	$	6	$	2	$	8

The held-to-maturity debt securities contractually mature by June 30, 2017. Investments in employee benefit trusts and equity method investments totaling $271 million as of March 31, 2016 and $255 million as of December 31, 2015, 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 debt issuance costs, premiums and discounts:

	March 31, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	20,217	$	21,821	$	20,244	$	21,519
FES	3,036		3,112		3,027		3,121

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. 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, 2016 and December 31, 2015.

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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 related 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) as follows:

• Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

• Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings.

• Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted.

Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.

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.

Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $11 million as of March 31, 2016 and December 31, 2015. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Less than $1 million of net unamortized losses is expected to be amortized to income during the next twelve months.

FirstEnergy has used forward starting interest rate 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 designated 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. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $39 million and $42 million as of March 31, 2016 and December 31, 2015, respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to be amortized to interest expense during the next twelve months.

Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three months ended March 31, 2016 and 2015.

As of March 31, 2016 and December 31, 2015, no commodity or interest rate derivatives were designated as cash flow hedges.

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. As of March 31, 2016 and December 31, 2015, 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 $17 million and $20 million as of March 31, 2016 and December 31, 2015, respectively. During the next twelve months, approximately $10 million of unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $3 million during the three months ended March 31, 2016 and 2015.

22

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. Derivative instruments are not used in quantities greater than forecasted needs.

As of March 31, 2016, FirstEnergy’s net asset position under commodity derivative contracts was $164 million, which related to FES positions. Under these commodity derivative contracts, FES posted $4 million of collateral and received $25 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $5 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, 2016, an increase in commodity prices of 10% would decrease net income by approximately $22 million during the next twelve months.

NUGs

As of March 31, 2016, FirstEnergy's net liability position under NUG contracts was $135 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.

FTRs

As of March 31, 2016, FirstEnergy's and FES' FTR position was a $6 million and $4 million net liability, respectively, and FES posted $6 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations.

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 PJM, 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.

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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, 2016		December 31, 2015			March 31, 2016			December 31, 2015
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	205	$	150	Commodity Contracts	$	(109	)	$	(94	)
FTRs	2		7		FTRs	(8		)	(12		)
	207		157			(117		)	(106		)
Deferred Charges and Other Assets - Other					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs(1)	(136		)	(137		)
Commodity Contracts	88		78		Noncurrent Liabilities - Other
FTRs	1		1		Commodity Contracts	(20		)	(37		)
NUGs(1)	1		1		FTRs	(1		)	(1		)
	90		80			(157		)	(175		)
Derivative Assets	$	297	$	237	Derivative Liabilities	$	(274	)	$	(281	)

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

FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. 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 assets and derivative liabilities 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, 2016	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	293		$	(128	)	$	(25	)	$	140
FTRs	3			(3		)	—			—
NUG contracts	1			—			—			1
	$	297		$	(131	)	$	(25	)	$	141
Derivative Liabilities
Commodity contracts	$	(129	)	$	128		$	—		$	(1	)
FTRs	(9		)	3			6			—
NUG contracts	(136		)	—			—			(136		)
	$	(274	)	$	131		$	6		$	(137	)

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				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2015	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged		Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	228		$	(125	)	$	—	$	103
FTRs	8			(8		)	—		—
NUG contracts	1			—			—		1
	$	237		$	(133	)	$	—	$	104
Derivative Liabilities
Commodity contracts	$	(131	)	$	125		$	3	$	(3	)
FTRs	(13		)	8			5		—
NUG contracts	(137		)	—			—		(137		)
	$	(281	)	$	133		$	8	$	(140	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2016:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	14	42	(28	)	MWH
FTRs	15	—	15		MWH
NUGs	4	—	4		MWH
Natural Gas	81	1	80		mmBTU

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The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2016 and 2015, are summarized in the following tables:

	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2016
Unrealized Gain Recognized in:
Other Operating Expense (1)	$	62		$	2		$	64
Realized Gain (Loss) Reclassified to:
Revenues (1)	$	71		$	2		$	73
Purchased Power Expense (1)	(45		)	—			(45		)
Other Operating Expense (1)	—			(12		)	(12		)
Fuel Expense	(8		)	—			(8		)
(1) All amounts are associated with FES.
	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2015
Unrealized Gain (Loss) Recognized in:
Other Operating Expense (2)	$	11		$	(13	)	$	(2	)
Realized Gain (Loss) Reclassified to:
Revenues (3)	$	(1	)	$	37		$	36
Purchased Power Expense (4)	(3		)	—			(3		)
Other Operating Expense (5)	—			(13		)	(13		)
Fuel Expense	(16		)	—			(16		)
(2) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES.
(3) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES.
(4) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES.
(5) Includes ($13) million for FTRs associated with FES.

The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months endedMarch 31, 2016 and 2015. Changes in the value of these instruments are deferred for future recovery from (or credit to) customers:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			Regulated FTRs			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2016	$	(136	)	$	1		$	(135	)
Unrealized loss	(12		)	(1		)	(13		)
Settlements	13			(2		)	11
Outstanding net asset (liability) as of March 31, 2016	$	(135	)	$	(2	)	$	(137	)
Outstanding net asset (liability) as of January 1, 2015	$	(151	)	$	11		$	(140	)
Unrealized gain (loss)	(8		)	1			(7		)
Settlements	11			(11		)	—
Outstanding net asset (liability) as of March 31, 2015	$	(148	)	$	1		$	(147	)

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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 SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC.PE recovers its costs plus a return for providing SOS.

The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years.PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014.The costs of the 2015-2017 plan are expected to be approximately$66 million for that three-year period, of which $26 million was incurred through March 2016. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%. PE continues to recover program costs subject to a five-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.On January 28, 2016, PE filed a request to increase plan spending by$2 millionin order to reach the new goals for 2017 set in the July 16, 2015 order.

On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the Maryland electric utilities to submit analyses 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 required 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's responsive filings 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 require 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.On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting.The Staff of the MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost.The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters.

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 is comprised oftwocomponents, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU.OneBGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers.The second BGS component provides a fixed price service and 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.

Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and financial components and is expected to take approximately one year to complete.

In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using afive-year look back from the beginning of the test year;

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(ii) allocating savings with75%retained by the company and25%allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation.On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding.Briefing has been completed, and oral argument has not yet been scheduled.

In April 2016, JCP&L intends to file tariffs with the NJBPU proposing a general rate increase associated with its distribution operations that seeks to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses.The filing will request approval to increase annual operating revenues by approximately$142.1 millionbased upon a hybrid test year for the twelve months ending June 30, 2016. JCP&L will request that the new rates take effect in January 2017.

On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. The procedural schedule was suspended while the NJBPU considers a motion on a legal issue regarding whether MAIT can be designated as a "public utility" in New Jersey.On February 24, 2016, the NJBPU issued an Order concluding that MAIT does not satisfy the “electricity distribution” element necessary for “public utility” status because MAIT would not own any electric distribution assets in New Jersey. On April 22, 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certain JCP&L distributions assets in the transfer to satisfy the "electricity distribution" element necessary for "public utility" status in accordance with the NJBPU’s February 24, 2016 order. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.

OHIO

The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016.The material terms of ESP 3 include:

• A base distribution rate freeze through May 31, 2016;

• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

• Economic development and assistance to low-income customers for thetwo-year plan period at levels established in the prior 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);

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

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

• A commitment not to recover from retail customers certain costs related to transmission cost allocations 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 FERC proceedings;

• 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, Ohio's renewable energy and energy efficiency standard, 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.

Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy Council and the ELPC.The oral argument in this matter occurred on January 6, 2016.

The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's Progress.The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and recommendations on May 28, 2015, and June 4, 2015.On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and Recommendation, which included PUCO Staff as a signatory party in addition to other signatories.

The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:

• Aneight-year term (June 1, 2016 - May 31, 2024);

• Contemplates continuing a base distribution rate freeze through May 31, 2024;

• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through aneight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

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

• Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

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• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows:$10 million in year five,$20 millionin year six,$30 millionin year seven and$40 millionin year eight;

• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of thefive-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals$360 million, including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings;

• Potential procurement of100 MWof new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;

• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;

• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016);

• A goal across FirstEnergy to reduce CO₂ emissions by90%below 2005 levels by 2045;

• A contribution of$3 millionper year ($24 millionover theeight-year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory;

• Contributions of $2.4 millionper year ($19 millionover the eight-year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and

• A contribution of$1 millionper year ($8 millionover theeight-year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio.

On March 31, 2016, the PUCO issued an Opinion and Order adopting and approving, with modifications, the Ohio Companies’ ESP IV. Changes arising from the approval of ESP IV will go into effect on June 1, 2016.The PUCO’s modifications of ESP IV, among others, included:

• Limiting average customer bill amounts for the firsttwoyears of the plan, subject to certain exceptions, and permitting deferral for the second year;

• Prohibiting recovery of retirement costs of the ESP IV PPA Facilities through Rider RRS;

• Assigning the burden of capacity performance penalties incurred by the ESP IV PPA Facilities to the Ohio Companies, rather than customers, and to provide that all capacity performance bonuses earned by the ESP IV PPA Facilities be retained by the Ohio Companies, rather than customers; and

• Providing for the modification of the severability provision previously included in ESP IV, to also address potential future PJM Tariff or rule changes prohibiting the Ohio Companies from offering output of the ESP IV PPA Facilities into PJM auctions.

Applications for Rehearing may be filed within thirty days of the issuance of the March 31, 2016 Opinion and Order.

On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies that requests FERC review the ESP IV PPA under Section 205 of the FPA. FES and the Ohio Companies responded to the complaint on February 23, 2016 and March 9, 2016. In a separate proceeding on March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint asks that FERC issue an order by May 1, 2016, so the revised rule can be in effect for the May 2016 PJM capacity auction. The Ohio Companies responded to the complaint on April 11, 2016 and April 20, 2016. In addition to such proceedings, opponents have expressed an intention to challenge in the courts and/or before FERC, the ESP IV PPA or PUCO's approval of the ESP IV. Management intends to vigorously defend against such challenges. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016.

Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of2,266GWHs in 2015 and2,288GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative amendments to the energy efficiency standards discussed below.The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional0.75%thereafter through 2020, subject to legislative amendments to the peak demand reduction standards discussed below.

On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy mandates, recommending that the current level of mandates remain in place indefinitely.The report also recommended: (i) an expedited process for review of utility proposed energy efficiency plans; (ii) ensuring maximum credit for all of Ohio's Energy Initiatives; (iii) a switch from energy mandates to energy incentives; and (iv) a declaration be made that the General Assembly may determine energy policy of the state. No legislation has yet been introduced to change the standards described above.

On September 24, 2014, the Ohio Companies filed an amendment to their energy efficiency portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB310.On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio plan.Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters specified in those applications and the matter remains pending before the PUCO.

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On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019.The plans as proposed comply with benchmarks contemplated by SB310 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities.The Ohio Companies anticipate the cost of the plans will be approximately$323 millionover the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms.

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, which is still pending.The matter has not been scheduled for oral argument.

Ohio law 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 2026, subject to legislative amendments discussed above, except 2015 and 2016 that remain at the 2014 level.The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements.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.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 certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of$43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent.On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted.On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order.The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded.The matter is not yet scheduled for oral argument.

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. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, 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 spot market purchases, quarterly descending clock auctions for 3, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn.

On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery period, which would provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the proposed programs, the supply would be provided by wholesale suppliers though a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. In addition, the proposal includes modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges.A hearing was held on February 25, 2016.A Joint Petition for Settlement resolving all issues was filed on April 1, 2016, which is subject to PPUC approval.

Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs.The Pennsylvania Companies' Phase II EE&C Plans are effective through May 31, 2016.Total Phase II costs of these plans are expected to be approximately$175 millionand recoverable through the Pennsylvania Companies' reconcilable EE&C riders.On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at1.8%for ME, 1.7% for Penn, 1.8% for WP, and 0%for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at4.0% for ME, 3.9%for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies filed their Phase III EE&C plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint settlement resolving all issues, which was subject to PPUC approval.On March 10, 2016, the PPUC entered an Opinion and Order approving the settlement and directing that the Pennsylvania Companies modify certain cost recovery methodologies to describe the allocation of EE&C Phase III common costs among customer classes and to describe the recovery of remaining costs of their Phase II EE&C Plans. None of the parties to the joint settlement elected to withdraw from the joint settlement due to the modifications.

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Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval.Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC.On October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five-year period of 2016 to 2020 for the following costs: WP$88.34 million; PN$56.74 million; Penn$56.35 million; and ME$43.44 million. These amounts include all qualifying distribution capital additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania Companies as discussed below. On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. The DSIC riders are expected to be effective July 1, 2016.Various parties have filed interventions, answers, or complaints with the PPUC in response to the Pennsylvania Companies’ request for approval of the DSIC filings raising cost allocation and other issues, and the Pennsylvania Companies have responded.

In April 2016, each of the Pennsylvania Companies intends to file tariffs with the PPUC proposing general rate increases associated with their distribution operations that will benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.The filings will request approval to increase annual operating revenues by approximately$140.2 millionat ME,$158.8 millionat PN,$42.0 millionat Penn, and$98.2 millionat WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. The new rates are expected to take effect in January 2017.

On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.On March 4, 2016, a Joint Petition for Full Settlement was submitted to the PPUC for consideration and approval. On April 18, 2016, the ALJs issued an Initial Decision approving the Joint Petition for Full Settlement without modifications.A final decision from the PPUC is expected by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually.

MP and PE filed with the WVPSC on March 31, 2016 their Phase II energy efficiency program proposal for approval.MP and PE are proposing three energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of0.5%of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP.The costs for the program are expected to be$9.9 millionwhich would be recovered through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year.MP and PE are requesting WVPSC approval by October 1, 2016 so MP and PE can implement the programs beginning January 1, 2017.

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, NG, 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 occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC.Moreover, it is clear that 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 electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows.

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FERC MATTERS

Ohio ESP IV PPA

For information regarding matters before FERC related to the ESP IV PPA between FES and the Ohio Companies, see “Regulatory Matters - Ohio” above.

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 advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM.This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit.On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines.The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole.The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings.Settlement discussions under a FERC-appointed settlement judge are ongoing.

In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent “right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of PJM’s RTEP process.FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether FirstEnergy and the PJM transmission owners have a "right of first refusal" is scheduled for oral argument on May 4, 2016, before the U.S. Court of Appeals for the D.C. Circuit in an appeal of FERC's order approving PJM's Order No.1000 compliance filing.

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.While many of the matters involved with the move have been resolved, FERC denied recovery under 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 demonstrating net benefits to customers from the transfer to PJM.Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, 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 March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.

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 before FERC and certain United States appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which is pending at FERC.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.On a related issue, FirstEnergy joined certain other PJM transmission owners in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region.On January 22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent.Certain PJM transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP export charge on transactions into PJM was correct and should be re-affirmed on remand.The briefs and replies thereto remain before FERC for consideration.

In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone.The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under PJM Transmission Rates.

The outcome of the proceedings that address the remaining open issues related to costs for the "Michigan Thumb" transmission project and "legacy RTEP" transmission projects cannot be predicted at this time.

Transfer of Transmission Assets to MAIT

On June 10, 2015, MAIT, a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the purposes of owning and operating all FERC-jurisdictional transmission assets of JCP&L, ME and PN following the receipt of all

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necessary state and federal regulatory approvals.On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT.Additionally, the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way associated with the utilities' transmission assets; (ii) a Mutual Assistance Agreement; (iii) MAIT being deemed a public utility under state law; (iv) MAIT's participation in FE's regulated companies' money pool; and (v) certain affiliated interest agreements. If approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL.MAIT's transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities under the PJM Tariff.FERC approved the transaction on February 18, 2016. Upon receipt of all applicable regulatory approvals with respect to the transfer,MAIT expects to file a Section 204 application with FERC, and other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their respective contributions, and to issue debt.MAIT will also make a Section 205 formula rate application with FERC to establish its transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.

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 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.The California parties appealed FERC's decision back to the Ninth Circuit.AE Supply joined with other intervenors in the case and filed a brief in support of FERC's dismissal of the case.On April 29, 2015, the Ninth Circuit remanded the case to FERC for further proceedings.On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.Settlement discussions under a FERC-appointed settlement judge are ongoing. On March 1, 2016, FERC issued an order on rehearing clarifying the scope of the evidentiary hearing and the standard of review on remand. In particular, FERC clarified that certain bilateral transactions, including those of AE Supply to the California parties, are protected by the Mobile-Sierra standard, which requires a demonstration of harm to the public interest to determine liability and obligation to make refunds. The California parties requested rehearing of FERC’s March 1, 2016 order, and also appealed FERC’s November 3, 2015, and March 1, 2016 orders to the Ninth Circuit, which has stayed its review pending the outcome of the ongoing proceeding discussed above.

In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a 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 and other parties filed motions to dismiss, which FERC granted.The California Attorney General 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.

The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.

PATH Transmission Project

On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland which PJM had previously suspended in February 2011.As a result of PJM canceling the project, 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.PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of10.9%(10.4%base plus0.5%for RTO membership) from PJM customers overfiveyears.FERC issued an order denying the0.5%ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to settlement proceedings and hearing if the parties could not agree to a settlement.On March 24, 2014, the FERC Chief ALJ terminated settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531, discussed below, to the PATH proceeding.On September 14, 2015, the ALJ issued his initial decision, disallowing recovery of certain costs. The initial decision and exceptions thereto remain before FERC for review and a final order.FirstEnergy continues to believe the costs are recoverable, subject to final ruling from FERC.

FERC Opinion No. 531

On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow element of FERC’s ROE methodology, and announced the potential for a qualitative adjustment to the ROE methodology results.Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight); and (b) a long-term dividend growth

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forecast based on a forecast for the U.S. economy (1/3 weight).Regarding the qualitative adjustment, for single-utility rate cases FERC formerly pegged ROE at the median of the “zone of reasonableness” that came out of the ROE formula, whereas going forward, FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level sufficient to attract future investment.On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE methodology to certain ISO New England transmission owners, andon March 3, 2015, FERC issued Opinion No. 531-B affirming its prior rulings.Appeals of Opinion Nos. 531, 532-A and 531-B are pending before the U.S. Court of Appeals for the D.C. Circuit.FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities and the cost-of-service wholesale power generation transactions of MP.

MISO Capacity Portability

On June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM.FirstEnergy and other parties submitted filings arguing that MISO's concerns largely are without foundation,FERC did not mandate a solution in response to MISO's concerns.At FERC's direction, in May, 2015, PJM, MISO, and their respective independent market monitors provided additional information on their various joint issues surrounding the PJM/MISO seam to assist FERC's understanding of the issues and what, if any, additional steps FERC should take to improve the efficiency of operations at the PJM/MISO seam.Stakeholders, including FESC on behalf of certain of its affiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions.The various submissions and responses remain before FERC for consideration.

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.

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, 2016, FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.7 billion, consisting of parental guarantees ($591 million), subsidiaries' guarantees ($2.1 billion), other guarantees ($300 million) and other assurances ($669 million).

Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG.Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG.

COLLATERAL AND CONTINGENT-RELATED FEATURES

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

Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral.Based on FES' power portfolio exposures as ofMarch 31, 2016, FES has posted collateral of$180 million.The Regulated Distribution segment has posted collateral of$1 million.

These credit-risk-related contingent features, or the margining provisions within bilateral agreements, 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, which is the ability to secure additional collateral when needed, 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 that may be required under certain events as ofMarch 31, 2016:

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Collateral Provisions	FES/ AE Supply (Tied to FE Corp. Rating)		FES/ AE Supply (Tied to FES Rating)		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	25	$	173	$	40	$	238
Non-Investment Grade Ratings (All Rating Agencies at or below BB+/Ba1)	$	25	$	200	$	40	$	265
Total Exposure from Contractual Obligations	$	25	$	341	$	40	$	406

Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment.As ofMarch 31, 2016, 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 would be required to post$3 million with affiliated parties.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million. 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, continue to provide their joint and several guaranties of the obligations of Global Holding under the 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 under the current facility as collateral.

During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the Signal Peak mine to FG in exchange for FE extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million.See Note 6, Variable Interest Entities, for additional information regarding FEV's investment in Global Holding.

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.

Clean Air Act

FirstEnergy complies with SO₂and NOx emission 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.

CSAPR requires reductions of NOx and SO₂emissions intwophases (2015 and 2017), 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.The U.S. Court of Appeals for the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia.This follows the 2014 U.S. Supreme Court ruling generally upholding EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states.EPA proposed a CSAPR update rule on November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017.Depending on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result.

EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of75PPB to70PPB on October 1, 2015.EPA stated the vast majority of U.S. counties will meet the new70PPB standard by 2025 due to other federal and state rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017.States will then have roughlythreeyears to develop implementation plans to attain the new 2015 ozone NAAQS.Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result.

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MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant.FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately$345 million(CES segment of$168 millionand Regulated Distribution segment of$177 million), of which$226 millionhas been spent through March 31, 2016 ($96 millionat CES and$130 millionat Regulated Distribution).

On August 3, 2015, FG, a subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure that excuses FG’s performance under its coal transportation contract with these parties.Specifically, the dispute arises from a contract for the transportation by BNSF and CSX of a minimum of3.5 milliontons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, those plants were deactivated by April 16, 2015.In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance.Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages including, but not limited to, lost profits under the contract through 2025.As part of its statement of claim, a right to liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearings. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused.FirstEnergy and FES intend to vigorously assert their position in the arbitration proceedings.If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.FirstEnergy and FES are unable to estimate the loss or range of loss.

FG is also a party to another coal transportation contract covering the delivery of 2.5 milliontons annually through 2025, a portion of which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS.FG has asserted a defense of force majeure in response to delivery shortfalls to such plant under this contract as well.If FirstEnergy and FES fail to reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.FirstEnergy and FES are unable to estimate the loss or range of loss.

As to both coal transportation agreements referenced above, FES paid in settlement approximately$70 millionin liquidated damages for delivery shortfalls in 2014 related to its deactivated plants.

As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015.In response to notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the termination.This matter is currently in the discovery phase of litigation and no trial date has been established. There are approximately 5.5 milliontons remaining under the contract for delivery.At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going litigation with respect to this agreement.

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.The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs.On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued 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.On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009.FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.

Climate Change

FirstEnergy has established a goal to reduce CO₂ emissions by90%below 2005 levels by 2045.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 reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants.The EPA released its final regulations in August 2015, to reduce CO₂emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO₂emission rate goals.The EPA’s CPP allows states to request atwo-year extension to finalize SIPs by September 6, 2018.If states

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fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs.The EPA also finalized separate regulations imposing CO₂emission limits for new, modified, and reconstructed fossil fuel fired electric generating units.On June 23, 2014, the United States Supreme Court decided that CO₂or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies.Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015.On January 21, 2015, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument.On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court.Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020.The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris.The Paris Agreement must be ratified by at least 55 countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below two degrees Celsius become effective.FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.The CO₂ emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system.FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system.Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be substantial.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.The treatment obligations will phase-in as permits are renewed on afive-year cycle from 2018 to 2023.The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits.Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result.

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 the appeal or estimate the possible loss or range of loss.

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

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act.Certain coal combustion residuals, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA's evaluation of the need for future regulation.

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In December 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants.Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs.Although unexpected, changes in timing and closure plan requirements in the future could impact our asset retirement obligations significantly.

Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016 and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG 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 CCRs, 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 disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal options will be sufficient for the ongoing operation of the plant.On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR.On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility.

FirstEnergy or its subsidiaries 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 Sheets as ofMarch 31, 2016based 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$123 millionhave been accrued throughMarch 31, 2016. Included in the total are accrued liabilities of approximately$87 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 loss 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, 2016, FirstEnergy had approximately$2.4 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 NDTs 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 NDTs.FE and FES have also entered into a total of$24.5 millionin parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years.On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue operation through April 22, 2037.Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record and admit a contention on the NRC’s Continued Storage Rule.On August 6, 2015, this intervenor sought review of the NRC Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC intervened in that proceeding.

As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011.These inspections revealed that the cracking condition had propagated a small amount in select areas.FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking.The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance.FENOC plans to submit a license amendment application related to the Shield Building analysis in 2016.

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 FirstEnergy's nuclear facilities.

38

Other Legal Matters

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 a 93.83% 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 (Loss) and Comprehensive Income (Loss) for the three months ended March 31, 2016 and 2015, Condensed Consolidating Balance Sheets as of March 31, 2016 and December 31, 2015, and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2016 and 2015, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. 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.

39

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2016	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,155		$	415		$	531		$	(902	)	$	1,199
OPERATING EXPENSES:
Fuel	—			119			46			—			165
Purchased power from affiliates	927			—			57			(902		)	82
Purchased power from non-affiliates	377			—			—			—			377
Other operating expenses	4			71			153			12			240
Provision for depreciation	3			31			50			(1		)	83
General taxes	8			10			8			—			26
Total operating expenses	1,319			231			314			(891		)	973
OPERATING INCOME (LOSS)	(164		)	184			217			(11		)	226
OTHER INCOME (EXPENSE):
Investment income, including net income from equity investees	251			6			17			(259		)	15
Interest expense — affiliates	(9		)	(2		)	(2		)	11			(2		)
Interest expense — other	(13		)	(26		)	(11		)	14			(36		)
Capitalized interest	—			2			8			—			10
Total other income (expense)	229			(20		)	12			(234		)	(13		)
INCOME BEFORE INCOME TAXES (BENEFITS)	65			164			229			(245		)	213
INCOME TAXES (BENEFITS)	(66		)	61			86			1			82
NET INCOME	$	131		$	103		$	143		$	(246	)	$	131
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	131		$	103		$	143		$	(246	)	$	131
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(4		)	(3		)	—			3			(4		)
Change in unrealized gain on available-for-sale securities	23			—			23			(23		)	23
Other comprehensive income (loss)	19			(3		)	23			(20		)	19
Income taxes (benefits) on other comprehensive income (loss)	7			(1		)	8			(7		)	7
Other comprehensive income (loss), net of tax	12			(2		)	15			(13		)	12
COMPREHENSIVE INCOME	$	143		$	101		$	158		$	(259	)	$	143

40

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	1,332		$	493		$	507		$	(955	)	$	1,377
OPERATING EXPENSES:
Fuel	—			180			50			—			230
Purchased power from affiliates	957			—			68			(955		)	70
Purchased power from non-affiliates	543			—			—			—			543
Other operating expenses	180			67			154			12			413
Provision for depreciation	3			30			48			(1		)	80
General taxes	15			8			6			—			29
Total operating expenses	1,698			285			326			(944		)	1,365
OPERATING INCOME (LOSS)	(366		)	208			181			(11		)	12
OTHER INCOME (EXPENSE):
Investment income, including net income from equity investees	241			3			14			(245		)	13
Interest expense — affiliates	(6		)	(2		)	(1		)	7			(2		)
Interest expense — other	(13		)	(26		)	(13		)	15			(37		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	222			(24		)	8			(223		)	(17		)
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)	(144		)	184			189			(234		)	(5		)
INCOME TAXES (BENEFITS)	(141		)	67			70			2			(2		)
NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(4		)	(4		)	3			1			(4		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available-for-sale securities	3			—			—			—			3
Other comprehensive income (loss)	(2		)	(4		)	3			1			(2		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(1		)	1			—			(1		)
Other comprehensive income (loss), net of tax	(1		)	(3		)	2			1			(1		)
COMPREHENSIVE INCOME (LOSS)	$	(4	)	$	114		$	121		$	(235	)	$	(4	)

41

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of March 31, 2016	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	229		—		—		—			229
Affiliated companies	442		310		305		(610		)	447
Other	32		1		74		—			107
Notes receivable from affiliated companies	394		1,429		889		(2,712		)	—
Materials and supplies	39		191		216		—			446
Derivatives	207		—		—		—			207
Collateral	80		—		—		—			80
Prepayments and other	69		11		—		—			80
	1,492		1,944		1,484		(3,322		)	1,598
PROPERTY, PLANT AND EQUIPMENT:
In service	92		6,389		8,277		(382		)	14,376
Less — Accumulated provision for depreciation	43		2,163		3,863		(195		)	5,874
	49		4,226		4,414		(187		)	8,502
Construction work in progress	30		271		972		—			1,273
	79		4,497		5,386		(187		)	9,775
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,372		—			1,372
Investment in affiliated companies	7,712		—		—		(7,712		)	—
Other	—		10		—		—			10
	7,712		10		1,372		(7,712		)	1,382
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	276		—		—		(276		)	—
Customer intangibles	57		—		—		—			57
Goodwill	23		—		—		—			23
Property taxes	—		9		21		—			30
Derivatives	89		—		—		—			89
Other	24		301		4		56			385
	469		310		25		(220		)	584
	$	9,752	$	6,761	$	8,267	$	(11,441	)	$	13,339
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—	$	266	$	308	$	(25	)	$	549
Short-term borrowings-
Affiliated companies	2,373		386		2		(2,712		)	49
Accounts payable-
Affiliated companies	619		190		172		(619		)	362
Other	26		90		—		—			116
Accrued taxes	3		52		101		(85		)	71
Derivatives	115		—		—		—			115
Other	75		74		15		77			241
	3,211		1,058		598		(3,364		)	1,503
CAPITALIZATION:
Total equity	5,749		3,046		4,634		(7,680		)	5,749
Long-term debt and other long-term obligations	690		2,067		840		(1,117		)	2,480
	6,439		5,113		5,474		(8,797		)	8,229
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		782			782
Accumulated deferred income taxes	6		35		743		(62		)	722
Retirement benefits	28		311		—		—			339
Asset retirement obligations	—		188		650		—			838
Derivatives	21		—		—		—			21
Other	47		56		802		—			905
	102		590		2,195		720			3,607
	$	9,752	$	6,761	$	8,267	$	(11,441	)	$	13,339

42

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2015	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	275		—		—		—			275
Affiliated companies	433		403		461		(846		)	451
Other	36		4		19		—			59
Notes receivable from affiliated companies	406		1,210		805		(2,410		)	11
Materials and supplies	53		204		213		—			470
Derivatives	154		—		—		—			154
Collateral	70		—		—		—			70
Prepayments and other	48		18		—		—			66
	1,475		1,841		1,498		(3,256		)	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	93		6,367		8,233		(382		)	14,311
Less — Accumulated provision for depreciation	40		2,144		3,775		(194		)	5,765
	53		4,223		4,458		(188		)	8,546
Construction work in progress	30		249		878		—			1,157
	83		4,472		5,336		(188		)	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,327		—			1,327
Investment in affiliated companies	7,452		—		—		(7,452		)	—
Other	—		10		—		—			10
	7,452		10		1,327		(7,452		)	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	300		16		—		(316		)	—
Customer intangibles	61		—		—		—			61
Goodwill	23		—		—		—			23
Property taxes	—		12		28		—			40
Derivatives	79		—		—		—			79
Other	29		312		14		12			367
	492		340		42		(304		)	570
	$	9,502	$	6,663	$	8,203	$	(11,200	)	$	13,168
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—	$	229	$	308	$	(25	)	$	512
Short-term borrowings-
Affiliated companies	2,021		389		—		(2,410		)	—
Other	—		8		—		—			8
Accounts payable-
Affiliated companies	884		146		368		(856		)	542
Other	21		118		—		—			139
Accrued taxes	7		93		62		(86		)	76
Derivatives	103		1		—		—			104
Other	66		61		9		45			181
	3,102		1,045		747		(3,332		)	1,562
CAPITALIZATION:
Total equity	5,605		2,944		4,476		(7,420		)	5,605
Long-term debt and other long-term obligations	690		2,116		840		(1,136		)	2,510
	6,295		5,060		5,316		(8,556		)	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		791			791
Accumulated deferred income taxes	6		—		697		(103		)	600
Retirement benefits	27		305		—		—			332
Asset retirement obligations	—		191		640		—			831
Derivatives	37		1		—		—			38
Other	35		61		803		—			899
	105		558		2,140		688			3,491
	$	9,502	$	6,663	$	8,203	$	(11,200	)	$	13,168

43

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2016	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(356	)	$	277		$	307		$	—		$	228
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	352			8			1			(312		)	49
Redemptions and Repayments-
Short-term borrowings, net	—			(11		)	—			11			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	352			(5		)	1			(301		)	47
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27		)	(53		)	(63		)	—			(143		)
Nuclear fuel	—			—			(149		)	—			(149		)
Sales of investment securities held in trusts	—			—			138			—			138
Purchases of investment securities held in trusts	—			—			(151		)	—			(151		)
Cash investments	10			—			—			—			10
Loans to affiliated companies, net	12			(219		)	(83		)	301			11
Other	9			—			—			—			9
Net cash provided from (used for) investing activities	4			(272		)	(308		)	301			(275		)
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

44

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(662	)	$	222		$	545		$	—		$	105
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	674			—			—			(524		)	150
Redemptions and Repayments-
Long-term debt	(17		)	—			—			—			(17		)
Short-term borrowings, net	—			(5		)	(28		)	33			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	657			(7		)	(28		)	(491		)	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1		)	(36		)	(82		)	—			(119		)
Nuclear fuel	—			—			(60		)	—			(60		)
Sales of investment securities held in trusts	—			—			189			—			189
Purchases of investment securities held in trusts	—			—			(202		)	—			(202		)
Loans to affiliated companies, net	6			(179		)	(362		)	491			(44		)
Net cash provided from (used for) investing activities	5			(215		)	(517		)	491			(236		)
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

45

12. SEGMENT INFORMATION

FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.

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 located primarily in West Virginia, Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. As of March 31, 2016, this business segment controlled3,790MWs of generating 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). This segment also includes the regulatory asset associated with the abandoned PATH project. The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as fixed rates at certain of FirstEnergy’s utilities. Both the forward-looking and fixed rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of ATSI's and TrAIL’s revenue requirement is updated annually based on a projected rate base and projected costs, subject to annual true-up. Except for the recovery of the PATH abandoned project regulatory asset, the segment's revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

The CES segment, through FES and AE Supply, primarily 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. As of March 31, 2016, this business segment controlled13,162MWs of generating capacity.The CES 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 and capacity costs charged by PJM to deliver energy to the segment’s customers.

Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other.As of March 31, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $2.1 billion was borrowed by FE under its revolving credit facility.

46

Segment Financial Information

Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)
March 31, 2016
External revenues	$	2,521	$	275	$	1,152		$	(42	)	$	(37	)	$	3,869
Internal revenues	—		—		152			—			(152		)	—
Total revenues	2,521		275		1,304			(42		)	(189		)	3,869
Depreciation	169		43		102			15			—			329
Amortization of regulatory assets, net	59		2		—			—			—			61
Investment income	11		—		15			11			(9		)	28
Interest expense	147		43		47			51			—			288
Income taxes (benefits)	98		43		85			(13		)	—			213
Net income (loss)	165		74		144			(55		)	—			328
Total assets	27,907		7,679		16,578			531			—			52,695
Total goodwill	5,092		526		800			—			—			6,418
Property additions	262		258		169			9			—			698
March 31, 2015
External revenues	$	2,562	$	238	$	1,175		$	(42	)	$	(36	)	$	3,897
Internal revenues	—		—		260			—			(260		)	—
Total revenues	2,562		238		1,435			(42		)	(296		)	3,897
Depreciation	172		37		96			14			—			319
Amortization of regulatory assets, net	29		3		—			—			—			32
Investment income	13		—		12			2			(10		)	17
Interest expense	144		39		48			47			1			279
Income taxes (benefits)	122		42		(4		)	(18		)	2			144
Net income (loss)	208		72		(8		)	(50		)	—			222
Total assets	27,974		6,601		16,497			807			—			51,879
Total goodwill	5,092		526		800			—			—			6,418
Property additions	280		254		126			8			—			668

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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

FIRSTENERGY’S BUSINESS

FirstEnergy and its subsidiaries are principally involved in the generation, transmission and distribution of electricity. Its reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.

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 located primarily in West Virginia, Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. As of March 31, 2016, this business segment controlled3,790MWs of generating 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). This segment also includes the regulatory asset associated with the abandoned PATH project. The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as fixed rates at certain of FirstEnergy’s utilities. Both the forward-looking and fixed rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of ATSI's and TrAIL’s revenue requirement is updated annually based on a projected rate base and projected costs, subject to annual true-up. Except for the recovery of the PATH abandoned project regulatory asset, the segment's revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

The CES segment, through FES and AE Supply, primarily 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. As of March 31, 2016, this business segment controlled13,162MWs of generating capacity.The CES 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 and capacity costs charged by PJM to deliver energy to the segment’s customers.

Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other.As of March 31, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $2.1 billion was borrowed by FE under its revolving credit facility.

EXECUTIVE SUMMARY

FirstEnergy continues to capitalize on investment opportunities available in its Regulated Transmission and Regulated Distribution businesses while implementing a conservative hedging strategy at its competitive business. FirstEnergy is focused on improving its balance sheet and maintaining investment grade credit metrics at each business unit, while improving metrics at FirstEnergy over time.

FirstEnergy’s regulated investment strategy focuses on delivering enhanced customer service and reliability, strengthening grid and cyber-security, and adding resiliency and operating flexibility to its transmission and distribution infrastructure. Focusing on reinvestment in its regulated operations will also provide stability and growth for FirstEnergy as this plan is implemented over the coming years.

Regulated Transmission

The centerpiece of FirstEnergy’s regulated investment strategy is the Energizing the Future transmission expansion plan. The initial phase of this plan includes $4.2 billion in investments from 2014 through 2017 to modernize FirstEnergy's transmission system. Through 2015, FirstEnergy’s capital expenditures under this plan were $2.4 billion and in 2016 capital expenditures under this plan are projected to be approximately $1 billion.

Additionally, in June 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT. If approved, MAIT will operate similar to FET’s two existing stand-alone transmission subsidiaries, ATSI and TrAIL. FERC approved the transaction in February 2016. In February

48

2016, the NJBPU issued an Order concluding that MAIT does not satisfy the “electricity distribution” element necessary for “public utility” status and in April 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certain JCP&L distribution assets in the transfer to satisfy the "electricity distribution" element necessary for "public utility" status in accordance with the NJPBU’s February 2016 order. On April 18, 2016, the ALJs issued an Initial Decision approving without modification the Joint Petition for Full Settlement submitted to the PPUC in March 2016. A final decision from the PPUC is expected by mid-2016. Upon receipt of all applicable regulatory approvals with respect to the transfer, MAIT expects to file a Section 204 application with FERC, and other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their respective contributions, and to issue debt. MAIT will also make a Section 205 formula rate application with FERC to establish its transmission rate.

Regulated Distribution

During the first quarter of 2016, FirstEnergy continued to pursue key regulatory initiatives across its utility footprint, focusing on providing significant benefits to customers while ensuring the timely and appropriate recovery of investments. These initiatives included:

• On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs for infrastructure improvements over the 2016-2020 period totaling nearly $245 million. The Pennsylvania Companies filed DSIC riders on February 16, 2016, for quarterly cost recovery associated with the projects approved in the LTIIPs, PPUC approval for such DSIC riders remain pending.

• The Ohio Companies’ ESP IV, Powering Ohio’s Progress, was approved by the PUCO on March 31, 2016, with certain modifications. The key terms of the approved ESP IV, as further described under Outlook below, include:

◦ An eight-year term;

◦ Contemplates continuing a base distribution rate freeze through May 31, 2024;

◦ An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through aneight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

◦ A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows:$10 million in year five,$20 millionin year six,$30 millionin year seven and$40 millionin year eight;

◦ Limiting average customer bill amounts for the firsttwoyears of the plan, subject to certain exceptions, and permitting deferral for the second year;

◦ Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

◦ A goal across FirstEnergy to reduce CO₂ emissions by 90 percent below 2005 levels by 2045;

◦ An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016); and

◦ An agreement to file a case seeking to transition to decoupled base rates for residential base distribution customers.

On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies that requests FERC review the ESP IV PPA under Section 205 of the FPA. FES and the Ohio Companies responded to the complaint on February 23, 2016 and March 9, 2016. In a separate proceeding on March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint asks that FERC issue an order by May 1, 2016, so the revised rule can be in effect for the May 2016 PJM capacity auction. The Ohio Companies responded to the complaint on April 11, 2016 and April 20, 2016. In addition to such proceeding, opponents have expressed an intention to challenge in the courts and/or before FERC, the ESP IV PPA or PUCO's approval of the ESP IV. Management intends to vigorously defend against such challenges. On April 1, 2016, the Ohio Companies and FES entered into the ESP IV PPA.

In April 2016, JCP&L intends to file tariffs with the NJBPU proposing a general rate increase, requesting approval to increase annual operating revenues by approximately $142 million. Additionally, in April 2016, each of the Pennsylvania Companies intends to file tariffs with the PPUC proposing general rate increases, requesting approval to increase annual operating revenues by approximately $140 million at ME, $159 million at PN, $42 million at Penn, and $98 million at WP.

Competitive Energy Services

FirstEnergy continues its strategy for its competitive business to more effectively hedge its generation by reducing exposure to weather-sensitive load in certain sales channels and pursuing high-margin sales, while leaving a portion of its generation available

49

to capture future market opportunities or to mitigate risk. This strategy is designed to position CES to benefit from opportunities if and when electricity markets improve while limiting risk from continued challenging market conditions. At the same time, FirstEnergy continues to advocate for reforms that can ensure competitive wholesale markets adequately value baseload generation, which is essential to maintaining grid reliability. 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 plant. The effect of this decision on FirstEnergy's and FES' results of operations would be to displace higher per unit fuel expense with lower per unit purchased power.

Following the PUCO’s March 31, 2016, Order and Opinion, approving, with modification, the Ohio Companies’ ESP IV as discussed above, FES entered into the ESP IV PPA with the Ohio Companies on April 1, 2016. The ESP IV PPA has an eight-year term whereby FES will sell all the output of the ESP IV PPA Facilities, which represents 3,241 MWs of generating capacity, to the Ohio Companies beginning June 1, 2016. In exchange for the rights to this output, the Ohio Companies will pay FES a negotiated rate consisting of all the costs, expenses and capital investment necessary to operate the Sammis and Davis-Besse plants, as well as FES' costs related to its OVEC entitlement interest. The ESP IV PPA would provide a stable source of cash flow to FES over the term of the agreement, which would enhance FE and FES’ credit metrics, while providing Ohio customers a hedge against volatility and retail price increases through Rider RRS discussed above.

If, as further described above, the ESP IV PPA is denied or unable to be implemented resulting from current or future challenges before FERC or in the courts, the MWHs covered under the ESP IV PPA of approximately 15 to 25 million MWHs annually would be subject to current retail or wholesale market prices, which continue to be depressed, and could negatively and materially impact the future results of operations and financial condition of FES and FE.

CES continues to evaluate its overall generation business, including plant operations, capital investments, and operation and maintenance expenses, in light of the continued pressure on energy and capacity prices.

On average, CES has the capability to generate approximately 75 to 80 million MWHs of electricity annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar and FES' entitlement in OVEC. As a result of the ESP IV PPA discussed above, in 2017 and beyond, FES expects to hedge 70% - 80% of its generation output by targeting approximately 35 to 45 million MWHs in annual contract sales; selling 15 to 25 million MWHs in sales to the Ohio Companies under the ESP IV PPA; and maintaining up to 20 million MWHs as reserve margin. For the period April 1, 2016 to December 31, 2016, CES’ generation supply, including committed purchases, is 100% hedged against committed sales, including the ESP IV PPA and assuming normal weather conditions. Contractual sales obligations for the periods April 1, 2016 to December 31, 2016 and 2017 are approximately 59 million MWHs and 62 million MWHs, respectively.

On March 26, 2016, Davis-Besse shut down for scheduled refueling and maintenance. While the unit is offline, about a third of the unit's 177 fuel assemblies will be replaced. Preventative maintenance and safety inspections to ensure continued safe and reliable operations also will be performed on major components including various pumps, valves, reactor vessel, steam generators and the cooling tower.

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FINANCIAL OVERVIEW

(In millions, except per share amounts)	For the Three Months Ended March 31
	2016			2015			2016 vs 2015
REVENUES:	$	3,869		$	3,897		$	(28	)	(1	)%
OPERATING EXPENSES:
Fuel	381			513			(132		)	(26	)%
Purchased power	1,124			1,113			11			1	%
Other operating expenses	918			1,057			(139		)	(13	)%
Provision for depreciation	329			319			10			3	%
Amortization of regulatory assets, net	61			32			29			91	%
General taxes	280			269			11			4	%
Total operating expenses	3,093			3,303			(210		)	(6	)%
OPERATING INCOME	776			594			182			31	%
OTHER INCOME (EXPENSE):
Investment income	28			17			11			65	%
Interest expense	(288		)	(279		)	(9		)	3	%
Capitalized financing costs	25			34			(9		)	(26	)%
Total other expense	(235		)	(228		)	(7		)	3	%
INCOME BEFORE INCOME TAXES	541			366			175			48	%
INCOME TAXES	213			144			69			48	%
NET INCOME	$	328		$	222		$	106		48	%
EARNINGS PER SHARE OF COMMON STOCK:
Basic	$	0.78		$	0.53		$	0.25		47	%
Diluted	$	0.77		$	0.53		$	0.24		45	%

FirstEnergy’s net income in the first quarter of 2016 was $328 million, or basic earnings of $0.78 per share of common stock ($0.77 diluted), compared with $222 million, or basic and diluted earnings of $0.53 per share of common stock in the first quarter of 2015.

As further discussed below, FirstEnergy’s first quarter 2016 net income increased $106 million as compared to the first quarter of 2015, primarily resulting from a year-over-year improvement of $152 million at CES, partially offset by a $43 million decrease at Regulated Distribution.

During the first quarter of 2016, FirstEnergy’s revenues decreased $28 million as compared to the same period in 2015, resulting from a $131 million decrease at CES and a $41 million decrease at Regulated Distribution, partially offset by a $37 million increase at Regulated Transmission.

• The decrease in revenue at CES resulted from a 7 million MWHs decline in contract sales as the segment continues to align its sales to its generation, partially offset by higher wholesale sales, including increased capacity revenue associated with higher capacity auction prices.

• The decrease in revenue at Regulated Distribution resulted from lower volumes, primarily associated with lower weather-related usage and the impact of low spot market energy prices on wholesale generation sales, partially offset by the impact of net rate increases implemented in 2015 as a result of approved rate cases at certain operating companies.

• The increase in revenue at Regulated Transmission primarily reflected a higher rate base and recovery of incremental operating expenses.

Operating expenses decreased $210 million in the first quarter of 2016 as compared to the first quarter of 2015, reflecting a decrease at CES of $367 million, partially offset by increases at Regulated Distribution and Regulated Transmission of $17 million and $23 million, respectively. Changes in certain operating expenses include the following:

• Fuel expense declined $132 million, primarily at CES, resulting from lower economic dispatch of fossil units associated with low wholesale spot market energy prices, as well as lower unit prices on fuel contracts.

• Other operating expenses decreased $139 million, primarily reflecting a decrease at CES associated with mark-to-market gains on commodity contract positions and lower transmission expenses, partially offset by an increase at Regulated Distribution resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's March 31 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

• Amortization of regulatory assets, net increased $29 million, primarily reflecting the recovery of deferred costs, including storm costs and West Virginia vegetation management expenses, partially offset by the deferral of network transmission expenses.

FirstEnergy's other expenses increased $7 million, or 3%, year-over-year, primarily resulting from higher interest expense associated with higher average debt levels and lower capitalized financing costs, partially offset by higher investment income.

FirstEnergy’s effective tax rate was 39.4% in 2016 compared to 39.3% in 2015.

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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.

Summary of Results of Operations — First Three Months of 2016 Compared with First Three Months of 2015

Financial results for FirstEnergy’s business segments in the first three months of 2016 and 2015 were as follows:

First Three Months 2016 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,442		$	275		$	1,101		$	(46	)	$	3,772
Other	79			—			51			(33		)	97
Internal	—			—			152			(152		)	—
Total Revenues	2,521			275			1,304			(231		)	3,869
Operating Expenses:
Fuel	139			—			242			—			381
Purchased power	926			—			350			(152		)	1,124
Other operating expenses	648			36			321			(87		)	918
Provision for depreciation	169			43			102			15			329
Amortization of regulatory assets, net	59			2			—			—			61
General taxes	185			41			39			15			280
Total Operating Expenses	2,126			122			1,054			(209		)	3,093
Operating Income	395			153			250			(22		)	776
Other Income (Expense):
Investment income	11			—			15			2			28
Interest expense	(147		)	(43		)	(47		)	(51		)	(288		)
Capitalized financing costs	4			7			11			3			25
Total Other Expense	(132		)	(36		)	(21		)	(46		)	(235		)
Income (Loss) Before Income Taxes (Benefits)	263			117			229			(68		)	541
Income taxes (benefits)	98			43			85			(13		)	213
Net Income	$	165		$	74		$	144		$	(55	)	$	328

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First Three Months 2015 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	2,517		$	238		$	1,125		$	(45	)	$	3,835
Other	45			—			50			(33		)	62
Internal	—			—			260			(260		)	—
Total Revenues	2,562			238			1,435			(338		)	3,897
Operating Expenses:
Fuel	146			—			367			—			513
Purchased power	975			—			398			(260		)	1,113
Other operating expenses	597			35			519			(94		)	1,057
Provision for depreciation	172			37			96			14			319
Amortization of regulatory assets, net	29			3			—			—			32
General taxes	190			24			41			14			269
Total Operating Expenses	2,109			99			1,421			(326		)	3,303
Operating Income	453			139			14			(12		)	594
Other Income (Expense):
Investment income	13			—			12			(8		)	17
Interest expense	(144		)	(39		)	(48		)	(48		)	(279		)
Capitalized financing costs	8			14			10			2			34
Total Other Expense	(123		)	(25		)	(26		)	(54		)	(228		)
Income (Loss) Before Income Taxes (Benefits)	330			114			(12		)	(66		)	366
Income taxes (benefits)	122			42			(4		)	(16		)	144
Net Income (Loss)	$	208		$	72		$	(8	)	$	(50	)	$	222

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Changes Between First Three Months 2016 and First Three Months 2015 Financial Results	Regulated Distribution			Regulated Transmission			Competitive Energy Services			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
External
Electric	$	(75	)	$	37		$	(24	)	$	(1	)	$	(63	)
Other	34			—			1			—			35
Internal	—			—			(108		)	108			—
Total Revenues	(41		)	37			(131		)	107			(28		)
Operating Expenses:
Fuel	(7		)	—			(125		)	—			(132		)
Purchased power	(49		)	—			(48		)	108			11
Other operating expenses	51			1			(198		)	7			(139		)
Provision for depreciation	(3		)	6			6			1			10
Amortization of regulatory assets, net	30			(1		)	—			—			29
General taxes	(5		)	17			(2		)	1			11
Total Operating Expenses	17			23			(367		)	117			(210		)
Operating Income	(58		)	14			236			(10		)	182
Other Income (Expense):
Investment income	(2		)	—			3			10			11
Interest expense	(3		)	(4		)	1			(3		)	(9		)
Capitalized financing costs	(4		)	(7		)	1			1			(9		)
Total Other Expense	(9		)	(11		)	5			8			(7		)
Income (Loss) Before Income Taxes (Benefits)	(67		)	3			241			(2		)	175
Income taxes (benefits)	(24		)	1			89			3			69
Net Income	$	(43	)	$	2		$	152		$	(5	)	$	106

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Regulated Distribution — First Three Months of 2016 Compared with First Three Months of 2015

Regulated Distribution's net income decreased $43 million in the first three months of 2016 as compared to the same period of 2015, reflecting lower revenues, primarily resulting from lower weather-related volumes, partially offset by the impact of net rate increases implemented in 2015 as a result of approved rate cases at certain operating companies. Additionally, the Ohio Companies recognized $51 million in regulatory charges resulting from the PUCO's March 31 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

Revenues —

The $41 milliondecrease in total revenues resulted from the following sources:

	For the Three Months Ended March 31				Increase
Revenues by Type of Service	2016		2015		(Decrease)
	(In millions)
Distribution services	$	1,036	$	1,027	$	9
Generation sales:
Retail	1,135		1,180		(45		)
Wholesale	109		145		(36		)
Total generation sales	1,244		1,325		(81		)
Transmission sales:
Retail	138		127		11
Wholesale	24		38		(14		)
Total transmission sales	162		165		(3		)
Other	79		45		34
Total Revenues	$	2,521	$	2,562	$	(41	)

Distribution services revenues increased $9 million primarily resulting from approved base distribution rate increases in Pennsylvania, effective May 3, 2015, and MP and PE in West Virginia, effective February 25, 2015, partially offset by a distribution rate decrease at JCP&L, including the recovery of 2011 and 2012 storm costs, effective April 1, 2015. Partially offsetting this net rate increase was a decline in MWH deliveries, primarily resulting from lower weather-related usage, as described below. Additionally, distribution service revenues increased related to a surcharge increase in West Virginia associated with the recovery of vegetation management program costs, effective January 1, 2016. Distribution deliveries by customer class are summarized in the following table:

	For the Three Months Ended March 31
Electric Distribution MWH Deliveries	2016	2015	(Decrease)
	(In thousands)
Residential	14,336	16,562	(13.4	)%
Commercial	10,560	11,132	(5.1	)%
Industrial	12,377	12,740	(2.8	)%
Other	147	147	—	%
Total Electric Distribution MWH Deliveries	37,420	40,581	(7.8	)%

Lower distribution deliveries to residential and commercial customers primarily reflect decreased weather-related usage resulting from heating degree days that were 25% below 2015, and 11% below normal. Deliveries to industrial customers decreased 2.8%, as the increase from shale and petroleum customer usage was more than offset by a decrease from steel and coal mining customer usage.

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The following table summarizes the price and volume factors contributing to the $81 milliondecrease in generation revenues for the first three months of 2016 compared to the same period of 2015:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Effect of decrease in sales volumes	$	(137	)
Change in prices	92
	(45		)
Wholesale:
Effect of increase in sales volumes	6
Change in prices	(50		)
Capacity Revenue	8
	(36		)
Decrease in Generation Revenues	$	(81	)

The decrease in retail generation sales volumes was primarily due to a decrease in weather-related usage, as described above, as well as higher customer shopping in Ohio and Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWH deliveries increased to 79% from 78% for the Ohio Companies and 65% from 62% for the Pennsylvania Companies. The increase in retail generation prices primarily resulted from higher default service auction prices in the Pennsylvania Companies and an ENEC rate increase in West Virginia, effective January 1, 2016.

Wholesale generation revenues decreased $36 million in the first three months of 2016, as compared to the same period of 2015, primarily due to lower spot market energy prices, partially offset by higher wholesale sales and higher capacity prices. The difference between current wholesale generation revenues and certain energy costs incurred are deferred for future recovery or refund, with no material impact to earnings.

The increase in retail transmission revenues of $11 million was primarily due to an increase in the Ohio Companies' NMB transmission rider revenues. The NMB rider recovers network transmission integration service costs from all distribution customers at the Ohio Companies, with no material impact to earnings. The decrease in wholesale transmission revenues of $14 million primarily relates to lower congestion revenue.

Other revenues increased $34 million primarily related to a $25 million gain on the sale of oil and gas rights at WP.

Operating Expenses —

Total operating expenses increased $17 million primarily due to the following:

• Fuel expense decreased $7 million in the first three months of 2016, as compared to the same period of 2015, primarily related to lower economic dispatch resulting from low spot market energy prices.

• Purchased power costs decreased $49 million during the first three months of 2016, as compared to the same period of 2015, due to decreased volumes primarily reflecting lower weather-related usage and increased customer shopping, as described above, partially offset by higher capacity expense at MP.

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Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(14	)
Change due to volumes	38
	24
Purchases from affiliates:
Change due to increased unit costs	12
Change due to volumes	(120		)
	(108		)
Capacity Expense	14
Amortization of deferred costs	21
Decrease in Purchased Power Costs	$	(49	)

• Other operating expenses increased $51 million primarily due to:

• An increase of $51 million resulting from the recognition of economic development and energy efficiency obligations in accordance with the PUCO's March 31 Opinion and Order adopting and approving, with modifications, the Ohio Companies' ESP IV.

• Higher retirement benefit costs of $13 million.

• Lower transmission expenses of $11 million primarily related to lower congestion expenses at MP, partially offset by an increase in network transmission expenses at the Ohio Companies. The difference between current transmission revenues and transmission costs incurred are deferred for future recovery, resulting in no material impact on current period earnings.

• Net amortization of regulatory assets increased $30 million primarily due to:

• Recovery of storm costs in New Jersey, Pennsylvania, and West Virginia effective with the implementation of new rates as discussed above ($29 million),

• Recovery of West Virginia vegetation management program costs ($17 million), and

• Recovery of Pennsylvania legacy meter costs effective with the implementation of new rates as discussed above($8 million), partially offset by

• Higher deferral of Ohio network transmission expenses ($18 million).

• General taxes decreased $5 million primarily due to lower property taxes in Ohio, partially offset by higher revenue-related taxes in Pennsylvania.

Other Expense —

Other expense increased $9 million in the first three months of 2016 primarily due to lower capitalized financing costs as well as higher interest expense related to long-term debt issuances in 2015 at JCPL and WPP, the proceeds of which, in part, paid off short term borrowings.

Income Taxes —

Regulated Distribution’s effective tax rate was 37.3% and 37.0% for the first three months of 2016 and 2015, respectively.

Regulated Transmission — First Three Months of 2016 Compared with First Three Months of 2015

Net income increased $2 million in the first three months of 2016, compared to the same period of 2015, resulting from a higher rate base at ATSI, partially offset by lower capitalized financing costs and a lower ROE at ATSI under its FERC-approved comprehensive settlement related to ATSI's implementation of a "forward-looking" rate.

Revenues —

Total revenues increased $37 million principally due to higher revenue requirements at ATSI and TrAIL, reflecting recovery of incremental operating expenses and a higher rate base.

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

	For the Three Months Ended March 31				Increase
Revenues by Transmission Asset Owner	2016		2015		(Decrease)
	(In millions)
ATSI	$	134	$	96	$	38
TrAIL	62		61		1
PATH	3		4		(1		)
Utilities	76		77		(1		)
Total Revenues	$	275	$	238	$	37

Operating Expenses —

Total operating expenses increased $23 million principally due to higher property taxes and depreciation expense at ATSI, which are recovered through ATSI's formula rate.

Other Expense —

Other expense increased $11 million in the first three months of 2016 compared to the same period of 2015 primarily due to lower capitalized financing costs of $7 million resulting from lower construction work in progress balances at ATSI as well as increased interest expense resulting from debt issuances of $150 million at ATSI in Q4 of 2015, the proceeds of which, in part, paid off short-term borrowings.

Income Taxes —

Regulated Transmission’s effective tax rate was 36.8% and 36.8% for the first three months of 2016 and 2015, respectively. 

CES — First Three Months of 2016 Compared with First Three Months of 2015

Operating results increased $152 million in the first three months of 2016, compared to the same period of 2015, primarily from higher capacity revenue resulting from higher capacity auction prices. Additionally, operating results were impacted by mark-to-market gains on commodity contract positions and the absence of termination and settlement costs on coal contracts. Furthermore, lower sales volumes were offset by lower fuel, purchased power and transmission expenses.

Revenues —

Total revenues decreased $131 million in the first three months of 2016, compared to the same period of 2015, primarily due to lower sales volumes resulting from the continuation of CES' strategy to more effectively hedge its generation. Revenues were also impacted by higher capacity revenues and higher net gains on financially settled contracts, as further described below.

The decrease in total revenues resulted from the following sources:

	For the Three Months Ended March 31				Increase (Decrease)
Revenues by Type of Service	2016		2015
	(In millions)
Contract Sales:
Direct	$	206	$	393	$	(187	)
Governmental Aggregation	240		288		(48		)
Mass Market	49		98		(49		)
POLR	157		275		(118		)
Structured Sales	162		133		29
Total Contract Sales	814		1,187		(373		)
Wholesale	418		132		286
Transmission	21		66		(45		)
Other	51		50		1
Total Revenues	$	1,304	$	1,435	$	(131	)

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	For the Three Months Ended March 31		Increase (Decrease)
MWH Sales by Channel	2016	2015
	(In thousands)
Contract Sales:
Direct	3,794	7,249	(47.7	)%
Governmental Aggregation	3,569	4,598	(22.4	)%
Mass Market	703	1,435	(51.0	)%
POLR	2,552	4,822	(47.1	)%
Structured Sales	3,896	3,089	26.1	%
Total Contract Sales	14,514	21,193	(31.5	)%
Wholesale	1,913	63	2,936.5	%
Total MWH Sales	16,427	21,256	(22.7	)%

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	$	(188	)	$	1		$	—	$	—	$	(187	)
Governmental Aggregation	(65		)	17			—		—		(48		)
Mass Market	(50		)	1			—		—		(49		)
POLR	(130		)	12			—		—		(118		)
Structured Sales	35			(6		)	—		—		29
Wholesale	71			(16		)	70		161		286

The Direct, Governmental Aggregation and Mass Market customer base was 1.6 million as of March 31, 2016, compared to 2.0 million as of March 31, 2015, reflecting CES' strategy to more effectively hedge its generation. Although unit pricing was higher year-over-year in the Direct, Governmental Aggregation and Mass Market channels, the increase was primarily attributable to higher capacity expense as discussed below, which is a component of the retail price.

The decrease in POLR sales of $118 million was due to lower volumes, partially offset by higher rates associated with recent POLR auctions. Structured Sales increased $29 million primarily due to higher volumes, partially offset by the impact of lower market prices.

Wholesale revenues increased $286 million, primarily due to an increase in capacity revenue from higher capacity auction prices, an increase in short-term (net hourly position) transactions, and higher net gains on financially settled contracts, partially offset by lower spot market energy prices. Although wholesale short-term transactions increased year-over-year, low average spot market energy prices reduced the economic dispatch of fossil generating units, limiting additional wholesale sales.

Transmission revenue decreased $45 million in the first three months of 2016, as compared to the same period of 2015, primarily due to lower congestion revenue associated with less volatile market conditions.

Operating Expenses —

Total operating expenses decreased $367 million in the first three months of 2016 due to the following:

• Fuel costs decreased $125 million, primarily due to lower economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, as well as lower unit prices on fuel contracts. Additionally, fuel costs were impacted by the absence of settlement and termination costs on coal contracts recognized in the first quarter of 2015.

• Purchased power costs decreased $48 million due to lower volumes ($116 million), partially offset by higher unit prices ($24 million), and higher capacity expenses ($44 million). Lower volumes primarily resulted from lower contract sales as

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discussed above, partially offset by economic purchases, resulting from the low wholesale spot market price environment. Higher unit prices are primarily due to higher losses on financially settled purchased power contracts, partially offset by lower wholesale spot market prices in the first three months of 2016 as compared to 2015. The increase in capacity expense, which is a component of CES' retail price, was primarily the result of higher capacity rates associated with CES' retail sales obligations.

• Fossil operating costs increased $7 million, primarily due to increased outage costs.

• Nuclear operating costs decreased $11 million as a result of lower planned refueling outage costs. The refueling outage at Davis-Besse began March 26, 2016, while the refueling outage at Perry began on March 9, 2015.

• Retirement benefit costs increased $8 million.

• Transmission expenses decreased $118 million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first quarter of 2015, as well as lower load requirements.

• Other operating expenses decreased $85 million, primarily due to $65 million in mark-to-market gains on commodity contract positions and a decrease in retail-related costs.

• Depreciation expense increased $6 million as a result of a higher asset base.

Other Expense —

Total other income increased $5 million in the first three months of 2016, compared to the same period of 2015, primarily due to higher income on NDT investments and lower interest expense.

Income Taxes (Benefits) —

CES' effective tax rate was 37.1% and 33.3% for the first three months of 2016 and 2015, respectively. 

Corporate / Other — First Three Months of 2016 Compared with First Three Months of 2015

Financial results from other operating segments and reconciling items resulted in a nominal $5 million decrease in net income in the first three months of 2016 compared to the same period of 2015 primarily due to higher interest expense and a slightly lower effective tax rate on pre-tax losses.

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, 2016 and December 31, 2015, and the changes during the three months ended March 31, 2016:

Regulatory Assets (Liabilities) by Source	March 31, 2016			December 31, 2015			Increase (Decrease)
	(In millions)
Regulatory transition costs	$	166		$	185		$	(19	)
Customer receivables for future income taxes	364			355			9
Nuclear decommissioning and spent fuel disposal costs	(291		)	(272		)	(19		)
Asset removal costs	(382		)	(372		)	(10		)
Deferred transmission costs	123			115			8
Deferred generation costs	240			243			(3		)
Deferred distribution costs	325			335			(10		)
Contract valuations	187			186			1
Storm-related costs	390			403			(13		)
Other	157			170			(13		)
Net Regulatory Assets included on the Consolidated Balance Sheets	$	1,279		$	1,348		$	(69	)

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Regulatory assets that do not earn a current return totaled approximately $148 million as of March 31, 2016 and December 31, 2015, respectively, primarily related to storm damage costs.

As of March 31, 2016 and December 31, 2015, FirstEnergy had approximately $134 million and $116 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 payments, dividend payments, and contributions to its pension plan. In addition to internal sources to fund liquidity and capital requirements for 2016 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. FirstEnergy also expects to issue long-term debt at certain Utilities and certain other subsidiaries to, among other things, refinance short-term and maturing debt in the ordinary course, subject to market and other conditions.

Additionally, in 2016, FirstEnergy has minimum required funding obligations of$381 millionto its qualified pension plan, of which

$160 millionhas been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof, depending on, among other things, market conditions.

With the exception of Regulated Transmission's 2016 projected capital expenditures discussed below, planned 2016 capital expenditures for Regulated Distribution, CES, and Corporate/Other will be finalized upon further clarity regarding the ESP IV PPA and the complaints before FERC.

FirstEnergy's strategy is to focus on investments in its regulated operations. The centerpiece of this strategy is a $4.2 billion Energizing the Future investment plan that began in 2014 and will continue through 2017 to upgrade and expand FirstEnergy's transmission system. This program is focused on projects that enhance system performance, physical security and add operating flexibility and capacity starting with the ATSI system and moving east across FirstEnergy's service territory over time. Through 2015, FirstEnergy's capital expenditures under this plan were $2.4 billion and in 2016 capital expenditures under this plan are currently projected to be approximately $1 billion. In total, FirstEnergy has identified at least $15 billion in transmission investment opportunities across the 24,000 mile transmission system, making this a continuing platform for investment in the years beyond 2017.

In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments and the repositioning of the CES segment, FirstEnergy is also focused on improving the balance sheet over time consistent with its business profile, maintaining investment grade metrics at each business unit, and maintaining strong liquidity for an overall stable financial position. Specifically, at the regulated businesses, authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt.

Any financing plans by FirstEnergy, including the issuance of equity, 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 issuances, 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, 2016, 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, 2016, included the following:

Currently Payable Long-Term Debt	(In millions)
PCRBs supported by bank LOCs(1)	$	92
Unsecured notes	300
FMBs	395
Unsecured PCRBs(1)	420
Collateralized lease obligation bonds	23
Sinking fund requirements	89
Other notes	36
	$	1,355

⁽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.

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Short-Term Borrowings

FirstEnergy had $2,125 million and $1,708 million of short-term borrowings as of March 31, 2016 and December 31, 2015, respectively. FirstEnergy’s and FES' available liquidity as of March 31, 2016, was as follows:

Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	March 2019	$	3,500	$	1,369
FES / AE Supply	Revolving	March 2019	1,500		1,452
FET(2)	Revolving	March 2019	1,000		1,000
		Subtotal	$	6,000	$	3,821
		Cash	—		146
		Total	$	6,000	$	3,967

⁽¹⁾  FE and the Utilities.

⁽²⁾  Includes FET, ATSI and TrAIL.

Revolving Credit Facilities

FirstEnergy, FES/AE Supply and FET Facilities

FE and certain of its subsidiaries participate in three five-year syndicated revolving credit facilities with aggregate commitments of $6.0 billion (Facilities) expiring on March 31, 2019.

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, 2016:

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			—			—			500		(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			—			—			100		(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.

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The entire amount of the FES/AE Supply Facility, $600 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.

As of March 31, 2016, the borrowers were in compliance with the applicable debt to total capitalization ratios under the respective Facilities.

Term Loans

FE has a $1 billion variable 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 May 29, 2020. 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.

As of March 31, 2016, FE was in compliance with the applicable debt to total capitalization ratios under each of these term loans.

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 rates for borrowings in the first three months of 2016 were 0.80% per annum for the regulated companies’ money pool and 1.76% per annum for the unregulated companies’ money pool.

Pollution Control Revenue Bonds

As of March 31, 2016, FirstEnergy’s currently payable long-term debt included approximately $92 million (all 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, 2016 were issued by the following bank:

Bank	Aggregate Amount(1)		Termination Date	Reimbursements of Draws Due
	(In millions)
The Bank of Nova Scotia	$	92	March 2017	March 2017

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

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Long-Term Debt Capacity

FE's and its subsidiaries' access to capital markets and costs of financing are influenced by the credit ratings of their securities. The following table displays FE’s and its subsidiaries’ credit ratings as of March 31, 2016:

	Senior Secured		Senior Unsecured
Issuer	S&P	Moody’s	S&P	Moody’s	Fitch
FE	—	—	BB+	Baa3	BB+
FES	BBB-	—	BBB-	Baa3	—
AE Supply	BBB-	—	BBB-	Baa3	—
AGC	—	—	BBB-	Baa3	—
ATSI	—	—	BBB-	Baa2	—
CEI	BBB+	Baa1	BBB-	Baa3	—
FET	—	—	BB+	Baa3	—
JCP&L	—	—	BBB-	Baa2	—
ME	—	—	BBB-	Baa1	—
MP	BBB+	A3	—	—	—
OE	BBB+	A2	BBB-	Baa1	—
PN	—	—	BBB-	Baa2	—
Penn	—	A2	—	—	—
PE	BBB+	A3	—	—	—
TE	BBB+	Baa1	—	—	—
TrAIL	—	—	BBB-	A3	—
WP	BBB+	A2	—	—	—

Debt capacity is subject to the consolidated debt to total capitalization limits in the Facilities previously discussed. As of March 31, 2016, 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 of March 31, 2016, 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.

Changes in Cash Position

As of March 31, 2016, FirstEnergy had $146 million of cash and cash equivalents compared to $131 million of cash and cash equivalents as of December 31, 2015. As of March 31, 2016 and December 31, 2015, FirstEnergy had approximately $51 million and $82 million, respectively, of restricted cash included in Other Current Assets on the Consolidated Balance Sheets.

Cash Flows From Operating Activities

FirstEnergy's most significant sources of cash are derived from electric service provided by its utility operating subsidiaries and the sales of energy and related products and services by its unregulated competitive subsidiaries. The most significant use of cash from operating activities is to buy electricity in the wholesale market and pay fuel suppliers, employees, tax authorities, lenders, and others for a wide range of material and services.

Net cash provided from operating activities was $638 million during the first three months of 2016 compared with $193 million provided from operating activities during the first three months of 2015. Cash flows from operations increased $445 million in the first three months of 2016, compared with the same period of 2015, primarily due to the following:

• Distribution rate increases associated with the implementation of new rates, partially offset by a year-over-year decline in distribution deliveries primarily associated with lower weather-related usage;

• Higher transmission revenue, reflecting recovery of incremental operating expenses and a higher rate base;

• Higher capacity revenues at CES, partially offset by a decline in sales volume;

• Lower disbursements for fuel and purchased power resulting from the lower sales volumes; and

• Lower posted collateral.

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Cash Flows From Financing Activities

In the first three months of 2016, cash provided from financing activities was $242 million compared to $560 million of cash provided from financing activities during the first three months of 2015. The following table summarizes redemptions, repayments, short-term borrowings, and dividends:

	For the Three Months Ended March 31
Securities Issued or Redeemed / Repaid	2016			2015
	(In millions)
Redemptions / Repayments
Senior secured notes	$	(31	)	$	(48	)
Short-term borrowings, net	$	425		$	760
Common stock dividend payments	$	(152	)	$	(152	)

Cash Flows From Investing Activities

Cash used for investing activities in the first three months of 2016 principally represented cash used for property additions. The following table summarizes investing activities for the first three months of 2016 and the comparable period of 2015:

	For the Three Months Ended March 31
Cash Used for Investing Activities	2016			2015			Increase (Decrease)
	(In millions)
Property Additions:
Regulated Distribution	$	262		$	280		$	(18	)
Regulated Transmission	258			254			4
Competitive Energy Services	169			126			43
Corporate / Other	9			8			1
Nuclear fuel	149			60			89
Investments	(7		)	2			(9		)
Asset removal costs	34			28			6
Other	(9		)	(10		)	1
	$	865		$	748		$	117

Cash used for investing activities for the first three months of 2016 increased $117 million, compared to the same period of 2015, primarily due to increases in nuclear fuel and property additions. The increase in nuclear fuel was due to the scheduled Davis-Besse refueling and maintenance outage.

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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, 2016, was approximately $3.7 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)	$	33
Deferred compensation arrangements	543
Other(2)	15
	591
Subsidiaries’ Guarantees
Energy and Energy-Related Contracts(3)	248
FES’ guarantee of NG’s nuclear property insurance	96
FES' guarantee of nuclear decommissioning costs	21
FES’ guarantee of FG’s sale and leaseback obligations	1,767
	2,132
FE's Guarantees on Behalf of Business Ventures
Global Holding facility	300
Other Assurances
Surety Bonds - Wholly Owned Subsidiaries	402
Surety Bonds	22
FES' LOC (long-term tax-exempt debt)(4)	93
LOCs(5)	152
	669
Total Guarantees and Other Assurances	$	3,692

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

⁽²⁾  Includes guarantees of $4 million for nuclear decommissioning funding assurances, $6 million for railcar leases and $5 million for various leases.

⁽³⁾  Includes Energy and Energy-Related Contracts associated with FES of approximately $248 million.

⁽⁴⁾  Reflects the $1 million of interest coverage portion of LOCs issued in support of floating rate PCRBs with various maturities and the principal amount of floating-rate PCRBs of $92 million, all of which is reflected in currently payable long-term debt on FirstEnergy's consolidated balance sheets.

⁽⁵⁾  Includes $54 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities, $87 million issued in connection with energy and energy related contracts, $1 million issued in connection with railcar leases, $7 million pledged in connection with the sale and leaseback of Beaver Valley Unit 2 by OE and $3 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.

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Collateral and Contingent-Related Features

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

Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral.Based on FES' power portfolio exposures as ofMarch 31, 2016, FES has posted collateral of$180 million.The Regulated Distribution segment has posted collateral of$1 million.

These credit-risk-related contingent features, or the margining provisions within bilateral agreements, 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, which is the ability to secure additional collateral when needed, 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 that may be required under certain events as ofMarch 31, 2016:

Collateral Provisions	FES/ AE Supply (Tied to FE Corp. Rating)		FES/ AE Supply (Tied to FES Rating)		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	25	$	173	$	40	$	238
Non-Investment Grade Ratings (All Rating Agencies at or below BB+/Ba1)	$	25	$	200	$	40	$	265
Total Exposure from Contractual Obligations	$	25	$	341	$	40	$	406

Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment.As ofMarch 31, 2016, 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 would be required to post$3 million with affiliated parties.

Other Commitments and Contingencies

FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million. 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, continue to provide their joint and several guaranties of the obligations of Global Holding under the 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 under the current facility as collateral.

During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the Signal Peak mine to FG in exchange for FE extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million. See Note 6, Variable Interest Entities, for additional information regarding FEV's investment in Global Holding.

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,

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was $967 million as of March 31, 2016, 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.

As of March 31, 2016, FirstEnergy's leasehold interest was3.75%of Perry Unit 1,93.83%of Bruce Mansfield Unit 1 and2.60%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.

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 net commodity derivative assets and liabilities as of March 31, 2016 are summarized by year in the following table:

Source of Information- Fair Value by Contract Year	2016			2017		2018			2019			2020			Thereafter		Total
	(In millions)
Prices actively quoted(1)	$	(4	)	$	—	$	—		$	—		$	—		$	—	$	(4	)
Other external sources(2)	56			19		(15		)	(26		)	—			—		34
Prices based on models	(2		)	3		—			—			(8		)	—		(7		)
Total(3)	$	50		$	22	$	(15	)	$	(26	)	$	(8	)	$	—	$	23

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

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

⁽³⁾  Includes $(135) million in non-hedge derivative contracts that are primarily related to NUG contracts at certain of the Utilities. NUG contracts are subject to regulatory accounting and do not 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, 2016, not subject to regulatory accounting, an increase in commodity prices of 10% would decrease net income by approximately $22 million during the next 12 months.

Equity Price Risk

As of March 31, 2016, the FirstEnergy pension plan assets were allocated approximately as follows: 40% in equity securities, 40% in fixed income securities, 6% in absolute return strategies, 11% 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, 2016, FirstEnergy made a $160 million contribution to its qualified pension plan. See Note 3, Pension 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, 2016, FirstEnergy's pension plan assets earned approximately 4.70% as compared to an annual expected return on plan assets of 7.50%.

NDT funds have been established to satisfy NG’s and other FirstEnergy subsidiaries' nuclear decommissioning obligations. As of March 31, 2016, approximately 67% of the funds were invested in fixed income securities, 26% of the funds were invested in equity securities and 7% were invested in short-term investments, with limitations related to concentration and investment grade ratings. The investments are carried at their market values of approximately $1,578 million, $628 million and $160 million for fixed income securities, equity securities and short-term investments, respectively, as of March 31, 2016, excluding $(6) million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $63 million reduction in fair value as of March 31, 2016. Certain FirstEnergy subsidiaries recognize in earnings the unrealized losses on AFS

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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, 2016, 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, 2016.

CREDIT RISK

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

Wholesale Credit Risk

FirstEnergy and FES measure 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 and FES have a legally enforceable right of offset. FirstEnergy and FES monitor and manage 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. The majority of FirstEnergy's and FES' energy contract counterparties maintain investment-grade credit ratings.

Retail Credit Risk

FirstEnergy's and FES' principal retail credit risk exposure relates to CES' 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 and FES' 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

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by the MDPSC and a third party monitor.Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC.PE recovers its costs plus a return for providing SOS.

The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years.PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014.The costs of the 2015-2017 plan are expected to be approximately$66 million for that three-year period, of which $26 million was incurred through March 2016. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%. PE continues to recover program costs subject to a five-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.On January 28, 2016, PE filed a request to increase plan spending by$2 millionin order to reach the new goals for 2017 set in the July 16, 2015 order.

On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the Maryland electric utilities to submit analyses 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 required 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's responsive filings 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 require 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.On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting.The Staff of the MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost.The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters.

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 is comprised oftwocomponents, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU.OneBGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers.The second BGS component provides a fixed price service and 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.

Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and financial components and is expected to take approximately one year to complete.

In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using afive-year look back from the beginning of the test year; (ii) allocating savings with75%retained by the company and25%allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation.On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding.Briefing has been completed, and oral argument has not yet been scheduled.

In April 2016, JCP&L intends to file tariffs with the NJBPU proposing a general rate increase associated with its distribution operations that seeks to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses.The filing will request approval to increase annual operating revenues by approximately$142.1 millionbased upon a hybrid test year for the twelve months ending June 30, 2016. JCP&L will request that the new rates take effect in January 2017.

On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. The procedural schedule was suspended while the NJBPU considers a motion on a legal issue regarding whether MAIT can be designated as a "public utility" in New Jersey.On February 24, 2016, the NJBPU issued an Order concluding that MAIT does not satisfy the “electricity distribution” element necessary for “public utility” status because MAIT would not own any electric distribution assets in New Jersey. On April 22, 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certain JCP&L distributions assets in the transfer to satisfy the "electricity distribution" element necessary for "public utility" status in accordance with the NJBPU’s February 24, 2016 order. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.

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OHIO

The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016.The material terms of ESP 3 include:

• A base distribution rate freeze through May 31, 2016;

• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

• Economic development and assistance to low-income customers for thetwo-year plan period at levels established in the prior 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);

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

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

• A commitment not to recover from retail customers certain costs related to transmission cost allocations 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 FERC proceedings;

• 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, Ohio's renewable energy and energy efficiency standard, 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.

Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy Council and the ELPC.The oral argument in this matter occurred on January 6, 2016.

The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's Progress.The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and recommendations on May 28, 2015, and June 4, 2015.On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and Recommendation, which included PUCO Staff as a signatory party in addition to other signatories.

The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:

• Aneight-year term (June 1, 2016 - May 31, 2024);

• Contemplates continuing a base distribution rate freeze through May 31, 2024;

• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through aneight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

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

• Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows:$10 million in year five,$20 millionin year six,$30 millionin year seven and$40 millionin year eight;

• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of thefive-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals$360 million, including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings;

• Potential procurement of100 MWof new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;

• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;

• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016);

• A goal across FirstEnergy to reduce CO₂ emissions by90%below 2005 levels by 2045;

• A contribution of$3 millionper year ($24 millionover theeight-year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory;

• Contributions of $2.4 millionper year ($19 millionover the eight-year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and

• A contribution of$1 millionper year ($8 millionover theeight-year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio.

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On March 31, 2016, the PUCO issued an Opinion and Order adopting and approving, with modifications, the Ohio Companies’ ESP IV. Changes arising from the approval of ESP IV will go into effect on June 1, 2016.The PUCO’s modifications of ESP IV, among others, included:

• Limiting average customer bill amounts for the firsttwoyears of the plan, subject to certain exceptions, and permitting deferral for the second year;

• Prohibiting recovery of retirement costs of the ESP IV PPA Facilities through Rider RRS;

• Assigning the burden of capacity performance penalties incurred by the ESP IV PPA Facilities to the Ohio Companies, rather than customers, and to provide that all capacity performance bonuses earned by the ESP IV PPA Facilities be retained by the Ohio Companies, rather than customers; and

• Providing for the modification of the severability provision previously included in ESP IV, to also address potential future PJM Tariff or rule changes prohibiting the Ohio Companies from offering output of the ESP IV PPA Facilities into PJM auctions.

Applications for Rehearing may be filed within thirty days of the issuance of the March 31, 2016 Opinion and Order.

On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies that requests FERC review the ESP IV PPA under Section 205 of the FPA. FES and the Ohio Companies responded to the complaint on February 23, 2016 and March 9, 2016. In a separate proceeding on March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint asks that FERC issue an order by May 1, 2016, so the revised rule can be in effect for the May 2016 PJM capacity auction. The Ohio Companies responded to the complaint on April 11, 2016 and April 20, 2016. In addition to such proceedings, opponents have expressed an intention to challenge in the courts and/or before FERC, the ESP IV PPA or PUCO's approval of the ESP IV. Management intends to vigorously defend against such challenges. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016.

Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of2,266GWHs in 2015 and2,288GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative amendments to the energy efficiency standards discussed below.The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional0.75%thereafter through 2020, subject to legislative amendments to the peak demand reduction standards discussed below.

On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy mandates, recommending that the current level of mandates remain in place indefinitely.The report also recommended: (i) an expedited process for review of utility proposed energy efficiency plans; (ii) ensuring maximum credit for all of Ohio's Energy Initiatives; (iii) a switch from energy mandates to energy incentives; and (iv) a declaration be made that the General Assembly may determine energy policy of the state. No legislation has yet been introduced to change the standards described above.

On September 24, 2014, the Ohio Companies filed an amendment to their energy efficiency portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB310.On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio plan.Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters specified in those applications and the matter remains pending before the PUCO.

On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019.The plans as proposed comply with benchmarks contemplated by SB310 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities.The Ohio Companies anticipate the cost of the plans will be approximately$323 millionover the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms.

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, which is still pending.The matter has not been scheduled for oral argument.

Ohio law 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 2026, subject to legislative amendments discussed above, except 2015 and 2016 that remain at the 2014 level.The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements.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.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 certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of$43.4 million, plus interest, on the basis that the Ohio Companies did not prove such

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purchases were prudent.On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted.On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order.The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded.The matter is not yet scheduled for oral argument.

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. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, 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 spot market purchases, quarterly descending clock auctions for 3, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn.

On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery period, which would provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the proposed programs, the supply would be provided by wholesale suppliers though a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. In addition, the proposal includes modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges.A hearing was held on February 25, 2016.A Joint Petition for Settlement resolving all issues was filed on April 1, 2016, which is subject to PPUC approval.

Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs.The Pennsylvania Companies' Phase II EE&C Plans are effective through May 31, 2016.Total Phase II costs of these plans are expected to be approximately$175 millionand recoverable through the Pennsylvania Companies' reconcilable EE&C riders.On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at1.8%for ME, 1.7% for Penn, 1.8% for WP, and 0%for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at4.0% for ME, 3.9%for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies filed their Phase III EE&C plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint settlement resolving all issues, which was subject to PPUC approval.On March 10, 2016, the PPUC entered an Opinion and Order approving the settlement and directing that the Pennsylvania Companies modify certain cost recovery methodologies to describe the allocation of EE&C Phase III common costs among customer classes and to describe the recovery of remaining costs of their Phase II EE&C Plans. None of the parties to the joint settlement elected to withdraw from the joint settlement due to the modifications.

Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval.Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC.On October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five-year period of 2016 to 2020 for the following costs: WP$88.34 million; PN$56.74 million; Penn$56.35 million; and ME$43.44 million. These amounts include all qualifying distribution capital additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania Companies as discussed below. On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. The DSIC riders are expected to be effective July 1, 2016.Various parties have filed interventions, answers, or complaints with the PPUC in response to the Pennsylvania Companies’ request for approval of the DSIC filings raising cost allocation and other issues, and the Pennsylvania Companies have responded.

In April 2016, each of the Pennsylvania Companies intends to file tariffs with the PPUC proposing general rate increases associated with their distribution operations that will benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.The filings will request approval to increase annual operating revenues by approximately$140.2 millionat ME,$158.8 millionat PN,$42.0 millionat Penn, and$98.2 millionat WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. The new rates are expected to take effect in January 2017.

On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.On March 4, 2016, a Joint Petition for Full Settlement was submitted to the PPUC for consideration and approval. On April 18, 2016, the ALJs issued an Initial Decision approving the Joint Petition for Full Settlement without modifications.A final decision from the

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PPUC is expected by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually.

MP and PE filed with the WVPSC on March 31, 2016 their Phase II energy efficiency program proposal for approval.MP and PE are proposing three energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of0.5%of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP.The costs for the program are expected to be$9.9 millionwhich would be recovered through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year.MP and PE are requesting WVPSC approval by October 1, 2016 so MP and PE can implement the programs beginning January 1, 2017.

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, NG, 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 occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC.Moreover, it is clear that 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 electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows.

FERC MATTERS

Ohio ESP IV PPA

For information regarding matters before FERC related to the ESP IV PPA between FES and the Ohio Companies, see “Regulatory Matters - Ohio” above.

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 advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM.This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit.On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines.The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole.The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings.Settlement discussions under a FERC-appointed settlement judge are ongoing.

In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent “right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of PJM’s RTEP process.FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether FirstEnergy and the PJM transmission owners have a "right of first refusal" is scheduled for oral argument on May 4, 2016, before the U.S. Court of Appeals for the D.C. Circuit in an appeal of FERC's order approving PJM's Order No.1000 compliance filing.

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

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RTO Realignment

On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM.While many of the matters involved with the move have been resolved, FERC denied recovery under 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 demonstrating net benefits to customers from the transfer to PJM.Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, 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 March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.

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 before FERC and certain United States appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which is pending at FERC.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.On a related issue, FirstEnergy joined certain other PJM transmission owners in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region.On January 22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent.Certain PJM transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP export charge on transactions into PJM was correct and should be re-affirmed on remand.The briefs and replies thereto remain before FERC for consideration.

In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone.The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under PJM Transmission Rates.

The outcome of the proceedings that address the remaining open issues related to costs for the "Michigan Thumb" transmission project and "legacy RTEP" transmission projects cannot be predicted at this time.

Transfer of Transmission Assets to MAIT

On June 10, 2015, MAIT, a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the purposes of owning and operating all FERC-jurisdictional transmission assets of JCP&L, ME and PN following the receipt of all necessary state and federal regulatory approvals.On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT.Additionally, the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way associated with the utilities' transmission assets; (ii) a Mutual Assistance Agreement; (iii) MAIT being deemed a public utility under state law; (iv) MAIT's participation in FE's regulated companies' money pool; and (v) certain affiliated interest agreements. If approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL.MAIT's transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities under the PJM Tariff.FERC approved the transaction on February 18, 2016. Upon receipt of all applicable regulatory approvals with respect to the transfer,MAIT expects to file a Section 204 application with FERC, and other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their respective contributions, and to issue debt.MAIT will also make a Section 205 formula rate application with FERC to establish its transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.

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 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.The California parties appealed FERC's decision back to the Ninth Circuit.AE Supply joined with other intervenors in the case and filed a brief in support of FERC's dismissal of the case.On April 29, 2015, the Ninth Circuit remanded the case to FERC for further proceedings.On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.Settlement discussions under a FERC-appointed settlement judge are ongoing. On March 1, 2016, FERC issued an order on rehearing clarifying the scope of the evidentiary

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hearing and the standard of review on remand. In particular, FERC clarified that certain bilateral transactions, including those of AE Supply to the California parties, are protected by the Mobile-Sierra standard, which requires a demonstration of harm to the public interest to determine liability and obligation to make refunds. The California parties requested rehearing of FERC’s March 1, 2016 order, and also appealed FERC’s November 3, 2015, and March 1, 2016 orders to the Ninth Circuit, which has stayed its review pending the outcome of the ongoing proceeding discussed above.

In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a 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 and other parties filed motions to dismiss, which FERC granted.The California Attorney General 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.

The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.

PATH Transmission Project

On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland which PJM had previously suspended in February 2011.As a result of PJM canceling the project, 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.PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of10.9%(10.4%base plus0.5%for RTO membership) from PJM customers overfiveyears.FERC issued an order denying the0.5%ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to settlement proceedings and hearing if the parties could not agree to a settlement.On March 24, 2014, the FERC Chief ALJ terminated settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531, discussed below, to the PATH proceeding.On September 14, 2015, the ALJ issued his initial decision, disallowing recovery of certain costs. The initial decision and exceptions thereto remain before FERC for review and a final order.FirstEnergy continues to believe the costs are recoverable, subject to final ruling from FERC.

FERC Opinion No. 531

On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow element of FERC’s ROE methodology, and announced the potential for a qualitative adjustment to the ROE methodology results.Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight); and (b) a long-term dividend growth forecast based on a forecast for the U.S. economy (1/3 weight).Regarding the qualitative adjustment, for single-utility rate cases FERC formerly pegged ROE at the median of the “zone of reasonableness” that came out of the ROE formula, whereas going forward, FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level sufficient to attract future investment.On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE methodology to certain ISO New England transmission owners, andon March 3, 2015, FERC issued Opinion No. 531-B affirming its prior rulings.Appeals of Opinion Nos. 531, 532-A and 531-B are pending before the U.S. Court of Appeals for the D.C. Circuit.FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities and the cost-of-service wholesale power generation transactions of MP.

MISO Capacity Portability

On June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM.FirstEnergy and other parties submitted filings arguing that MISO's concerns largely are without foundation,FERC did not mandate a solution in response to MISO's concerns.At FERC's direction, in May, 2015, PJM, MISO, and their respective independent market monitors provided additional information on their various joint issues surrounding the PJM/MISO seam to assist FERC's understanding of the issues and what, if any, additional steps FERC should take to improve the efficiency of operations at the PJM/MISO seam.Stakeholders, including FESC on behalf of certain of its affiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions.The various submissions and responses remain before FERC for consideration.

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.

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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.

Clean Air Act

FirstEnergy complies with SO₂and NOx emission 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.

CSAPR requires reductions of NOx and SO₂emissions intwophases (2015 and 2017), 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.The U.S. Court of Appeals for the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia.This follows the 2014 U.S. Supreme Court ruling generally upholding EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states.EPA proposed a CSAPR update rule on November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017.Depending on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result.

EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of75PPB to70PPB on October 1, 2015.EPA stated the vast majority of U.S. counties will meet the new70PPB standard by 2025 due to other federal and state rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017.States will then have roughlythreeyears to develop implementation plans to attain the new 2015 ozone NAAQS.Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result.

MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant.FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately$345 million(CES segment of$168 millionand Regulated Distribution segment of$177 million), of which$226 millionhas been spent through March 31, 2016 ($96 millionat CES and$130 millionat Regulated Distribution).

On August 3, 2015, FG, a subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure that excuses FG’s performance under its coal transportation contract with these parties.Specifically, the dispute arises from a contract for the transportation by BNSF and CSX of a minimum of3.5 milliontons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, those plants were deactivated by April 16, 2015.In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance.Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages including, but not limited to, lost profits under the contract through 2025.As part of its statement of claim, a right to liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearings. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused.FirstEnergy and FES intend to vigorously assert their position in the arbitration proceedings.If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.FirstEnergy and FES are unable to estimate the loss or range of loss.

FG is also a party to another coal transportation contract covering the delivery of 2.5 milliontons annually through 2025, a portion of which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS.FG has asserted a defense of force majeure in response to delivery shortfalls to such plant under this contract as well.If FirstEnergy and FES fail to reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.FirstEnergy and FES are unable to estimate the loss or range of loss.

As to both coal transportation agreements referenced above, FES paid in settlement approximately$70 millionin liquidated damages for delivery shortfalls in 2014 related to its deactivated plants.

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As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015.In response to notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the termination.This matter is currently in the discovery phase of litigation and no trial date has been established. There are approximately 5.5 milliontons remaining under the contract for delivery.At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going litigation with respect to this agreement.

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.The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs.On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued 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.On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009.FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.

Climate Change

FirstEnergy has established a goal to reduce CO₂ emissions by90%below 2005 levels by 2045.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 reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants.The EPA released its final regulations in August 2015, to reduce CO₂emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO₂emission rate goals.The EPA’s CPP allows states to request atwo-year extension to finalize SIPs by September 6, 2018.If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs.The EPA also finalized separate regulations imposing CO₂emission limits for new, modified, and reconstructed fossil fuel fired electric generating units.On June 23, 2014, the United States Supreme Court decided that CO₂or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies.Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015.On January 21, 2015, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument.On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court.Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020.The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris.The Paris Agreement must be ratified by at least 55 countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below two degrees Celsius become effective.FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.The CO₂ emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system.FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's

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cooling water intake system.Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be substantial.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.The treatment obligations will phase-in as permits are renewed on afive-year cycle from 2018 to 2023.The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits.Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result.

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 the appeal or estimate the possible loss or range of loss.

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

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act.Certain coal 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 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants.Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs.Although unexpected, changes in timing and closure plan requirements in the future could impact our asset retirement obligations significantly.

Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016 and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG 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 CCRs, 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 disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal options will be sufficient for the ongoing operation of the plant.On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR.On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility.

FirstEnergy or its subsidiaries 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 Sheets as ofMarch 31, 2016based 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$123 millionhave been accrued throughMarch 31, 2016. Included in the total are accrued liabilities of approximately$87 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 loss 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, 2016, FirstEnergy had approximately$2.4 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 NDTs 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 NDTs.FE and FES have also entered into a total of$24.5 millionin parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years.On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue operation through April 22, 2037.Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record and admit a contention on the NRC’s Continued Storage Rule.On August 6, 2015, this intervenor sought review of the NRC Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC intervened in that proceeding.

As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011.These inspections revealed that the cracking condition had propagated a small amount in select areas.FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking.The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance.FENOC plans to submit a license amendment application related to the Shield Building analysis in 2016.

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 FirstEnergy's nuclear facilities.

Other Legal Matters

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.

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NEW ACCOUNTING PRONOUNCEMENTS

In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded.In August 2015, the FASB issued a final ASU deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date). In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)", clarifying the principal versus agent implementation guidance in the following areas: unit of account at which the principal/agent determination is made; applying the control principle to certain types of transactions and the control principle and principal/agent indicators.In April 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, clarifying the identification of performance obligations and the licensing implementation guidance.The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards.

In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated.A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries. See Note 6, Variable Interest Entities, for additional information.

In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified$93 million and $17 millionof debt issuance costs included in Deferred Charges and Other Assets to Long-term Debt and Other Long-term Obligations. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset.

In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets.In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required.The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

Additionally, in March of 2016, the FASB issued the following ASUs:

• ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”,

• ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and

• ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”.

FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

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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, NG and AE Supply, as well as the output relating to leasehold interests of OE and TE in certain of those facilities that are subject to sale and leaseback arrangements, and pursuant to full output, cost-of-service PSAs.

FES’ revenues are derived primarily from sales to individual retail customers, sales to customers in the form of governmental aggregation programs, and participation in affiliated and non-affiliated POLR auctions. FES’ sales are primarily concentrated in Ohio, Pennsylvania, Illinois, Michigan, New Jersey and Maryland. The demand for electricity produced and sold by FES, along with the price of that electricity, is principally impacted by conditions in competitive power markets, global economic activity as well as economic activity and weather conditions in the Midwest and Mid-Atlantic regions of the United States.

Following the PUCO’s March 31, 2016, Order and Opinion, approving, with modification, the Ohio Companies’ ESP IV as discussed above, FES entered into the ESP IV PPA with the Ohio Companies on April 1, 2016. The ESP IV PPA has an eight-year term whereby FES will sell all the output of the ESP IV PPA Facilities, which represents 3,241 MWs of generating capacity, to the Ohio Companies, beginning June 1, 2016. In exchange for the rights to this output, the Ohio Companies will pay FES a negotiated rate consisting of all the costs, expenses and capital investment necessary to operate the Sammis and Davis-Besse plants, as well as FES' costs related to its OVEC entitlement interest. The ESP IV PPA would provide a stable source of cash flow to FES over the term of the agreement, which would enhance FE and FES’ credit metrics, while providing Ohio customers a hedge against volatility and retail price increases through Rider RRS. Certain parties have filed complaints and expressed intention to challenge in the courts and/or before FERC, the ESP IV PPA. See FirstEnergy’s Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information with respect to the ESP IV PPA.

If, as further described above, the ESP IV PPA is denied or unable to be implemented resulting from current or future challenges before FERC or in the courts, the MWHs covered under the ESP IV PPA of approximately 15 to 25 million MWHs annually would be subject to current retail or wholesale market prices, which continue to be depressed, and could negatively and materially impact the future results of operations and financial condition of FES.

FES continues to evaluate its overall generation business, including plant operations, capital investments, and operation and maintenance expenses, in light of the continued pressure on energy and capacity prices.

Through its own facilities and purchased power agreements with affiliates described above, FES has the capability to produce approximately 75 to 80 million MWHs of electricity annually, with up to an additional five million MWHs available from purchased power agreements for wind, solar and FES' entitlement in OVEC. As a result of the ESP IV PPA discussed above, in 2017 and going forward, FES expects to hedge 70% - 80% of its generation output by targeting approximately 35 to 45 million MWHs in annual contract sales; selling 15 to 25 million MWHs to the Ohio Companies under the ESP IV PPA; and maintaining up to 20 million MWHs as reserve margin. For the period April 1, 2016 to December 31, 2016, FES’ generation supply, including committed purchases, is 100% hedged against committed sales, including the ESP IV PPA and assuming normal weather conditions. Contractual sales obligations for the periods April 1, 2016 to December 31, 2016 and 2017 are approximately 59 million MWHs and 62 million MWHs, respectively.

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 DR 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.

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: FirstEnergy's Business, Executive Summary, Capital Resources and Liquidity, Guarantees and Other Assurances, Off-Balance Sheet Arrangements, Market Risk Information, Credit Risk and Outlook.

Results of Operations

Operating results increased $134 million in the first three months of 2016, compared to the same period of 2015, primarily from higher capacity revenue resulting from higher capacity auction prices. Additionally, operating results were impacted by mark-to-market gains on commodity contract positions and the absence of a gain recognized in the first quarter of 2015 associated with the

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elimination of an obligation under an existing coal contract. Furthermore, lower sales volumes were offset by lower fuel, purchased power and transmission expenses.

Revenues -

Total revenues decreased$178 million, in the first three months of 2016, compared to the same period of 2015, primarily due to lower sales volumes resulting from the continuation of FES' strategy to more effectively hedge its generation. Revenues were also impacted by higher capacity revenues and higher net gains on financially settled contracts, as further described below.

The change in total revenues resulted from the following sources:

	Three Months Ended March 31				Increase
Revenues by Type of Service	2016		2015		(Decrease)
	(In millions)
Contract Sales:
Direct	$	206	$	393	$	(187	)
Governmental Aggregation	240		288		(48		)
Mass Market	49		98		(49		)
POLR	157		275		(118		)
Structured Sales	155		125		30
Total Contract Sales	807		1,179		(372		)
Wholesale	328		92		236
Transmission	19		59		(40		)
Other	45		47		(2		)
Total Revenues	$	1,199	$	1,377	$	(178	)

	Three Months Ended March 31		Increase
MWH Sales by Channel	2016	2015	(Decrease)
	(In thousands)
Contract Sales:
Direct	3,794	7,249	(47.7	)%
Governmental Aggregation	3,569	4,598	(22.4	)%
Mass Market	703	1,435	(51.0	)%
POLR	2,552	4,822	(47.1	)%
Structured Sales	3,779	2,955	27.9	%
Wholesale	363	—	—
Total MWH Sales	14,760	21,059	(29.9	)%

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The following table summarizes the price and volume factors contributing to changes in revenues in the first three months of 2016 compared with the same period of 2015:

	Source of Change in Revenues
	Increase (Decrease)
MWH Sales Channel:	Sales Volumes			Prices			Gain on Settled Contracts		Capacity Revenue		Total
	(In millions)
Direct	$	(188	)	$	1		$	—	$	—	$	(187	)
Governmental Aggregation	(65		)	17			—		—		(48		)
Mass Market	(50		)	1			—		—		(49		)
POLR	(130		)	12			—		—		(118		)
Structured Sales	35			(5		)	—		—		30
Wholesale	10			—			70		156		236

The Direct, Governmental Aggregation and Mass Market customer base was 1.6 million as of March 31, 2016, compared to 2.0 million as of March 31, 2015, reflecting FES' strategy to more effectively hedge its generation. Although unit pricing was higher year-over-year in the Direct, Governmental Aggregation and Mass Market channels, the increase was primarily attributable to higher capacity expense as discussed below, which is a component of the retail price.

The decrease in POLR sales of $118 million was due to lower volumes, partially offset by higher rates associated with recent POLR auctions. Structured Sales increased $30 million primarily due to higher volumes, partially offset by the impact of lower market prices.

Wholesale revenues increased $236 million, primarily due to an increase in capacity revenue from higher capacity auction prices, higher net gains on financially settled contracts and an increase in short-term (net hourly position) transactions. Although wholesale short-term transactions increased year-over-year, low average spot market energy prices reduced the economic dispatch of fossil generating units, limiting additional wholesale sales.

Transmission revenue decreased$40 million in the first three months of 2016, as compared to the same period of 2015, primarily due to lower congestion revenue associated with less volatile market conditions.

Operating Expenses -

Total operating expenses decreased$392 million in the first three months of 2016 compared to the same period of 2015.

The following table summarizes the factors contributing to the changes in fuel and purchased power costs in the first three months of 2016 compared with the same period of 2015:

	Source of Change
	Increase (Decrease)
Operating Expense	Volumes			Prices			Loss on Settled Contracts		Capacity Expense		Total
	(In millions)
Fossil Fuel	$	(66	)	$	(7	)	$	12	$	—	$	(61	)
Nuclear Fuel	(1		)	(3		)	—		—		(4		)
Affiliated Purchased Power	(2		)	(9		)	23		—		12
Non-affiliated Purchased Power	(204		)	(48		)	42		44		(166		)

Fossil and nuclear fuel costs decreased$65 million, primarily due to lower economic dispatch of fossil units resulting from low wholesale spot market energy prices, as described above, as well as lower unit prices on fuel contracts. Additionally, fuel costs were impacted by the absence of a $12 million gain recognized in the first quarter of 2015 associated with the elimination of an obligation under an existing coal contract.

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Affiliated purchased power costs increased $12 million, primarily associated with net losses on financially settled contracts with AE Supply resulting from lower wholesale spot market prices in the first three months of 2016, as compared to the same period of 2015.

Non-affiliated purchased power costs decreased $166 million due to lower volumes ($204 million) and lower prices, net of financials ($6 million), partially offset by higher capacity expenses ($44 million). Lower volumes primarily resulted from lower contract sales as discussed above, partially offset by economic purchases resulting from the low wholesale spot market price environment. The increase in capacity expense, which is a component of FES' retail price, was primarily the result of higher capacity rates associated with FES' retail sales obligations.

Other operating expenses decreased$173 million in the first three months of 2016, compared to the same period of 2015, primarily due to the following:

• Nuclear operating costs decreased $11 million as a result of lower planned refueling outage costs. The refueling outage at Davis-Besse began March 26, 2016, while the refueling outage at Perry began on March 9, 2015.

• Retirement benefit costs increased $8 million.

• Transmission expenses decreased $101million, primarily due to lower congestion and market-based ancillary costs associated with less volatile market conditions as compared to the first quarter of 2015, as well as lower load requirements.

• Other operating expenses decreased $71 million, primarily due to $65 million in mark-to-market gains on commodity contract positions and a decrease in retail-related costs.

Other Expense —

Total other income increased $4 million in the first three months of 2016, compared to the same period of 2015, primarily due to higher income on NDT investments and lower interest expense.

Income Taxes (Benefits) —

FES' effective tax rate for the three months ended March 31, 2016 and 2015 was 38.5% and 40.0%, respectively.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Market Risk Information” in Item 2 above.

ITEM 4. CONTROLS AND PROCEDURES

(a) Evaluation of Disclosure Controls and Procedures

The management of FirstEnergy and FES, with the participation of each registrant's chief executive officer and chief financial officer, have reviewed and evaluated the effectiveness of the registrant's disclosure controls and procedures, as defined in the Securities Exchange Act of 1934, as amended, Rules 13a-15(e) and 15d-15(e), as of the end of the period covered by this report. Based on that evaluation, the chief executive officer and chief financial officer of FE and FES have concluded that their respective registrant's disclosure controls and procedures were effective as of the end of the period covered by this report.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2016, 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

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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

In addition to the other information set forth in this report including, without limitation, the below revised risk factor, the reader should carefully consider the factors discussed in "Item 1A. Risk Factors" in the Registrants' Annual Report on Form 10-K for the year ended December 31, 2015, which could materially affect the Registrants' business, financial condition or future results.

Should there be a Subsequent Modification or Amendment to, Denial of, or Delay in the Effectiveness of, the PUCO Order Approving ESP IV or if the ESP IV PPA is Invalidated, Terminated, Substantially Modified or the Effectiveness thereof is otherwise Substantially Impaired or Delayed, then in either Case, there may be a Material and Adverse Impact to the Credit Ratings, Results of Operations and Financial Condition of FE and FES

On March 31, 2016, the PUCO approved, with modifications, the Ohio Companies ESP IV entitled Powering Ohio's Progress that contemplates continuing a base distribution rate freeze and includes continuing their Rider DCR mechanism and competitive bidding process for non-shopping load and to undertake and implement an Economic Stability Program provision, which is designed to provide customers retail rate stability against market prices over a longer term. However, the PUCO’s order approving the ESP IV remains subject to rehearing by the PUCO and appeal to the Supreme Court of Ohio. Any subsequent amendment or modification to, denial of, or delay in the effectiveness of, the PUCO’s order approving the ESP IV could impose risks on our operations and materially and adversely impact the credit ratings, results of operations and financial condition of FE and FES.

On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies requesting FERC review the then proposed ESP IV PPA under Section 205 of the FPA. In a separate proceeding on March 21, 2016, a number of generation owners filed a complaint with FERC against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular the alleged price suppression that would result from the then proposed ESP IV PPA and other similar agreements. In addition to such proceedings, various opponents have expressed an intention to challenge the ESP IV PPA or the PUCO's approval of the ESP IV in the courts and/or before FERC. Management intends to vigorously defend against such challenges. However, if, as a result of such challenges, the ESP IV PPA is either invalidated, terminated, substantially modified or the effectiveness thereof is otherwise substantially impaired or delayed, there could be a material and adverse impact to the credit ratings, results of operations and financial condition of FE and FES.

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
(B)	10.1	Executive Short-Term Incentive Program, effective February 16, 2016 (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-56, File No. 333-21011)
(B)	10.2	Form of 2016-2018 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-57, File No. 333-21011)
(B)	10.3	Form of 2016-2018 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-58, File No. 333-21011)
(B)	10.4	Form of 2016 Restricted Stock Award Agreement (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-59, 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, 2016, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.
FES
(A)	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, 2016, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.

(A) Provided herein in electronic format as an exhibit.

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

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SIGNATURES

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

April 26, 2016

FIRSTENERGY CORP.

Registrant

FIRSTENERGY SOLUTIONS CORP.

Registrant

/s/ K. Jon Taylor

K. Jon Taylor

Vice President, Controller

and Chief Accounting Officer 

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EXHIBIT INDEX

Exhibit Number
FirstEnergy
(B)	10.1	Executive Short-Term Incentive Program, effective February 16, 2016 (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-56, File No. 333-21011)
(B)	10.2	Form of 2016-2018 Cash-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-57, File No. 333-21011)
(B)	10.3	Form of 2016-2018 Stock-Based Performance-Adjusted Restricted Stock Unit Award Agreement (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-58, File No. 333-21011)
(B)	10.4	Form of 2016 Restricted Stock Award Agreement (incorporated herein by reference to FE’s Form 10-K filed February 16, 2016. Exhibit 10-59, 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, 2016, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income and Consolidated Statements of Comprehensive Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Cash Flows, (iv) related notes to these financial statements and (v) document and entity information.
FES
(A)	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, 2016, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Statements of Income (Loss) and Comprehensive Income (Loss), (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.

89

EX-12

EXHIBIT 12

FIRSTENERGY CORP.

CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES

	Three Months Ended March 31			Year Ended December 31
	2016			2015			2014			2013			2012			2011
(In millions)
EARNINGS AS DEFINED IN REGULATION S-K:
Net Income/Income from continuing operations	$	328		$	578		$	213		$	375		$	755		$	856
Interest and other charges, before reduction for amounts capitalized and deferred	288			1,132			1,073			1,016			1,001			1,008
Capitalized interest	(17		)	(68		)	(69		)	(75		)	(72		)	(70		)
Provision for income taxes	213			315			(42		)	195			545			566
Interest element of rentals charged to income (1)	19			78			83			96			136			150
Earnings as defined	$	831		$	2,035		$	1,258		$	1,607		$	2,365		$	2,510
FIXED CHARGES AS DEFINED IN REGULATION S-K:
Interest before reduction for amounts capitalized and deferred	$	288		$	1,132		$	1,073		$	1,016		$	1,001		$	1,008
Interest element of rentals charged to income (1)	19			78			83			96			136			150
Fixed charges as defined	$	307		$	1,210		$	1,156		$	1,112		$	1,137		$	1,158
CONSOLIDATED RATIO OF EARNINGS TO FIXED CHARGES	2.71			1.68			1.09			1.45			2.08			2.17

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

90

EX-31.1

EXHIBIT 31.1

Certification

I, Charles E. Jones, 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: April 26, 2016

/s/ Charles E. Jones

Charles E. Jones

President and Chief Executive Officer

91

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: April 26, 2016

/s/ Donald R. Schneider

Donald R. Schneider

President

92

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: April 26, 2016

/s/ James F. Pearson

James F. Pearson

Executive Vice President and Chief Financial Officer

93

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: April 26, 2016

/s/ James F. Pearson

James F. Pearson

Executive Vice President and Chief Financial Officer

94

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 ended March 31, 2016 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), each undersigned officer of the Company does hereby certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, that to the best of his knowledge:

(1) The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ Charles E. Jones

Charles E. Jones

President and Chief Executive Officer

/s/ James F. Pearson

James F. Pearson

Executive Vice President and Chief Financial Officer

Date: April 26, 2016

95

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 ended March 31, 2016 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

/s/ James F. Pearson

James F. Pearson

Executive Vice President and Chief Financial Officer

Date: April 26, 2016

96

XML

Document and Entity Information	3 Months Ended
	Mar. 31, 2016 shares
Entity Information [Line Items]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	0001031296
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	424,712,431
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, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
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

Consolidated Statements of Income (FirstEnergy Corp.) - USD ($) shares in Millions, $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
REVENUES:
Regulated Distribution		$ 2,521	$ 2,562
Regulated Transmission		275	238
Unregulated businesses		1,073	1,097
Total revenues	[1]	3,869	3,897
OPERATING EXPENSES:
Fuel		381	513
Purchased power		1,124	1,113
Other operating expenses		918	1,057
Provision for depreciation		329	319
Amortization of regulatory assets, net		61	32
General taxes		280	269
Total operating expenses		3,093	3,303
OPERATING INCOME		776	594
OTHER INCOME (EXPENSE):
Investment income (loss)		28	17
Interest expense		(288)	(279)
Capitalized financing costs		25	34
Total other income (expense)		(235)	(228)
INCOME BEFORE INCOME TAXES		541	366
INCOME TAXES (BENEFITS)		213	144
NET INCOME (LOSS)		$ 328	$ 222
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Net Earnings per Basic Share to FirstEnergy Corp., in dollars per share		$ 0.78	$ 0.53
Diluted - Net Earnings per Diluted Share Available to FirstEnergy Corp., in dollars per share		$ 0.77	$ 0.53
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		424	421
Diluted, in shares		426	423
DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share		$ 0.72	$ 0.72

[1] Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

XML

Consolidated Statements of Income (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Statement [Abstract]
Excise taxes collected	$ 107	$ 115

XML

Consolidated Statements of Comprehensive Income (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 328	$ 222
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(18)	(31)
Amortized (gains) losses on derivative hedges	2	1
Change in unrealized gain on available-for-sale securities	28	4
Other comprehensive income (loss)	12	(26)
Income tax benefits on other comprehensive loss	4	(10)
Other comprehensive income (loss), net of tax	8	(16)
COMPREHENSIVE INCOME (LOSS)	$ 336	$ 206

XML

Consolidated Balance Sheets (FirstEnergy Corp.) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 146	$ 131
Receivables-
Customers, net of allowance for uncollectible accounts of $64 in 2016 and $69 in 2015	1,432	1,415
Other, net of allowance for uncollectible accounts of $5 in 2016 and 2015	162	180
Materials and supplies	781	785
Prepaid taxes	267	135
Derivatives	207	157
Collateral	80	70
Other	155	167
Total current assets	3,230	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371	49,952
Less - Accumulated provision for depreciation	15,421	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	34,950	34,792
Construction work in progress	2,694	2,422
Total net property, plant and equipment	37,644	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,282
Other	526	506
Total other property and investments	2,886	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Regulatory assets	1,279	1,348
Other	1,238	1,286
Total deferred charges and other assets	8,935	9,052
Total assets	52,695	52,094
CURRENT LIABILITIES:
Currently payable long-term debt	1,355	1,166
Short-term borrowings	2,125	1,708
Accounts payable	1,000	1,075
Accrued taxes	513	519
Accrued compensation and benefits	309	334
Derivatives	117	106
Other	970	694
Total current liabilities	6,389	5,602
Common stockholders' equity-
Common stock, $0.10 par value, authorized 490,000,000 shares - 424,712,431 and 423,560,397 shares outstanding as of March 31, 2016 and December 31, 2015, respectively	42	42
Other paid-in capital	9,963	9,952
Accumulated other comprehensive income	179	171
Retained earnings	2,279	2,256
Total common stockholders' equity	12,463	12,421
Noncontrolling interest	1	1
Total equity	12,464	12,422
Long-term debt and other long-term obligations	18,878	19,099
Total capitalization	31,342	31,521
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	6,996	6,773
Retirement benefits	4,135	4,245
Asset retirement obligations	1,427	1,410
Deferred gain on sale and leaseback transaction	782	791
Adverse power contract liability	194	197
Other	1,430	1,555
Total noncurrent liabilities	$ 14,964	$ 14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 52,695	$ 52,094

XML

Consolidated Balance Sheets (FirstEnergy Corp.) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
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	424,712,431	423,560,397
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 64	$ 69
Other [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5

XML

Consolidated Statements of Cash Flows (FirstEnergy Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME	$ 328	$ 222
Adjustments to reconcile net income to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	455	425
Deferred purchased power and other costs	(10)	(31)
Deferred income taxes and investment tax credits, net	206	127
Deferred costs on sale leaseback transaction, net	12	12
Retirement benefits	16	(4)
Pension trust contributions	(160)	(143)
Commodity derivative transactions, net	(64)	2
Changes in current assets and liabilities-
Receivables	1	(97)
Materials and supplies	4	30
Prepayments and other current assets	(82)	(116)
Accounts payable	25	(177)
Accrued taxes	(110)	(80)
Accrued interest	47	44
Accrued compensation and benefits	(102)	(80)
Other current liabilities	19	11
Cash collateral, net	(6)	(15)
Other	59	63
Net cash provided from operating activities	638	193
New Financing-
Short-term borrowings, net	425	760
Redemptions and Repayments-
Long-term debt	(31)	(48)
Common stock dividend payments	(152)	(152)
Net cash provided from (used for) financing activities	242	560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698)	(668)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	465	371
Purchases of investment securities held in trusts	(488)	(394)
Cash investments	30	21
Asset removal costs	(34)	(28)
Other	9	10
Net cash used for investing activities	(865)	(748)
Net change in cash and cash equivalents	15	5
Cash and cash equivalents at beginning of period	131	$ 85
Cash and cash equivalents at end of period	$ 146

XML

Consolidated Statements of Income and Comprehensive Income (Loss) (FirstEnergy Solutions Corp.) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
REVENUES:
Electric sales		$ 1,073	$ 1,097
Total revenues	[1]	3,869	3,897
OPERATING EXPENSES:
Fuel		381	513
Purchased power		1,124	1,113
Other operating expenses		918	1,057
Provision for depreciation		329	319
General taxes		280	269
Total operating expenses		3,093	3,303
OPERATING INCOME		776	594
OTHER INCOME (EXPENSE):
Investment income (loss)		28	17
Interest expense		(288)	(279)
Capitalized interest		25	34
Total other income (expense)		(235)	(228)
INCOME BEFORE INCOME TAXES		541	366
INCOME TAXES (BENEFITS)		213	144
NET INCOME (LOSS)		328	222
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)		328	222
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(18)	(31)
Amortized gains on derivative hedges		2	1
Change in unrealized gain on available-for-sale securities		28	4
Other comprehensive income (loss)		12	(26)
Income taxes (benefits) on other comprehensive income (loss)		4	(10)
Other comprehensive income (loss), net of tax		8	(16)
COMPREHENSIVE INCOME (LOSS)		336	206
FES
REVENUES:
Other		45	47
Total revenues		1,199	1,377
OPERATING EXPENSES:
Fuel		165	230
Other operating expenses		240	413
Provision for depreciation		83	80
General taxes		26	29
Total operating expenses		973	1,365
OPERATING INCOME		226	12
OTHER INCOME (EXPENSE):
Investment income (loss)		15	13
Capitalized interest		10	9
Total other income (expense)		(13)	(17)
INCOME BEFORE INCOME TAXES		213	(5)
INCOME TAXES (BENEFITS)		82	(2)
NET INCOME (LOSS)		131	(3)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)		131	(3)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs		(4)	(4)
Amortized gains on derivative hedges		0	(1)
Change in unrealized gain on available-for-sale securities		23	3
Other comprehensive income (loss)		19	(2)
Income taxes (benefits) on other comprehensive income (loss)		7	(1)
Other comprehensive income (loss), net of tax		12	(1)
COMPREHENSIVE INCOME (LOSS)		143	(4)
FES | Affiliates
REVENUES:
Electric sales		147	255
OPERATING EXPENSES:
Purchased power		82	70
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FES | Non-Affiliates
REVENUES:
Electric sales		1,007	1,075
OPERATING EXPENSES:
Purchased power		377	543
OTHER INCOME (EXPENSE):
Interest expense		$ (36)	$ (37)

[1] Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

XML

Consolidated Balance Sheets (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
CURRENT ASSETS:
Cash and cash equivalents	$ 146	$ 131
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2016 and 2015	1,432	1,415
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	162	180
Materials and supplies	781	785
Derivatives	207	157
Collateral	80	70
Prepayments and other	155	167
Total current assets	3,230	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371	49,952
Less - Accumulated provision for depreciation	15,421	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	34,950	34,792
Construction work in progress	2,694	2,422
Total net property, plant and equipment	37,644	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,282
Other	526	506
Total other property and investments	2,886	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418
Other	1,238	1,286
Total deferred charges and other assets	8,935	9,052
Total assets	52,695	52,094
CURRENT LIABILITIES:
Currently payable long-term debt	1,355	1,166
Other	2,125	1,708
Accounts payable-
Accrued taxes	513	519
Derivatives	117	106
Other	970	694
Total current liabilities	6,389	5,602
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2016 and December 31, 2015	42	42
Accumulated other comprehensive income	179	171
Retained earnings	2,279	2,256
Total common stockholders' equity	12,463	12,421
Long-term debt and other long-term obligations	18,878	19,099
Total capitalization	31,342	31,521
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	6,996	6,773
Retirement benefits	4,135	4,245
Asset retirement obligations	1,427	1,410
Other	1,430	1,555
Total noncurrent liabilities	$ 14,964	$ 14,971
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 52,695	$ 52,094
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2
Receivables-
Customers, net of allowance for uncollectible accounts of $8 in 2016 and 2015	229	275
Affiliated companies	447	451
Other, net of allowance for uncollectible accounts of $3 in 2016 and 2015	107	59
Notes receivable from affiliated companies	0	11
Materials and supplies	446	470
Derivatives	207	154
Collateral	80	70
Prepayments and other	80	66
Total current assets	1,598	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,376	14,311
Less - Accumulated provision for depreciation	5,874	5,765
Property, plant and equipment in service net of accumulated provision for depreciation	8,502	8,546
Construction work in progress	1,273	1,157
Total net property, plant and equipment	9,775	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372	1,327
Other	10	10
Total other property and investments	1,382	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Customer intangibles	57	61
Goodwill	23	23
Property taxes	30	40
Derivatives	89	79
Other	385	367
Total deferred charges and other assets	584	570
Total assets	13,339	13,168
CURRENT LIABILITIES:
Currently payable long-term debt	549	512
Other		8
Accounts payable-
Affiliated companies	362	542
Other	116	139
Accrued taxes	71	76
Derivatives	115	104
Other	241	181
Total current liabilities	1,503	1,562
Common stockholders' equity-
Common stock, without par value, authorized 750 shares - 7 shares outstanding as of March 31, 2016 and December 31, 2015	3,614	3,613
Accumulated other comprehensive income	58	46
Retained earnings	2,077	1,946
Total common stockholders' equity	5,749	5,605
Long-term debt and other long-term obligations	2,480	2,510
Total capitalization	8,229	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	722	600
Retirement benefits	339	332
Asset retirement obligations	838	831
Derivatives	21	38
Other	905	899
Total noncurrent liabilities	$ 3,607	$ 3,491
COMMITMENTS, GUARANTEES AND CONTINGENCIES
Total liabilities and capitalization	$ 13,339	$ 13,168
FES | Affiliated Entity [Member]
CURRENT LIABILITIES:
Affiliated companies	49	0
FES | Non-Affiliated Entity [Member]
CURRENT LIABILITIES:
Affiliated companies	$ 0	$ 8

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Consolidated Balance Sheets (FirstEnergy Solutions Corp.) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Common stockholders' equity-
Common stock, shares authorized	490,000,000	490,000,000
Common stock, shares outstanding	424,712,431	423,560,397
Customer [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 64	$ 69
Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 5	$ 5
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)	$ 8	$ 8
FES | Other Receivables [Member]
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 3	$ 3

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Consolidated Statements of Cash Flows (FirstEnergy Solutions Corp.) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	$ 328	$ 222
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	455	425
Deferred costs on sale and leaseback transaction, net	(12)	(12)
Deferred income taxes and investment tax credits, net	206	127
Commodity derivative transactions, net	(64)	2
Changes in current assets and liabilities-
Receivables	1	(97)
Materials and supplies	4	30
Prepayments and other current assets	(82)	(116)
Accounts payable	25	(177)
Accrued taxes	(110)	(80)
Accrued compensation and benefits	(102)	(80)
Other current liabilities	19	11
Cash collateral, net	(6)	(15)
Other	59	63
Net cash provided from operating activities	638	193
New financing-
Short-term borrowings, net	425	760
Redemptions and Repayments-
Long-term debt	(31)	(48)
Net cash provided from (used for) financing activities	242	560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698)	(668)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	465	371
Purchases of investment securities held in trusts	(488)	(394)
Cash investments	30	21
Other	9	10
Net cash used for investing activities	(865)	(748)
Net change in cash and cash equivalents	15	5
Cash and cash equivalents at beginning of period	131	85
Cash and cash equivalents at end of period	146
FES
CASH FLOWS FROM OPERATING ACTIVITIES:
NET INCOME (LOSS)	131	(3)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Depreciation and amortization, including nuclear fuel, regulatory assets, net, and customer intangible asset amortization	138	144
Deferred costs on sale and leaseback transaction, net	(12)	(12)
Deferred income taxes and investment tax credits, net	113	34
Investment impairments	8	6
Commodity derivative transactions, net	(64)	1
Changes in current assets and liabilities-
Receivables	2	1
Materials and supplies	24	21
Prepayments and other current assets	(12)	(18)
Accounts payable	(103)	(75)
Accrued taxes	(15)	(24)
Accrued compensation and benefits	(11)	(9)
Other current liabilities	18	8
Cash collateral, net	(10)	12
Other	(3)	(5)
Net cash provided from operating activities	228	105
New financing-
Short-term borrowings, net	49	150
Redemptions and Repayments-
Long-term debt	0	(17)
Other	(2)	(2)
Net cash provided from (used for) financing activities	47	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(143)	(119)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	138	189
Purchases of investment securities held in trusts	(151)	(202)
Cash investments	10	0
Loans to affiliated companies, net	11	(44)
Other	9	0
Net cash used for investing activities	(275)	(236)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	$ 2	$ 2

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Organization and Basis of Presentation

3 Months Ended

Mar. 31, 2016

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. FE’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, FET and its principal subsidiaries (ATSI and TrAIL), and AESC. In addition, FE holds all of the outstanding common stock of other direct subsidiaries including: FirstEnergy Properties, Inc., FEV, FENOC, FELHC, Inc., GPU Nuclear, Inc., and Allegheny Ventures, Inc.

FirstEnergy and its subsidiaries are principally involved in the generation, transmission, and distribution of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving six million customers in the Midwest and Mid-Atlantic regions. Its generation subsidiaries control nearly 17,000 MW of capacity from a diverse mix of non-emitting nuclear, scrubbed coal, natural gas, hydroelectric and other renewables. FirstEnergy’s transmission operations include approximately 24,000 miles of lines and two regional transmission operation centers.

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, 2015. These Notes to the Consolidated Financial Statements are combined for FirstEnergy and FES.

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 necessarily 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 as appropriate. 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 do not have a controlling financial interest, 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 of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.

For the three months ended March 31, 2016 and 2015, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $8 million and $16 million, respectively, of allowance for equity funds used during construction and $17 million and $18 million, respectively, of capitalized interest.

New Accounting Pronouncements

In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded.In August 2015, the FASB issued a final ASU deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date). In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)", clarifying the principal versus agent implementation guidance in the following areas: unit of account at which the principal/agent determination is made; applying the control principle to certain types of transactions and the control principle and principal/agent indicators.In April 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, clarifying the identification of performance obligations and the licensing implementation guidance.The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards.

In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated.A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries. See Note 6, Variable Interest Entities, for additional information.

In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified$93 million and $17 millionof debt issuance costs included in Deferred Charges and Other Assets to Long-term Debt and Other Long-term Obligations. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset.

In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets.In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required.The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

Additionally, in March of 2016, the FASB issued the following ASUs:

• ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”,

• ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and

• ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”.

FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

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Earnings Per Share Of Common Stock

3 Months Ended

Mar. 31, 2016

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)	For the Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2016		2015
Net income	$	328	$	222
Weighted average number of basic shares outstanding	424		421
Assumed exercise of dilutive stock options and awards(1)	2		2
Weighted average number of diluted shares outstanding	426		423
Basic earnings per share of common stock	$	0.78	$	0.53
Diluted earnings per share of common stock	$	0.77	$	0.53

⁽¹⁾  For both the three months ended March 31, 2016 and March 31, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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Pension and Other Postemployment Benefits

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

PENSION AND OTHER POSTEMPLOYMENT BENEFITS

In 2016, FirstEnergy has minimum required funding obligations of$381 millionto its qualified pension plan, of which$160 millionhas been contributed to date. FirstEnergy expects to make future contributions to the qualified pension plan in 2016 with cash, equity or a combination thereof, depending on, among other things, market conditions.

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

Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended March 31	2016			2015			2016			2015
	(In millions)
Service costs	$	48		$	48		$	1		$	1
Interest costs	100			96			7			7
Expected return on plan assets	(97		)	(111		)	(8		)	(8		)
Amortization of prior service costs (credits)	2			2			(20		)	(33		)
Net periodic costs (credits)	$	53		$	35		$	(20	)	$	(33	)

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

	Pension				OPEB
	2016		2015		2016			2015
	(In millions)
For the Three Months Ended March 31	$	6	$	4	$	(4	)	$	(5	)

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

Net Periodic Benefit Expense (Credit)	Pension				OPEB
For the Three Months Ended March 31	2016		2015		2016			2015
	(In millions)
FirstEnergy	$	37	$	25	$	(15	)	$	(23	)
FES	6		4		(4		)	(4		)

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Accumulated Other Comprehensive Income

3 Months Ended

Mar. 31, 2016

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, 2016 and 2015, for FirstEnergy are included 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, 2016	$	(33	)	$	18		$	186		$	171
Other comprehensive income before reclassifications	—			41			—			41
Amounts reclassified from AOCI	2			(13		)	(18		)	(29		)
Other comprehensive income (loss)	2			28			(18		)	12
Income tax (benefits) on other comprehensive income (loss)	1			10			(7		)	4
Other comprehensive income (loss), net of tax	1			18			(11		)	8
AOCI Balance as of March 31, 2016	$	(32	)	$	36		$	175		$	179
AOCI Balance as of January 1, 2015	$	(37	)	$	25		$	258		$	246
Other comprehensive income before reclassifications	—			14			—			14
Amounts reclassified from AOCI	1			(10		)	(31		)	(40		)
Other comprehensive income (loss)	1			4			(31		)	(26		)
Income tax (benefits) on other comprehensive income (loss)	—			1			(11		)	(10		)
Other comprehensive income (loss), net of tax	1			3			(20		)	(16		)
AOCI Balance as of March 31, 2015	$	(36	)	$	28		$	238		$	230

The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2016 and 2015:

		For the Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (2)		2016			2015
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts		$	—		$	(1	)	Other operating expenses
Long-term debt		2			2			Interest expense
		2			1			Total before taxes
		(1		)	—			Income taxes
		$	1		$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities		$	(13	)	$	(10	)	Investment income
		5			4			Income taxes
		$	(8	)	$	(6	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs		$	(18	)	$	(31	)	(1)
		7			11			Income taxes
		$	(11	)	$	(20	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.

The changes in AOCI, net of tax, in the three months ended March 31, 2016 and 2015, for FES are included in the following tables:

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, 2016	$	(9	)	$	16		$	39		$	46
Other comprehensive income before reclassifications	—			36			—			36
Amounts reclassified from AOCI	—			(13		)	(4		)	(17		)
Other comprehensive income (loss)	—			23			(4		)	19
Income tax (benefits) on other comprehensive income (loss)	—			9			(2		)	7
Other comprehensive income (loss), net of tax	—			14			(2		)	12
AOCI Balance as of March 31, 2016	$	(9	)	$	30		$	37		$	58
AOCI Balance as of January 1, 2015	$	(7	)	$	21		$	43		$	57
Other comprehensive income before reclassifications	—			13			—			13
Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
Other comprehensive income (loss)	(1		)	3			(4		)	(2		)
Income tax (benefits) on other comprehensive income (loss)	—			—			(1		)	(1		)
Other comprehensive income (loss), net of tax	(1		)	3			(3		)	(1		)
AOCI Balance as of March 31, 2015	$	(8	)	$	24		$	40		$	56

The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2016 and 2015:

		For the Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income (Loss)
Reclassifications from AOCI (2)		2016			2015
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts		$	—		$	(1	)	Other operating expenses
		—			—			Income taxes (benefits)
		$	—		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities		$	(13	)	$	(10	)	Investment income
		5			4			Income taxes (benefits)
		$	(8	)	$	(6	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs		$	(4	)	$	(4	)	(1)
		2			1			Income taxes (benefits)
		$	(2	)	$	(3	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

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Income Taxes

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

FirstEnergy’s and FES’ interim effective tax rates reflect the estimated annual effective tax rates for 2016 and 2015. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period.

FirstEnergy’s effective tax rate from continuing operations for the three months ended March 31, 2016 and 2015 was 39.4% and 39.3%, respectively. FES’ effective tax rate from continuing operations for the three months ended March 31, 2016 and 2015 was 38.5% and 40.0%, respectively.

During the three months ended March 31, 2016, FirstEnergy recorded unrecognized tax benefits of $69 million primarily related to protective refund claims filed with the state of Pennsylvania as a result of a recent ruling by the Commonwealth Court citing the state’s NOL carryover limitation violated the uniformity clause and was unconstitutional. The state of Pennsylvania has appealed this ruling to the Pennsylvania Supreme Court.

As of March 31, 2016, it is reasonably possible that approximately $54 million of unrecognized tax benefits may be resolved within the next twelve months as a result of the statute of limitations expiring and an expected decision at the appeals level with respect to certain claims, of which approximately $16 million would affect FirstEnergy's effective tax rate.

In February 2016, the IRS completed its examination of FirstEnergy’s 2014 federal income tax return and issued a full acceptance letter with no adjustments.

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Variable Interest Entities

3 Months Ended

Mar. 31, 2016

Variable Interest Entities [Abstract]

VARIABLE INTEREST ENTITIES

VARIABLE INTEREST ENTITIES

FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) 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.

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 categories based on similar risk characteristics and significance.

Consolidated VIEs

VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements):

• PNBV Trust - PNBV, a business trust established by OE in 1996, issued certain beneficial interests and notes to fund the acquisition of a portion of the bonds issued by certain owner trusts in connection with the sale and leaseback in 1987 of a portion of OE's interest in the Perry Plant and Beaver Valley Unit 2. OE used debt and available funds to purchase the notes issued by PNBV. The beneficial ownership of PNBV includes a 3% interest by unaffiliated third parties.

• Ohio Securitization- In September 2012, the Ohio Companies created separate, wholly-owned limited liability companies (SPEs) which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of March 31, 2016 and December 31, 2015, $350 million and $362 million of the phase-in recovery bonds were outstanding, respectively.

• JCP&L Securitization - In June 2002, JCP&L Transition Funding sold transition bonds to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station. In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s and JCP&L’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding and JCP&L Transition Funding II and are collateralized by each company’s equity and assets, which consist primarily of bondable transition property. As of March 31, 2016 and December 31, 2015, $118 million and $128 million of the transition bonds were outstanding, respectively.

• MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The special purpose limited liability companies own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the special purpose limited liability companies, have no recourse to any assets or revenues of the special purpose limited liability companies. As of March 31, 2016 and December 31, 2015, $419 million and $429 million of the environmental control bonds were outstanding, respectively.

Unconsolidated VIEs

FirstEnergy is not the primary beneficiary of the following VIEs:

• Global Holding - 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 with coal sales in U.S. and international markets. 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.

As discussed in Note 10, Commitments, Guarantees and Contingencies, FE is the guarantor under Global Holding's $300 million term loan facility. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

• 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 FE 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 PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting.

• 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 14 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 one of these NUG entities, it does not have a variable interest in the entities or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; 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 during the three months ended March 31, 2016 and 2015 were $31 million.

• Sale and Leaseback Transactions - 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. 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. As of March 31, 2016, FirstEnergy's leasehold interest was3.75%of Perry Unit 1,93.83%of Bruce Mansfield Unit 1 and2.60%of Beaver Valley Unit 2.

On June 24, 2014, OE exercised its irrevocable right to repurchase from the remaining owner participants the lessors' interests in Beaver Valley Unit 2 at the end of the lease term (June 1, 2017), which right to repurchase was assigned to NG. Additionally, on June 24, 2014, NG entered into a purchase agreement with an owner participant to purchase its lessor equity interests of the remaining non-affiliated leasehold interest in Perry Unit 1 on May 23, 2016, which is just prior to the end of the lease term. Upon the completion of these transactions, NG will have obtained all of the lessor equity interests at Perry Unit 1 and Beaver Valley Unit 2.

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, 2016:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(In millions)
FirstEnergy	$	1,228	$	967	$	261
FES	1,171		949		222

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Fair Value Measurements

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASUREMENTS

Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy 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 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 PJM 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 PJM 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, 2016, from those used as of December 31, 2015. 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, 2016. 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, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,264		$	—		$	1,264		$	—		$	1,245		$	—		$	1,245
Derivative assets - commodity contracts	3			290			—			293			4			224			—			228
Derivative assets - FTRs	—			—			3			3			—			—			8			8
Derivative assets - NUG contracts(1)	—			—			1			1			—			—			1			1
Equity securities(2)	628			—			—			628			576			—			—			576
Foreign government debt securities	—			73			—			73			—			75			—			75
U.S. government debt securities	—			188			—			188			—			180			—			180
U.S. state debt securities	—			245			—			245			—			246			—			246
Other(3)	146			232			—			378			105			212			—			317
Total assets	$	777		$	2,292		$	4		$	3,073		$	685		$	2,182		$	9		$	2,876
Liabilities
Derivative liabilities - commodity contracts	$	(7	)	$	(122	)	$	—		$	(129	)	$	(9	)	$	(122	)	$	—		$	(131	)
Derivative liabilities - FTRs	—			—			(9		)	(9		)	—			—			(13		)	(13		)
Derivative liabilities - NUG contracts(1)	—			—			(136		)	(136		)	—			—			(137		)	(137		)
Total liabilities	$	(7	)	$	(122	)	$	(145	)	$	(274	)	$	(9	)	$	(122	)	$	(150	)	$	(281	)
Net assets (liabilities)(4)	$	770		$	2,170		$	(141	)	$	2,799		$	676		$	2,060		$	(141	)	$	2,595

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

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽⁴⁾  Excludes $(6) million and $7 million as of March 31, 2016 and December 31, 2015, 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 and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2016 and December 31, 2015:

	NUG Contracts(1)									FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2015 Balance	$	2		$	(153	)	$	(151	)	$	39		$	(14	)	$	25
Unrealized gain (loss)	2			(49		)	(47		)	(5		)	(7		)	(12		)
Purchases	—			—			—			22			(11		)	11
Settlements	(3		)	65			62			(48		)	19			(29		)
December 31, 2015 Balance	$	1		$	(137	)	$	(136	)	$	8		$	(13	)	$	(5	)
Unrealized loss	—			(12		)	(12		)	—			(1		)	(1		)
Settlements	—			13			13			(5		)	5			—
March 31, 2016 Balance	$	1		$	(136	)	$	(135	)	$	3		$	(9	)	$	(6	)

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

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, 2016:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(6	)	Model	RTO auction clearing prices	($4.60) to $3.70	$0.60	Dollars/MWH
NUG Contracts	$	(135	)	Model	Generation	400 to 3,651,000	777,000	MWH
					Regional electricity prices	$37.30 to $45.60	$39.60	Dollars/MWH

FES
Recurring Fair Value Measurements	March 31, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	715		$	—		$	715		$	—		$	678		$	—		$	678
Derivative assets - commodity contracts	3			290			—			293			4			224			—			228
Derivative assets - FTRs	—			—			3			3			—			—			5			5
Equity securities(1)	408			—			—			408			378			—			—			378
Foreign government debt securities	—			58			—			58			—			59			—			59
U.S. government debt securities	—			25			—			25			—			23			—			23
U.S. state debt securities	—			4			—			4			—			4			—			4
Other(2)	—			170			—			170			—			184			—			184
Total assets	$	411		$	1,262		$	3		$	1,676		$	382		$	1,172		$	5		$	1,559
Liabilities
Derivative liabilities - commodity contracts	$	(7	)	$	(122	)	$	—		$	(129	)	$	(9	)	$	(122	)	$	—		$	(131	)
Derivative liabilities - FTRs	—			—			(7		)	(7		)	—			—			(11		)	(11		)
Total liabilities	$	(7	)	$	(122	)	$	(7	)	$	(136	)	$	(9	)	$	(122	)	$	(11	)	$	(142	)
Net assets (liabilities)(3)	$	404		$	1,140		$	(4	)	$	1,540		$	373		$	1,050		$	(6	)	$	1,417

⁽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 $1 million as of March 31, 2016 and December 31, 2015, 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, 2016 and December 31, 2015:

	Derivative Asset			Derivative Liability			Net Asset (Liability)
	(In millions)
January 1, 2015 Balance	$	27		$	(13	)	$	14
Unrealized gain (loss)	2			(5		)	(3		)
Purchases	9			(10		)	(1		)
Settlements	(33		)	17			(16		)
December 31, 2015 Balance	$	5		$	(11	)	$	(6	)
Unrealized loss	—			(1		)	(1		)
Settlements	(2		)	5			3
March 31, 2016 Balance	$	3		$	(7	)	$	(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, 2016:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(4	)	Model	RTO auction clearing prices	($4.60) to $3.70	$0.50	Dollars/MWH

INVESTMENTS

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities.

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 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 NDTs of JCP&L, ME and PN are subject to regulatory accounting with unrealized gains and losses offset against regulatory assets.

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, 2016 and December 31, 2015:

	March 31, 2016(1)						December 31, 2015(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,776	$	44	$	1,820	$	1,778	$	16	$	1,794
FES	825		26		851		801		9		810
Equity securities
FirstEnergy	$	576	$	52	$	628	$	542	$	34	$	576
FES	372		36		408		354		24		378

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $161 million; FES - $113 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $157 million; FES - $139 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, 2016 and 2015 were as follows:

Three Months Ended
March 31, 2016	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	465	$	61	$	(50	)	$	(9	)	$	23
FES	138		42		(29		)	(8		)	13
March 31, 2015	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	371	$	60	$	(50	)	$	(7	)	$	25
FES	189		38		(28		)	(6		)	14

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, 2016 and December 31, 2015:

	March 31, 2016						December 31, 2015
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	6	$	1	$	7	$	6	$	2	$	8

The held-to-maturity debt securities contractually mature by June 30, 2017. Investments in employee benefit trusts and equity method investments totaling $271 million as of March 31, 2016 and $255 million as of December 31, 2015, 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 debt issuance costs, premiums and discounts:

	March 31, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	20,217	$	21,821	$	20,244	$	21,519
FES	3,036		3,112		3,027		3,121

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. 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, 2016 and December 31, 2015.

XML

Derivative Instruments

3 Months Ended

Mar. 31, 2016

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 related 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) as follows:

• Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

• Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings.

• Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted.

Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.

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.

Total pre-tax net unamortized losses included in AOCI associated with instruments previously designated as cash flow hedges totaled $11 million as of March 31, 2016 and December 31, 2015. Since the forecasted transactions remain probable of occurring, these amounts will be amortized into earnings over the life of the hedging instruments. Less than $1 million of net unamortized losses is expected to be amortized to income during the next twelve months.

FirstEnergy has used forward starting interest rate 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 designated 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. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $39 million and $42 million as of March 31, 2016 and December 31, 2015, respectively. Based on current estimates, approximately $9 million of these unamortized losses is expected to be amortized to interest expense during the next twelve months.

Refer to Note 4, Accumulated Other Comprehensive Income, for reclassifications from AOCI during the three months ended March 31, 2016 and 2015.

As of March 31, 2016 and December 31, 2015, no commodity or interest rate derivatives were designated as cash flow hedges.

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. As of March 31, 2016 and December 31, 2015, 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 $17 million and $20 million as of March 31, 2016 and December 31, 2015, respectively. During the next twelve months, approximately $10 million of unamortized gains is expected to be amortized to interest expense. Amortization of unamortized gains included in long-term debt totaled approximately $3 million during the three months ended March 31, 2016 and 2015.

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. Derivative instruments are not used in quantities greater than forecasted needs.

As of March 31, 2016, FirstEnergy’s net asset position under commodity derivative contracts was $164 million, which related to FES positions. Under these commodity derivative contracts, FES posted $4 million of collateral and received $25 million of collateral. Certain commodity derivative contracts include credit risk related contingent features that would require FES to post $5 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, 2016, an increase in commodity prices of 10% would decrease net income by approximately $22 million during the next twelve months.

NUGs

As of March 31, 2016, FirstEnergy's net liability position under NUG contracts was $135 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.

FTRs

As of March 31, 2016, FirstEnergy's and FES' FTR position was a $6 million and $4 million net liability, respectively, and FES posted $6 million of collateral. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations.

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 PJM, 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, 2016		December 31, 2015			March 31, 2016			December 31, 2015
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	205	$	150	Commodity Contracts	$	(109	)	$	(94	)
FTRs	2		7		FTRs	(8		)	(12		)
	207		157			(117		)	(106		)
Deferred Charges and Other Assets - Other					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs(1)	(136		)	(137		)
Commodity Contracts	88		78		Noncurrent Liabilities - Other
FTRs	1		1		Commodity Contracts	(20		)	(37		)
NUGs(1)	1		1		FTRs	(1		)	(1		)
	90		80			(157		)	(175		)
Derivative Assets	$	297	$	237	Derivative Liabilities	$	(274	)	$	(281	)

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

FirstEnergy enters into contracts with counterparties that allow for the offsetting of derivative assets and derivative liabilities under netting arrangements with the same counterparty. 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 assets and derivative liabilities 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, 2016	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	293		$	(128	)	$	(25	)	$	140
FTRs	3			(3		)	—			—
NUG contracts	1			—			—			1
	$	297		$	(131	)	$	(25	)	$	141
Derivative Liabilities
Commodity contracts	$	(129	)	$	128		$	—		$	(1	)
FTRs	(9		)	3			6			—
NUG contracts	(136		)	—			—			(136		)
	$	(274	)	$	131		$	6		$	(137	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2015	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged		Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	228		$	(125	)	$	—	$	103
FTRs	8			(8		)	—		—
NUG contracts	1			—			—		1
	$	237		$	(133	)	$	—	$	104
Derivative Liabilities
Commodity contracts	$	(131	)	$	125		$	3	$	(3	)
FTRs	(13		)	8			5		—
NUG contracts	(137		)	—			—		(137		)
	$	(281	)	$	133		$	8	$	(140	)

The following table summarizes the volumes associated with FirstEnergy’s outstanding derivative transactions as of March 31, 2016:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	14	42	(28	)	MWH
FTRs	15	—	15		MWH
NUGs	4	—	4		MWH
Natural Gas	81	1	80		mmBTU

The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2016 and 2015, are summarized in the following tables:

	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2016
Unrealized Gain Recognized in:
Other Operating Expense (1)	$	62		$	2		$	64
Realized Gain (Loss) Reclassified to:
Revenues (1)	$	71		$	2		$	73
Purchased Power Expense (1)	(45		)	—			(45		)
Other Operating Expense (1)	—			(12		)	(12		)
Fuel Expense	(8		)	—			(8		)
(1) All amounts are associated with FES.
	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2015
Unrealized Gain (Loss) Recognized in:
Other Operating Expense (2)	$	11		$	(13	)	$	(2	)
Realized Gain (Loss) Reclassified to:
Revenues (3)	$	(1	)	$	37		$	36
Purchased Power Expense (4)	(3		)	—			(3		)
Other Operating Expense (5)	—			(13		)	(13		)
Fuel Expense	(16		)	—			(16		)
(2) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES.
(3) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES.
(4) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES.
(5) Includes ($13) million for FTRs associated with FES.

The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months endedMarch 31, 2016 and 2015. Changes in the value of these instruments are deferred for future recovery from (or credit to) customers:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			Regulated FTRs			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2016	$	(136	)	$	1		$	(135	)
Unrealized loss	(12		)	(1		)	(13		)
Settlements	13			(2		)	11
Outstanding net asset (liability) as of March 31, 2016	$	(135	)	$	(2	)	$	(137	)
Outstanding net asset (liability) as of January 1, 2015	$	(151	)	$	11		$	(140	)
Unrealized gain (loss)	(8		)	1			(7		)
Settlements	11			(11		)	—
Outstanding net asset (liability) as of March 31, 2015	$	(148	)	$	1		$	(147	)

XML

Regulatory Matters

3 Months Ended

Mar. 31, 2016

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 SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC.PE recovers its costs plus a return for providing SOS.

The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years.PE's current plan, covering the three-year period 2015-2017, was approved by the MDPSC on December 23, 2014.The costs of the 2015-2017 plan are expected to be approximately$66 million for that three-year period, of which $26 million was incurred through March 2016. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the level of savings achieved under PE's current plan for 2016, and ramping up 0.2% per year thereafter to reach 2%. PE continues to recover program costs subject to a five-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.On January 28, 2016, PE filed a request to increase plan spending by$2 millionin order to reach the new goals for 2017 set in the July 16, 2015 order.

On February 27, 2013, the MDPSC issued an order (the February 27 Order) requiring the Maryland electric utilities to submit analyses 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 required 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's responsive filings 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 require 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.On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting.The Staff of the MDPSC also recommended the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that the utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost.The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters.

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 is comprised oftwocomponents, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU.OneBGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers.The second BGS component provides a fixed price service and 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.

Pursuant to the NJBPU's March 26, 2015 final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which include operational and financial components and is expected to take approximately one year to complete.

In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases (Generic CTA proceeding), the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using afive-year look back from the beginning of the test year; (ii) allocating savings with75%retained by the company and25%allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation.On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the Generic CTA proceeding to the New Jersey Superior Court and JCP&L has filed to participate as a respondent in that proceeding.Briefing has been completed, and oral argument has not yet been scheduled.

In April 2016, JCP&L intends to file tariffs with the NJBPU proposing a general rate increase associated with its distribution operations that seeks to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses.The filing will request approval to increase annual operating revenues by approximately$142.1 millionbased upon a hybrid test year for the twelve months ending June 30, 2016. JCP&L will request that the new rates take effect in January 2017.

On June 19, 2015, JCP&L, along with PN, ME, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET. The procedural schedule was suspended while the NJBPU considers a motion on a legal issue regarding whether MAIT can be designated as a "public utility" in New Jersey.On February 24, 2016, the NJBPU issued an Order concluding that MAIT does not satisfy the “electricity distribution” element necessary for “public utility” status because MAIT would not own any electric distribution assets in New Jersey. On April 22, 2016, JCP&L and MAIT filed a supplemental petition and testimony seeking to include certain JCP&L distributions assets in the transfer to satisfy the "electricity distribution" element necessary for "public utility" status in accordance with the NJBPU’s February 24, 2016 order. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.

OHIO

The Ohio Companies operate under their ESP 3 plan which expires on May 31, 2016.The material terms of ESP 3 include:

• A base distribution rate freeze through May 31, 2016;

• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

• Economic development and assistance to low-income customers for thetwo-year plan period at levels established in the prior 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);

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

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

• A commitment not to recover from retail customers certain costs related to transmission cost allocations 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 FERC proceedings;

• 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, Ohio's renewable energy and energy efficiency standard, 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.

Notices of appeal of the Ohio Companies' ESP 3 plan to the Supreme Court of Ohio were filed by the Northeast Ohio Public Energy Council and the ELPC.The oral argument in this matter occurred on January 6, 2016.

The Ohio Companies filed an application with the PUCO on August 4, 2014 seeking approval of their ESP IV entitled Powering Ohio's Progress.The Ohio Companies filed a Stipulation and Recommendation on December 22, 2014, and supplemental stipulations and recommendations on May 28, 2015, and June 4, 2015.On December 1, 2015, the Ohio Companies filed a Third Supplemental Stipulation and Recommendation, which included PUCO Staff as a signatory party in addition to other signatories.

The proposed ESP IV supports FirstEnergy's strategic focus on regulated operations and better positions the Ohio Companies to deliver on their ongoing commitment to upgrade, modernize and maintain reliable electric service for customers while preserving electric security in Ohio. The material terms of the proposed ESP IV, as modified by the stipulations include:

• Aneight-year term (June 1, 2016 - May 31, 2024);

• Contemplates continuing a base distribution rate freeze through May 31, 2024;

• An Economic Stability Program that flows through charges or credits through Rider RRS representing the net result of the price paid to FES through aneight-year FERC-jurisdictional PPA, referred to as the ESP IV PPA, for the output of the ESP IV PPA Facilities against the revenues received from selling such output into the PJM markets over the same period, subject to the PUCO’s termination of Rider RRS associated with any of the ESP IV PPA Facilities that may be sold or transferred;

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

• Continuing Rider DCR with increased revenue caps of approximately $30 million per year from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024 that supports continued investment related to the distribution system for the benefit of customers;

• Collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs;

• A risk-sharing mechanism that would provide guaranteed credits under Rider RRS in years five through eight to customers as follows:$10 million in year five,$20 millionin year six,$30 millionin year seven and$40 millionin year eight;

• A continuing commitment not to recover from retail customers certain costs related to transmission cost allocations for the longer of thefive-year period from June 1, 2011 through May 31, 2016 or when the amount of such costs avoided by customers for certain types of products totals$360 million, including such costs from MISO along with such costs from PJM, subject to the outcome of certain FERC proceedings;

• Potential procurement of100 MWof new Ohio wind or solar resources subject to a demonstrated need to procure new renewable energy resources as part of a strategy to further diversify Ohio's energy portfolio;

• An agreement to file a case with the PUCO by April 3, 2017, seeking to transition to decoupled base rates for residential customers;

• An agreement to file by February 29, 2016, a Grid Modernization Business Plan for PUCO consideration and approval (which filing was made on February 29, 2016);

• A goal across FirstEnergy to reduce CO₂ emissions by90%below 2005 levels by 2045;

• A contribution of$3 millionper year ($24 millionover theeight-year term) to fund energy conservation programs, economic development and job retention in the Ohio Companies service territory;

• Contributions of $2.4 millionper year ($19 millionover the eight-year term) to fund a fuel-fund in each of the Ohio Companies service territories to assist low-income customers; and

• A contribution of$1 millionper year ($8 millionover theeight-year term) to establish a Customary Advisory Council to ensure preservation and growth of the competitive market in Ohio.

On March 31, 2016, the PUCO issued an Opinion and Order adopting and approving, with modifications, the Ohio Companies’ ESP IV. Changes arising from the approval of ESP IV will go into effect on June 1, 2016.The PUCO’s modifications of ESP IV, among others, included:

• Limiting average customer bill amounts for the firsttwoyears of the plan, subject to certain exceptions, and permitting deferral for the second year;

• Prohibiting recovery of retirement costs of the ESP IV PPA Facilities through Rider RRS;

• Assigning the burden of capacity performance penalties incurred by the ESP IV PPA Facilities to the Ohio Companies, rather than customers, and to provide that all capacity performance bonuses earned by the ESP IV PPA Facilities be retained by the Ohio Companies, rather than customers; and

• Providing for the modification of the severability provision previously included in ESP IV, to also address potential future PJM Tariff or rule changes prohibiting the Ohio Companies from offering output of the ESP IV PPA Facilities into PJM auctions.

Applications for Rehearing may be filed within thirty days of the issuance of the March 31, 2016 Opinion and Order.

On January 27, 2016, certain parties filed a complaint with FERC against FES and the Ohio Companies that requests FERC review the ESP IV PPA under Section 205 of the FPA. FES and the Ohio Companies responded to the complaint on February 23, 2016 and March 9, 2016. In a separate proceeding on March 21, 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in the PJM capacity markets by state-subsidized generation, in particular alleged price suppression that could result from the ESP IV PPA and other similar agreements. The complaint asks that FERC issue an order by May 1, 2016, so the revised rule can be in effect for the May 2016 PJM capacity auction. The Ohio Companies responded to the complaint on April 11, 2016 and April 20, 2016. In addition to such proceedings, opponents have expressed an intention to challenge in the courts and/or before FERC, the ESP IV PPA or PUCO's approval of the ESP IV. Management intends to vigorously defend against such challenges. FES and the Ohio Companies entered into the ESP IV PPA on April 1, 2016.

Under Ohio's energy efficiency standards (SB221 and SB310), and based on the Ohio Companies' amended energy efficiency plans, the Ohio Companies are required to implement energy efficiency programs that achieve a total annual energy savings equivalent of2,266GWHs in 2015 and2,288GWHs in 2016, and then begin to increase by 1% each year in 2017, subject to legislative amendments to the energy efficiency standards discussed below.The Ohio Companies are also required to retain the 2014 peak demand reduction level for 2015 and 2016 and then increase the benchmark by an additional0.75%thereafter through 2020, subject to legislative amendments to the peak demand reduction standards discussed below.

On September 30, 2015, the Energy Mandates Study Committee issued its report related to energy efficiency and renewable energy mandates, recommending that the current level of mandates remain in place indefinitely.The report also recommended: (i) an expedited process for review of utility proposed energy efficiency plans; (ii) ensuring maximum credit for all of Ohio's Energy Initiatives; (iii) a switch from energy mandates to energy incentives; and (iv) a declaration be made that the General Assembly may determine energy policy of the state. No legislation has yet been introduced to change the standards described above.

On September 24, 2014, the Ohio Companies filed an amendment to their energy efficiency portfolio plan as contemplated by SB310, seeking to suspend certain programs for the 2015-2016 period in order to better align the plan with the new benchmarks under SB310.On November 20, 2014, the PUCO approved the Ohio Companies' amended portfolio plan.Several applications for rehearing were filed, and the PUCO granted those applications for further consideration of the matters specified in those applications and the matter remains pending before the PUCO.

On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019.The plans as proposed comply with benchmarks contemplated by SB310 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities.The Ohio Companies anticipate the cost of the plans will be approximately$323 millionover the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms.

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, which is still pending.The matter has not been scheduled for oral argument.

Ohio law 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 2026, subject to legislative amendments discussed above, except 2015 and 2016 that remain at the 2014 level.The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements.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.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 certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of$43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent.On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a notice of appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted.On February 18, 2014, the OCC and the ELPC also filed appeals of the PUCO's order.The Ohio Companies timely filed their merit brief with the Supreme Court of Ohio and the briefing process has concluded.The matter is not yet scheduled for oral argument.

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. On November 18, 2015, the PUCO ruled that on a going-forward basis, pass-through clauses may not be included in fixed-price contracts for all customer classes. On December 18, 2015, FES filed an Application for Rehearing seeking to change the ruling or have it only apply to residential and small commercial customers.

PENNSYLVANIA

The Pennsylvania Companies currently operate under DSPs that expire on May 31, 2017, 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 spot market purchases, quarterly descending clock auctions for 3, 12- and 24-month energy contracts, and one RFP seeking 2-year contracts to serve SRECs for ME, PN and Penn.

On November 3, 2015, the Pennsylvania Companies filed their proposed DSPs for the June 1, 2017 through May 31, 2019 delivery period, which would provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the proposed programs, the supply would be provided by wholesale suppliers though a mix of 12 and 24-month energy contracts, as well as one RFP for 2-year SREC contracts for ME, PN and Penn. In addition, the proposal includes modifications to the Pennsylvania Companies’ existing POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges.A hearing was held on February 25, 2016.A Joint Petition for Settlement resolving all issues was filed on April 1, 2016, which is subject to PPUC approval.

Pursuant to Pennsylvania's EE&C legislation (Act 129 of 2008) and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs.The Pennsylvania Companies' Phase II EE&C Plans are effective through May 31, 2016.Total Phase II costs of these plans are expected to be approximately$175 millionand recoverable through the Pennsylvania Companies' reconcilable EE&C riders.On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at1.8%for ME, 1.7% for Penn, 1.8% for WP, and 0%for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at4.0% for ME, 3.9%for PN, 3.3% for Penn, and 2.6% for WP. The Pennsylvania Companies filed their Phase III EE&C plans for the June 2016 through May 2021 period on November 23, 2015, which are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order. EDCs are permitted to recover costs for implementing their EE&C plans. On February 10, 2016, the Pennsylvania Companies and the parties intervening in the PPUC's Phase III proceeding filed a joint settlement resolving all issues, which was subject to PPUC approval.On March 10, 2016, the PPUC entered an Opinion and Order approving the settlement and directing that the Pennsylvania Companies modify certain cost recovery methodologies to describe the allocation of EE&C Phase III common costs among customer classes and to describe the recovery of remaining costs of their Phase II EE&C Plans. None of the parties to the joint settlement elected to withdraw from the joint settlement due to the modifications.

Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval.Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC.On October 19, 2015, each of the Pennsylvania Companies filed LTIIPs with the PPUC for infrastructure improvement over the five-year period of 2016 to 2020 for the following costs: WP$88.34 million; PN$56.74 million; Penn$56.35 million; and ME$43.44 million. These amounts include all qualifying distribution capital additions identified in the revised implementation plan for the recent focused management and operations audit of the Pennsylvania Companies as discussed below. On February 11, 2016, the PPUC approved the Pennsylvania Companies' LTIIPs. On February 16, 2016, the Pennsylvania Companies filed DSIC riders for PPUC approval for quarterly cost recovery associated with the capital projects approved in the LTIIPs. The DSIC riders are expected to be effective July 1, 2016.Various parties have filed interventions, answers, or complaints with the PPUC in response to the Pennsylvania Companies’ request for approval of the DSIC filings raising cost allocation and other issues, and the Pennsylvania Companies have responded.

In April 2016, each of the Pennsylvania Companies intends to file tariffs with the PPUC proposing general rate increases associated with their distribution operations that will benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements.The filings will request approval to increase annual operating revenues by approximately$140.2 millionat ME,$158.8 millionat PN,$42.0 millionat Penn, and$98.2 millionat WP, based upon fully projected future test years for the twelve months ending December 31, 2017 at each of the Pennsylvania Companies. The new rates are expected to take effect in January 2017.

On June 19, 2015, ME and PN, along with JCP&L, FET and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT, a new transmission-only subsidiary of FET.On March 4, 2016, a Joint Petition for Full Settlement was submitted to the PPUC for consideration and approval. On April 18, 2016, the ALJs issued an Initial Decision approving the Joint Petition for Full Settlement without modifications.A final decision from the PPUC is expected by mid-2016. See Transfer of Transmission Assets to MAIT in FERC Matters below for further discussion of this transaction.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually.

MP and PE filed with the WVPSC on March 31, 2016 their Phase II energy efficiency program proposal for approval.MP and PE are proposing three energy efficiency programs to meet their Phase II requirement of energy efficiency reductions of0.5%of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period, as agreed to by MP and PE, and approved by the WVPSC in the 2012 proceeding approving the transfer of ownership of Harrison Power Station to MP.The costs for the program are expected to be$9.9 millionwhich would be recovered through the existing energy efficiency rider which is reviewed in the fuel (ENEC) case each year.MP and PE are requesting WVPSC approval by October 1, 2016 so MP and PE can implement the programs beginning January 1, 2017.

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, NG, 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 occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC.Moreover, it is clear that 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 electric system could result in the imposition of financial penalties, and obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows.

FERC MATTERS

Ohio ESP IV PPA

For information regarding matters before FERC related to the ESP IV PPA between FES and the Ohio Companies, see “Regulatory Matters - Ohio” above.

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 advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM.This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit.On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines.The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole.The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings.Settlement discussions under a FERC-appointed settlement judge are ongoing.

In a series of orders in certain Order No. 1000 dockets, FERC asserted that the PJM transmission owners do not hold an incumbent “right of first refusal” to construct, own and operate transmission projects within their respective footprints that are approved as part of PJM’s RTEP process.FirstEnergy and other PJM transmission owners have appealed these rulings, and the question of whether FirstEnergy and the PJM transmission owners have a "right of first refusal" is scheduled for oral argument on May 4, 2016, before the U.S. Court of Appeals for the D.C. Circuit in an appeal of FERC's order approving PJM's Order No.1000 compliance filing.

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.While many of the matters involved with the move have been resolved, FERC denied recovery under 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 demonstrating net benefits to customers from the transfer to PJM.Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, 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 March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis.

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 before FERC and certain United States appellate courts. On October 29, 2015, FERC issued an order finding that ATSI and the ATSI zone do not have to pay MISO MVP charges for the Michigan Thumb transmission project. MISO and the MISO TOs filed a request for rehearing, which is pending at FERC.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.On a related issue, FirstEnergy joined certain other PJM transmission owners in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region.On January 22, 2015, FERC issued an order establishing a paper hearing on remand from the Seventh Circuit of the issue of whether any limitation on "export pricing" for sales of energy from MISO into PJM is justified in light of applicable FERC precedent.Certain PJM transmission owners, including FirstEnergy, filed an initial brief asserting that FERC’s prior ruling rejecting MISO’s proposed MVP export charge on transactions into PJM was correct and should be re-affirmed on remand.The briefs and replies thereto remain before FERC for consideration.

In addition, in a May 31, 2011 order, FERC ruled that the costs for certain "legacy RTEP" transmission projects in PJM approved before ATSI joined PJM could be charged to transmission customers in the ATSI zone.The amount to be paid, and the question of derived benefits, is pending before FERC as a result of the Seventh Circuit's June 25, 2014 order described above under PJM Transmission Rates.

The outcome of the proceedings that address the remaining open issues related to costs for the "Michigan Thumb" transmission project and "legacy RTEP" transmission projects cannot be predicted at this time.

Transfer of Transmission Assets to MAIT

On June 10, 2015, MAIT, a Delaware limited liability company, was formed as a new transmission-only subsidiary of FET for the purposes of owning and operating all FERC-jurisdictional transmission assets of JCP&L, ME and PN following the receipt of all necessary state and federal regulatory approvals.On June 19, 2015, JCP&L, PN, ME, FET, and MAIT made filings with FERC, the NJBPU, and the PPUC requesting authorization for JCP&L, PN and ME to contribute their transmission assets to MAIT.Additionally, the filings requested approval from the NJBPU and PPUC, as applicable, of: (i) a lease to MAIT of real property and rights-of-way associated with the utilities' transmission assets; (ii) a Mutual Assistance Agreement; (iii) MAIT being deemed a public utility under state law; (iv) MAIT's participation in FE's regulated companies' money pool; and (v) certain affiliated interest agreements. If approved, JCP&L, ME, and PN will contribute their transmission assets at net book value and an allocated portion of goodwill in a tax-free exchange to MAIT, which will operate similar to FET's two existing stand-alone transmission subsidiaries, ATSI and TrAIL.MAIT's transmission facilities will remain under the functional control of PJM, and PJM will provide transmission service using these facilities under the PJM Tariff.FERC approved the transaction on February 18, 2016. Upon receipt of all applicable regulatory approvals with respect to the transfer,MAIT expects to file a Section 204 application with FERC, and other necessary filings with the PPUC and the NJBPU, seeking authorization to issue equity to FET, JCP&L, PN and ME for their respective contributions, and to issue debt.MAIT will also make a Section 205 formula rate application with FERC to establish its transmission rate. See New Jersey and Pennsylvania in State Regulation above for further discussion of this transaction.

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 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.The California parties appealed FERC's decision back to the Ninth Circuit.AE Supply joined with other intervenors in the case and filed a brief in support of FERC's dismissal of the case.On April 29, 2015, the Ninth Circuit remanded the case to FERC for further proceedings.On November 3, 2015, FERC set for hearing and settlement procedures the remanded issue of whether any individual public utility seller’s violation of FERC’s market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular seller in California during the 2000-2001 period.Settlement discussions under a FERC-appointed settlement judge are ongoing. On March 1, 2016, FERC issued an order on rehearing clarifying the scope of the evidentiary hearing and the standard of review on remand. In particular, FERC clarified that certain bilateral transactions, including those of AE Supply to the California parties, are protected by the Mobile-Sierra standard, which requires a demonstration of harm to the public interest to determine liability and obligation to make refunds. The California parties requested rehearing of FERC’s March 1, 2016 order, and also appealed FERC’s November 3, 2015, and March 1, 2016 orders to the Ninth Circuit, which has stayed its review pending the outcome of the ongoing proceeding discussed above.

In another proceeding, in May 2009, the California Attorney General, on behalf of certain California parties, filed a 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 and other parties filed motions to dismiss, which FERC granted.The California Attorney General 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.

The outcome of either of the above matters or estimate of loss or range of loss cannot be predicted at this time.

PATH Transmission Project

On August 24, 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland which PJM had previously suspended in February 2011.As a result of PJM canceling the project, 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.PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of10.9%(10.4%base plus0.5%for RTO membership) from PJM customers overfiveyears.FERC issued an order denying the0.5%ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to settlement proceedings and hearing if the parties could not agree to a settlement.On March 24, 2014, the FERC Chief ALJ terminated settlement proceedings and appointed an ALJ to preside over the hearing phase of the case, including discovery and additional pleadings leading up to hearing, which subsequently included the parties addressing the application of FERC's Opinion No. 531, discussed below, to the PATH proceeding.On September 14, 2015, the ALJ issued his initial decision, disallowing recovery of certain costs. The initial decision and exceptions thereto remain before FERC for review and a final order.FirstEnergy continues to believe the costs are recoverable, subject to final ruling from FERC.

FERC Opinion No. 531

On June 19, 2014, FERC issued Opinion No. 531, in which FERC revised its approach for calculating the discounted cash flow element of FERC’s ROE methodology, and announced the potential for a qualitative adjustment to the ROE methodology results.Under the old methodology, FERC used a five-year forecast for the dividend growth variable, whereas going forward the growth variable will consist of two parts: (a) a five-year forecast for dividend growth (2/3 weight); and (b) a long-term dividend growth forecast based on a forecast for the U.S. economy (1/3 weight).Regarding the qualitative adjustment, for single-utility rate cases FERC formerly pegged ROE at the median of the “zone of reasonableness” that came out of the ROE formula, whereas going forward, FERC may rely on record evidence to make qualitative adjustments to the outcome of the ROE methodology in order to reach a level sufficient to attract future investment.On October 16, 2014, FERC issued its Opinion No. 531-A, applying the revised ROE methodology to certain ISO New England transmission owners, andon March 3, 2015, FERC issued Opinion No. 531-B affirming its prior rulings.Appeals of Opinion Nos. 531, 532-A and 531-B are pending before the U.S. Court of Appeals for the D.C. Circuit.FirstEnergy is evaluating the potential impact of Opinion No. 531 on the authorized ROE of our FERC-regulated transmission utilities and the cost-of-service wholesale power generation transactions of MP.

MISO Capacity Portability

On June 11, 2012, in response to certain arguments advanced by MISO, FERC requested comments regarding whether existing rules on transfer capability act as barriers to the delivery of capacity between MISO and PJM.FirstEnergy and other parties submitted filings arguing that MISO's concerns largely are without foundation,FERC did not mandate a solution in response to MISO's concerns.At FERC's direction, in May, 2015, PJM, MISO, and their respective independent market monitors provided additional information on their various joint issues surrounding the PJM/MISO seam to assist FERC's understanding of the issues and what, if any, additional steps FERC should take to improve the efficiency of operations at the PJM/MISO seam.Stakeholders, including FESC on behalf of certain of its affiliates and as part of a coalition of certain other PJM utilities, filed responses to the RTO submissions.The various submissions and responses remain before FERC for consideration.

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.

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Commitments, Guarantees and Contingencies

3 Months Ended

Mar. 31, 2016

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, 2016, FirstEnergy's outstanding guarantees and other assurances aggregated approximately $3.7 billion, consisting of parental guarantees ($591 million), subsidiaries' guarantees ($2.1 billion), other guarantees ($300 million) and other assurances ($669 million).

Of this aggregate amount, substantially all relates to guarantees of wholly-owned consolidated entities of FirstEnergy. FES' debt obligations are generally guaranteed by its subsidiaries, FG and NG, and FES guarantees the debt obligations of each of FG and NG.Accordingly, present and future holders of indebtedness of FES, FG and NG would have claims against each of FES, FG and NG, regardless of whether their primary obligor is FES, FG or NG.

COLLATERAL AND CONTINGENT-RELATED FEATURES

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

Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral.Based on FES' power portfolio exposures as ofMarch 31, 2016, FES has posted collateral of$180 million.The Regulated Distribution segment has posted collateral of$1 million.

These credit-risk-related contingent features, or the margining provisions within bilateral agreements, 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, which is the ability to secure additional collateral when needed, 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 that may be required under certain events as ofMarch 31, 2016:

Collateral Provisions	FES/ AE Supply (Tied to FE Corp. Rating)		FES/ AE Supply (Tied to FES Rating)		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	25	$	173	$	40	$	238
Non-Investment Grade Ratings (All Rating Agencies at or below BB+/Ba1)	$	25	$	200	$	40	$	265
Total Exposure from Contractual Obligations	$	25	$	341	$	40	$	406

Excluded from the preceding table are the potential collateral obligations due to affiliate transactions between the Regulated Distribution segment and CES segment.As ofMarch 31, 2016, 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 would be required to post$3 million with affiliated parties.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a syndicated senior secured term loan facility due March 3, 2020, under which Global Holding borrowed $300 million. 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, continue to provide their joint and several guaranties of the obligations of Global Holding under the 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 under the current facility as collateral.

During the first quarter of 2015, a subsidiary of Global Holding eliminated its right to put 2 million tons annually through 2024 from the Signal Peak mine to FG in exchange for FE extending its guarantee under Global Holding's $300 million senior secured term loan facility through 2020, resulting in a pre-tax charge of $24 million.See Note 6, Variable Interest Entities, for additional information regarding FEV's investment in Global Holding.

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.

Clean Air Act

FirstEnergy complies with SO₂and NOx emission 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.

CSAPR requires reductions of NOx and SO₂emissions intwophases (2015 and 2017), 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.The U.S. Court of Appeals for the D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia.This follows the 2014 U.S. Supreme Court ruling generally upholding EPA’s regulatory approach under CSAPR, but questioning whether EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states.EPA proposed a CSAPR update rule on November 16, 2015, that would reduce summertime NOx emissions from power plants in 23 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017.Depending on how the EPA and the states implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's and FES' operations may result.

EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of75PPB to70PPB on October 1, 2015.EPA stated the vast majority of U.S. counties will meet the new70PPB standard by 2025 due to other federal and state rules and programs but EPA will designate those counties that fail to attain the new 2015 ozone NAAQS by October 1, 2017.States will then have roughlythreeyears to develop implementation plans to attain the new 2015 ozone NAAQS.Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s and FES’ operations may result.

MATS imposes emission limits for mercury, PM, and HCl for all existing and new fossil fuel fired electric generating units effective in April 2015 with averaging of emissions from multiple units located at a single plant.FirstEnergy's total capital cost for compliance (over the 2012 to 2018 time period) is currently expected to be approximately$345 million(CES segment of$168 millionand Regulated Distribution segment of$177 million), of which$226 millionhas been spent through March 31, 2016 ($96 millionat CES and$130 millionat Regulated Distribution).

On August 3, 2015, FG, a subsidiary of FES, submitted to the AAA office in New York, N.Y., a demand for arbitration and statement of claim against BNSF and CSX seeking a declaration that MATS constituted a force majeure that excuses FG’s performance under its coal transportation contract with these parties.Specifically, the dispute arises from a contract for the transportation by BNSF and CSX of a minimum of3.5 milliontons of coal annually through 2025 to certain coal-fired power plants owned by FG that are located in Ohio. As a result of and in compliance with MATS, those plants were deactivated by April 16, 2015.In January 2012, FG notified BNSF and CSX that MATS constituted a force majeure event under the contract that excused FG’s further performance.Separately, on August 4, 2015, BNSF and CSX submitted to the AAA office in Washington, D.C., a demand for arbitration and statement of claim against FG alleging that FG breached the contract and that FG’s declaration of a force majeure under the contract is not valid and seeking damages including, but not limited to, lost profits under the contract through 2025.As part of its statement of claim, a right to liquidated damages is alleged. The arbitration panel has determined to consolidate the claims with a liability hearing expected to begin in November 2016, and, if necessary, a damages hearing is expected to begin in May 2017. The decision on liability is expected to be issued within sixty days from the end of the liability hearings. FirstEnergy and FES continue to believe that MATS constitutes a force majeure event under the contract as it relates to the deactivated plants and that FG’s performance under the contract is therefore excused.FirstEnergy and FES intend to vigorously assert their position in the arbitration proceedings.If, however, the arbitration panel rules in favor of BNSF and CSX, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.FirstEnergy and FES are unable to estimate the loss or range of loss.

FG is also a party to another coal transportation contract covering the delivery of 2.5 milliontons annually through 2025, a portion of which is to be delivered to another coal-fired plant owned by FG that was deactivated as a result of MATS.FG has asserted a defense of force majeure in response to delivery shortfalls to such plant under this contract as well.If FirstEnergy and FES fail to reach a resolution with the applicable counterparties to the contract, and if it were ultimately determined that, contrary to FirstEnergy’s and FES’ belief, the force majeure provisions of that contract do not excuse the delivery shortfalls to the deactivated plant, the results of operations and financial condition of both FirstEnergy and FES could be materially adversely impacted.FirstEnergy and FES are unable to estimate the loss or range of loss.

As to both coal transportation agreements referenced above, FES paid in settlement approximately$70 millionin liquidated damages for delivery shortfalls in 2014 related to its deactivated plants.

As to a specific coal supply agreement, FirstEnergy and AE Supply have asserted termination rights effective in 2015.In response to notification of the termination, the coal supplier commenced litigation alleging FirstEnergy and AE Supply do not have sufficient justification to terminate the agreement. FirstEnergy and AE Supply have filed an answer denying any liability related to the termination.This matter is currently in the discovery phase of litigation and no trial date has been established. There are approximately 5.5 milliontons remaining under the contract for delivery.At this time, FirstEnergy cannot estimate the loss or range of loss regarding the on-going litigation with respect to this agreement.

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.The EPA's NOV alleges equipment replacements during maintenance outages triggered the pre-construction permitting requirements under the NSR and PSD programs.On June 29, 2012, January 31, 2013, and March 27, 2013, EPA issued 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.On December 12, 2014, EPA issued a CAA section 114 request for the Fort Martin coal-fired plant seeking information and documentation relevant to its operation and maintenance, including capital projects undertaken since 2009.FirstEnergy intends to comply with the CAA but, at this time, is unable to predict the outcome of this matter or estimate the loss or range of loss.

Climate Change

FirstEnergy has established a goal to reduce CO₂ emissions by90%below 2005 levels by 2045.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 reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants.The EPA released its final regulations in August 2015, to reduce CO₂emissions from existing fossil fuel fired electric generating units that would require each state to develop SIPs by September 6, 2016, to meet the EPA’s state specific CO₂emission rate goals.The EPA’s CPP allows states to request atwo-year extension to finalize SIPs by September 6, 2018.If states fail to develop SIPs, the EPA also proposed a federal implementation plan that can be implemented by the EPA that included model emissions trading rules which states can also adopt in their SIPs.The EPA also finalized separate regulations imposing CO₂emission limits for new, modified, and reconstructed fossil fuel fired electric generating units.On June 23, 2014, the United States Supreme Court decided that CO₂or other GHG emissions alone cannot trigger permitting requirements under the CAA, but that air emission sources that need PSD permits due to other regulated air pollutants can be required by the EPA to install GHG control technologies.Numerous states and private parties filed appeals and motions to stay the CPP with the U.S. Court of Appeals for the D.C. Circuit in October 2015.On January 21, 2015, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument.On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court.Depending on the outcome of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

At the international level, the United Nations Framework Convention on Climate Change resulted in the Kyoto Protocol requiring participating countries, which does not include the U.S., to reduce GHGs commencing in 2008 and has been extended through 2020.The Obama Administration submitted in March 2015, a formal pledge for the U.S. to reduce its economy-wide greenhouse gas emissions by 26 to 28 percent below 2005 levels by 2025 and joined in adopting the agreement reached on December 12, 2015 at the United Nations Framework Convention on Climate Change meetings in Paris.The Paris Agreement must be ratified by at least 55 countries representing at least 55% of global GHG emissions before its non-binding obligations to limit global warming to well below two degrees Celsius become effective.FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO₂ emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations.The CO₂ emissions per KWH of electricity generated by FirstEnergy is lower than many of its regional competitors due to its diversified generation sources, which include low or non-CO₂ emitting gas-fired and nuclear generators.

Clean Water Act

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

The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system.FirstEnergy is studying various control options and their costs and effectiveness, including pilot testing of reverse louvers in a portion of the Bay Shore plant's cooling water intake channel to divert fish away from the plant's cooling water intake system.Depending on the results of such studies and any final action taken by the states based on those studies, the future capital costs of compliance with these standards may be substantial.

On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water.The treatment obligations will phase-in as permits are renewed on afive-year cycle from 2018 to 2023.The final rule also allows plants to commit to more stringent effluent limits for wet scrubber systems based on evaporative technology and in return have until the end of 2023 to meet the more stringent limits.Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's and FES' operations may result.

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 the appeal or estimate the possible loss or range of loss.

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

Regulation of Waste Disposal

Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act.Certain coal 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 2014, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards regarding landfill design, structural integrity design and assessment criteria for surface impoundments, groundwater monitoring and protection procedures and other operational and reporting procedures to assure the safe disposal of CCRs from electric generating plants.Based on an assessment of the finalized regulations, the future cost of compliance and expected timing of spend had no significant impact on FirstEnergy's or FES' existing AROs associated with CCRs.Although unexpected, changes in timing and closure plan requirements in the future could impact our asset retirement obligations significantly.

Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016 and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG 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 CCRs, 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 disposal of CCRs following December 31, 2016 and expects beneficial reuse and disposal options will be sufficient for the ongoing operation of the plant.On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR.On July 6, 2015 and October 22, 2015, the Sierra Club filed Notices of Appeal with the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility.

FirstEnergy or its subsidiaries 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 Sheets as ofMarch 31, 2016based 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$123 millionhave been accrued throughMarch 31, 2016. Included in the total are accrued liabilities of approximately$87 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 loss 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, 2016, FirstEnergy had approximately$2.4 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 NDTs 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 NDTs.FE and FES have also entered into a total of$24.5 millionin parental guarantees in support of the decommissioning of the spent fuel storage facilities located at the nuclear facilities.As required by the NRC, FirstEnergy annually recalculates and adjusts the amount of its parental guarantees, as appropriate.

In August 2010, FENOC submitted an application to the NRC for renewal of the Davis-Besse operating license for an additional twenty years.On December 8, 2015, the NRC renewed the operating license for Davis-Besse, which is now authorized to continue operation through April 22, 2037.Prior to that decision, the NRC Commissioners denied an intervenor's request to reopen the record and admit a contention on the NRC’s Continued Storage Rule.On August 6, 2015, this intervenor sought review of the NRC Commissioners' decision before the U.S. Court of Appeals for the DC Circuit. FENOC intervened in that proceeding.

As part of routine inspections of the concrete shield building at Davis-Besse in 2013, FENOC identified changes to the subsurface laminar cracking condition originally discovered in 2011.These inspections revealed that the cracking condition had propagated a small amount in select areas.FENOC's analysis confirms that the building continues to maintain its structural integrity, and its ability to safely perform all of its functions.In a May 28, 2015, Inspection Report regarding the apparent cause evaluation on crack propagation, the NRC issued a non-cited violation for FENOC’s failure to request and obtain a license amendment for its method of evaluating the significance of the shield building cracking.The NRC also concluded that the shield building remained capable of performing its design safety functions despite the identified laminar cracking and that this issue was of very low safety significance.FENOC plans to submit a license amendment application related to the Shield Building analysis in 2016.

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 FirstEnergy's nuclear facilities.

Other Legal Matters

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.

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Supplemental Guarantor Information

3 Months Ended

Mar. 31, 2016

Supplemental Guarantor Information [Abstract]

SUPPLEMENTAL GUARANTOR INFORMATION

SUPPLEMENTAL GUARANTOR INFORMATION

In 2007, FG completed a sale and leaseback transaction for a 93.83% 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 (Loss) and Comprehensive Income (Loss) for the three months ended March 31, 2016 and 2015, Condensed Consolidating Balance Sheets as of March 31, 2016 and December 31, 2015, and Condensed Consolidating Statements of Cash Flows for the three months ended March 31, 2016 and 2015, for FES (parent and guarantor), FG and NG (non-guarantor) are presented below. These statements are provided as FES fully and unconditionally guarantees outstanding registered securities of FG as well as FG's obligations under the facility lease for the Bruce Mansfield sale and leaseback that underlie outstanding registered pass-through trust certificates. 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
For the Three Months Ended March 31, 2016	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,155		$	415		$	531		$	(902	)	$	1,199
OPERATING EXPENSES:
Fuel	—			119			46			—			165
Purchased power from affiliates	927			—			57			(902		)	82
Purchased power from non-affiliates	377			—			—			—			377
Other operating expenses	4			71			153			12			240
Provision for depreciation	3			31			50			(1		)	83
General taxes	8			10			8			—			26
Total operating expenses	1,319			231			314			(891		)	973
OPERATING INCOME (LOSS)	(164		)	184			217			(11		)	226
OTHER INCOME (EXPENSE):
Investment income, including net income from equity investees	251			6			17			(259		)	15
Interest expense — affiliates	(9		)	(2		)	(2		)	11			(2		)
Interest expense — other	(13		)	(26		)	(11		)	14			(36		)
Capitalized interest	—			2			8			—			10
Total other income (expense)	229			(20		)	12			(234		)	(13		)
INCOME BEFORE INCOME TAXES (BENEFITS)	65			164			229			(245		)	213
INCOME TAXES (BENEFITS)	(66		)	61			86			1			82
NET INCOME	$	131		$	103		$	143		$	(246	)	$	131
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	131		$	103		$	143		$	(246	)	$	131
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(4		)	(3		)	—			3			(4		)
Change in unrealized gain on available-for-sale securities	23			—			23			(23		)	23
Other comprehensive income (loss)	19			(3		)	23			(20		)	19
Income taxes (benefits) on other comprehensive income (loss)	7			(1		)	8			(7		)	7
Other comprehensive income (loss), net of tax	12			(2		)	15			(13		)	12
COMPREHENSIVE INCOME	$	143		$	101		$	158		$	(259	)	$	143

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	1,332		$	493		$	507		$	(955	)	$	1,377
OPERATING EXPENSES:
Fuel	—			180			50			—			230
Purchased power from affiliates	957			—			68			(955		)	70
Purchased power from non-affiliates	543			—			—			—			543
Other operating expenses	180			67			154			12			413
Provision for depreciation	3			30			48			(1		)	80
General taxes	15			8			6			—			29
Total operating expenses	1,698			285			326			(944		)	1,365
OPERATING INCOME (LOSS)	(366		)	208			181			(11		)	12
OTHER INCOME (EXPENSE):
Investment income, including net income from equity investees	241			3			14			(245		)	13
Interest expense — affiliates	(6		)	(2		)	(1		)	7			(2		)
Interest expense — other	(13		)	(26		)	(13		)	15			(37		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	222			(24		)	8			(223		)	(17		)
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)	(144		)	184			189			(234		)	(5		)
INCOME TAXES (BENEFITS)	(141		)	67			70			2			(2		)
NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(4		)	(4		)	3			1			(4		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available-for-sale securities	3			—			—			—			3
Other comprehensive income (loss)	(2		)	(4		)	3			1			(2		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(1		)	1			—			(1		)
Other comprehensive income (loss), net of tax	(1		)	(3		)	2			1			(1		)
COMPREHENSIVE INCOME (LOSS)	$	(4	)	$	114		$	121		$	(235	)	$	(4	)

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of March 31, 2016	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	229		—		—		—			229
Affiliated companies	442		310		305		(610		)	447
Other	32		1		74		—			107
Notes receivable from affiliated companies	394		1,429		889		(2,712		)	—
Materials and supplies	39		191		216		—			446
Derivatives	207		—		—		—			207
Collateral	80		—		—		—			80
Prepayments and other	69		11		—		—			80
	1,492		1,944		1,484		(3,322		)	1,598
PROPERTY, PLANT AND EQUIPMENT:
In service	92		6,389		8,277		(382		)	14,376
Less — Accumulated provision for depreciation	43		2,163		3,863		(195		)	5,874
	49		4,226		4,414		(187		)	8,502
Construction work in progress	30		271		972		—			1,273
	79		4,497		5,386		(187		)	9,775
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,372		—			1,372
Investment in affiliated companies	7,712		—		—		(7,712		)	—
Other	—		10		—		—			10
	7,712		10		1,372		(7,712		)	1,382
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	276		—		—		(276		)	—
Customer intangibles	57		—		—		—			57
Goodwill	23		—		—		—			23
Property taxes	—		9		21		—			30
Derivatives	89		—		—		—			89
Other	24		301		4		56			385
	469		310		25		(220		)	584
	$	9,752	$	6,761	$	8,267	$	(11,441	)	$	13,339
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—	$	266	$	308	$	(25	)	$	549
Short-term borrowings-
Affiliated companies	2,373		386		2		(2,712		)	49
Accounts payable-
Affiliated companies	619		190		172		(619		)	362
Other	26		90		—		—			116
Accrued taxes	3		52		101		(85		)	71
Derivatives	115		—		—		—			115
Other	75		74		15		77			241
	3,211		1,058		598		(3,364		)	1,503
CAPITALIZATION:
Total equity	5,749		3,046		4,634		(7,680		)	5,749
Long-term debt and other long-term obligations	690		2,067		840		(1,117		)	2,480
	6,439		5,113		5,474		(8,797		)	8,229
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		782			782
Accumulated deferred income taxes	6		35		743		(62		)	722
Retirement benefits	28		311		—		—			339
Asset retirement obligations	—		188		650		—			838
Derivatives	21		—		—		—			21
Other	47		56		802		—			905
	102		590		2,195		720			3,607
	$	9,752	$	6,761	$	8,267	$	(11,441	)	$	13,339

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2015	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	275		—		—		—			275
Affiliated companies	433		403		461		(846		)	451
Other	36		4		19		—			59
Notes receivable from affiliated companies	406		1,210		805		(2,410		)	11
Materials and supplies	53		204		213		—			470
Derivatives	154		—		—		—			154
Collateral	70		—		—		—			70
Prepayments and other	48		18		—		—			66
	1,475		1,841		1,498		(3,256		)	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	93		6,367		8,233		(382		)	14,311
Less — Accumulated provision for depreciation	40		2,144		3,775		(194		)	5,765
	53		4,223		4,458		(188		)	8,546
Construction work in progress	30		249		878		—			1,157
	83		4,472		5,336		(188		)	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,327		—			1,327
Investment in affiliated companies	7,452		—		—		(7,452		)	—
Other	—		10		—		—			10
	7,452		10		1,327		(7,452		)	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	300		16		—		(316		)	—
Customer intangibles	61		—		—		—			61
Goodwill	23		—		—		—			23
Property taxes	—		12		28		—			40
Derivatives	79		—		—		—			79
Other	29		312		14		12			367
	492		340		42		(304		)	570
	$	9,502	$	6,663	$	8,203	$	(11,200	)	$	13,168
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—	$	229	$	308	$	(25	)	$	512
Short-term borrowings-
Affiliated companies	2,021		389		—		(2,410		)	—
Other	—		8		—		—			8
Accounts payable-
Affiliated companies	884		146		368		(856		)	542
Other	21		118		—		—			139
Accrued taxes	7		93		62		(86		)	76
Derivatives	103		1		—		—			104
Other	66		61		9		45			181
	3,102		1,045		747		(3,332		)	1,562
CAPITALIZATION:
Total equity	5,605		2,944		4,476		(7,420		)	5,605
Long-term debt and other long-term obligations	690		2,116		840		(1,136		)	2,510
	6,295		5,060		5,316		(8,556		)	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		791			791
Accumulated deferred income taxes	6		—		697		(103		)	600
Retirement benefits	27		305		—		—			332
Asset retirement obligations	—		191		640		—			831
Derivatives	37		1		—		—			38
Other	35		61		803		—			899
	105		558		2,140		688			3,491
	$	9,502	$	6,663	$	8,203	$	(11,200	)	$	13,168

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2016	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(356	)	$	277		$	307		$	—		$	228
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	352			8			1			(312		)	49
Redemptions and Repayments-
Short-term borrowings, net	—			(11		)	—			11			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	352			(5		)	1			(301		)	47
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27		)	(53		)	(63		)	—			(143		)
Nuclear fuel	—			—			(149		)	—			(149		)
Sales of investment securities held in trusts	—			—			138			—			138
Purchases of investment securities held in trusts	—			—			(151		)	—			(151		)
Cash investments	10			—			—			—			10
Loans to affiliated companies, net	12			(219		)	(83		)	301			11
Other	9			—			—			—			9
Net cash provided from (used for) investing activities	4			(272		)	(308		)	301			(275		)
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

For the Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(662	)	$	222		$	545		$	—		$	105
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	674			—			—			(524		)	150
Redemptions and Repayments-
Long-term debt	(17		)	—			—			—			(17		)
Short-term borrowings, net	—			(5		)	(28		)	33			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	657			(7		)	(28		)	(491		)	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1		)	(36		)	(82		)	—			(119		)
Nuclear fuel	—			—			(60		)	—			(60		)
Sales of investment securities held in trusts	—			—			189			—			189
Purchases of investment securities held in trusts	—			—			(202		)	—			(202		)
Loans to affiliated companies, net	6			(179		)	(362		)	491			(44		)
Net cash provided from (used for) investing activities	5			(215		)	(517		)	491			(236		)
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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Segment Information

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

FirstEnergy's reportable segments are as follows: Regulated Distribution, Regulated Transmission, and CES.

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 located primarily in West Virginia, Virginia and New Jersey that MP and JCP&L, respectively, own or contractually control. The segment's results reflect the commodity costs of securing electric generation and the deferral and amortization of certain fuel costs. As of March 31, 2016, this business segment controlled3,790MWs of generating 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). This segment also includes the regulatory asset associated with the abandoned PATH project. The segment's revenues are primarily derived from forward-looking rates at ATSI and TrAIL, as well as fixed rates at certain of FirstEnergy’s utilities. Both the forward-looking and fixed rates recover costs and provide a return on transmission capital investment. Under the forward-looking rates, each of ATSI's and TrAIL’s revenue requirement is updated annually based on a projected rate base and projected costs, subject to annual true-up. Except for the recovery of the PATH abandoned project regulatory asset, the segment's revenues are primarily from transmission services provided to LSEs pursuant to the PJM Tariff. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities.

The CES segment, through FES and AE Supply, primarily 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. As of March 31, 2016, this business segment controlled13,162MWs of generating capacity.The CES 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 and capacity costs charged by PJM to deliver energy to the segment’s customers.

Corporate support and other businesses that do not constitute an operating segment, interest expense on stand-alone holding company debt and corporate income taxes are categorized as Corporate/Other for reportable business segment purposes. Additionally, reconciling adjustments for the elimination of inter-segment transactions are included in Corporate/Other.As of March 31, 2016, Corporate/Other had $4.2 billion of stand-alone holding company long-term debt, of which 28% was subject to variable-interest rates, and $2.1 billion was borrowed by FE under its revolving credit facility.

Segment Financial Information

Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)
March 31, 2016
External revenues	$	2,521	$	275	$	1,152		$	(42	)	$	(37	)	$	3,869
Internal revenues	—		—		152			—			(152		)	—
Total revenues	2,521		275		1,304			(42		)	(189		)	3,869
Depreciation	169		43		102			15			—			329
Amortization of regulatory assets, net	59		2		—			—			—			61
Investment income	11		—		15			11			(9		)	28
Interest expense	147		43		47			51			—			288
Income taxes (benefits)	98		43		85			(13		)	—			213
Net income (loss)	165		74		144			(55		)	—			328
Total assets	27,907		7,679		16,578			531			—			52,695
Total goodwill	5,092		526		800			—			—			6,418
Property additions	262		258		169			9			—			698
March 31, 2015
External revenues	$	2,562	$	238	$	1,175		$	(42	)	$	(36	)	$	3,897
Internal revenues	—		—		260			—			(260		)	—
Total revenues	2,562		238		1,435			(42		)	(296		)	3,897
Depreciation	172		37		96			14			—			319
Amortization of regulatory assets, net	29		3		—			—			—			32
Investment income	13		—		12			2			(10		)	17
Interest expense	144		39		48			47			1			279
Income taxes (benefits)	122		42		(4		)	(18		)	2			144
Net income (loss)	208		72		(8		)	(50		)	—			222
Total assets	27,974		6,601		16,497			807			—			51,879
Total goodwill	5,092		526		800			—			—			6,418
Property additions	280		254		126			8			—			668

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Organization and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2016

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 necessarily 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 as appropriate. 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 do not have a controlling financial interest, 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 of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income and Comprehensive Income.

New Accounting Pronouncements

New Accounting Pronouncements

In May 2014, the FASB issued, ASU 2014-09 "Revenue from Contracts with Customers", requiring entities to recognize revenue by applying a five-step model in accordance with the core principle to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In addition, the accounting for costs to obtain or fulfill a contract with a customer is specified and disclosure requirements for revenue recognition are expanded.In August 2015, the FASB issued a final ASU deferring the effective date until fiscal years beginning after December 15, 2017. Earlier application is permitted only as of annual reporting periods beginning after December 15, 2016, (the original effective date). In March 2016, the FASB issued ASU 2016-08, “Principal versus Agent Considerations (Reporting Revenue Gross versus Net)", clarifying the principal versus agent implementation guidance in the following areas: unit of account at which the principal/agent determination is made; applying the control principle to certain types of transactions and the control principle and principal/agent indicators.In April 2016, the FASB issued ASU 2016-10, “Identifying Performance Obligations and Licensing”, clarifying the identification of performance obligations and the licensing implementation guidance.The standards shall be applied retrospectively to each period presented or as a cumulative-effect adjustment as of the date of adoption. FirstEnergy is currently evaluating the impact on its financial statements of adopting these standards.

In February 2015, the FASB issued, ASU 2015-02 "Consolidations: Amendments to the Consolidation Analysis", which amends current consolidation guidance including changes to both the variable and voting interest models used by companies to evaluate whether an entity should be consolidated.A reporting entity must apply the amendments using a modified retrospective approach by recording a cumulative-effect adjustment to equity as of the beginning of the period of adoption or apply the amendments retrospectively. FirstEnergy's adoption of ASU 2015-02, on January 1, 2016, did not result in a change in the consolidation of VIEs by FirstEnergy or its subsidiaries. See Note 6, Variable Interest Entities, for additional information.

In April 2015, the FASB issued, ASU 2015-03 "Simplifying the Presentation of Debt Issuance Costs", which requires debt issuance costs to be presented on the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. In addition, in August 2015, the FASB issued ASU 2015-15, "Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements", which allows debt issuance costs related to line of credit arrangements to be presented as an asset and amortized ratably over the term of the arrangement, regardless of whether there are any outstanding borrowings on the line-of-credit. FirstEnergy adopted ASU 2015-15 and ASU 2015-03 beginning January 1, 2016. As of December 31, 2015, FirstEnergy and FES reclassified$93 million and $17 millionof debt issuance costs included in Deferred Charges and Other Assets to Long-term Debt and Other Long-term Obligations. FirstEnergy will elect to continue presenting debt issuance costs relating to its revolving credit facilities as an asset.

In January of 2016, the FASB issued ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities", which primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. In addition, the FASB clarified guidance related to the valuation allowance assessment when recognizing deferred tax assets resulting from unrealized losses on available-for-sale debt securities. The ASU will be effective in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.Early adoption can be elected for all financial statements of fiscal years and interim periods that have not yet been issued or that have not yet been made available for issuance. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In February 2016, the FASB issued ASU 2016-02, "Leases (Topic 842)", which will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets.In addition, new qualitative and quantitative disclosures of the amounts, timing, and uncertainty of cash flows arising from leases will be required.The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2018, with early adoption permitted. Lessors and lessees will be required to apply a modified retrospective transition approach, which requires adjusting the accounting for any leases existing at the beginning of the earliest comparative period presented in the adoption-period financial statements. Any leases that expire before the initial application date will not require any accounting adjustment. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

In March of 2016, the FASB issued ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting", which simplifies several aspects of the accounting for employee share-based payment. The new guidance will require all income tax effects of awards to be recognized in the income statement when the awards vest or are settled. It also will not require liability accounting when an employer repurchases more of an employee’s shares for tax withholding purposes. The ASU will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2016, with early adoption permitted. FirstEnergy is currently evaluating the impact on its financial statements of adopting this standard.

Additionally, in March of 2016, the FASB issued the following ASUs:

• ASU 2016-05, “Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships”,

• ASU 2016-06, “Contingent Put and Call Options in Debt Instruments (a consensus of the FASB Emerging Issues Task Force)", and

• ASU 2016-07, “Simplifying the Transition to the Equity Method of Accounting”.

FirstEnergy does not expect these ASUs to have a material effect on its financial statements.

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 based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance, and (ii) 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.

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.

Investment Policy

All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include held-to-maturity securities and AFS securities.

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 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.

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.

Derivatives Instruments Policy

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows:

• Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings.

• Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings.

• Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted.

Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.

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Earnings Per Share Of Common Stock (Tables)

3 Months Ended

Mar. 31, 2016

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)	For the Three Months Ended March 31
Reconciliation of Basic and Diluted Earnings per Share of Common Stock	2016		2015
Net income	$	328	$	222
Weighted average number of basic shares outstanding	424		421
Assumed exercise of dilutive stock options and awards(1)	2		2
Weighted average number of diluted shares outstanding	426		423
Basic earnings per share of common stock	$	0.78	$	0.53
Diluted earnings per share of common stock	$	0.77	$	0.53

⁽¹⁾  For both the three months ended March 31, 2016 and March 31, 2015, one million shares were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive.

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Pension and Other Postemployment Benefits (Tables)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Costs

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

Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended March 31	2016			2015			2016			2015
	(In millions)
Service costs	$	48		$	48		$	1		$	1
Interest costs	100			96			7			7
Expected return on plan assets	(97		)	(111		)	(8		)	(8		)
Amortization of prior service costs (credits)	2			2			(20		)	(33		)
Net periodic costs (credits)	$	53		$	35		$	(20	)	$	(33	)

Net Periodic Pension and OPEB Costs

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

	Pension				OPEB
	2016		2015		2016			2015
	(In millions)
For the Three Months Ended March 31	$	6	$	4	$	(4	)	$	(5	)

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

Net Periodic Benefit Expense (Credit)	Pension				OPEB
For the Three Months Ended March 31	2016		2015		2016			2015
	(In millions)
FirstEnergy	$	37	$	25	$	(15	)	$	(23	)
FES	6		4		(4		)	(4		)

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Accumulated Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2016

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income

The changes in AOCI, net of tax, in the three months ended March 31, 2016 and 2015, for FirstEnergy are included 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, 2016	$	(33	)	$	18		$	186		$	171
Other comprehensive income before reclassifications	—			41			—			41
Amounts reclassified from AOCI	2			(13		)	(18		)	(29		)
Other comprehensive income (loss)	2			28			(18		)	12
Income tax (benefits) on other comprehensive income (loss)	1			10			(7		)	4
Other comprehensive income (loss), net of tax	1			18			(11		)	8
AOCI Balance as of March 31, 2016	$	(32	)	$	36		$	175		$	179
AOCI Balance as of January 1, 2015	$	(37	)	$	25		$	258		$	246
Other comprehensive income before reclassifications	—			14			—			14
Amounts reclassified from AOCI	1			(10		)	(31		)	(40		)
Other comprehensive income (loss)	1			4			(31		)	(26		)
Income tax (benefits) on other comprehensive income (loss)	—			1			(11		)	(10		)
Other comprehensive income (loss), net of tax	1			3			(20		)	(16		)
AOCI Balance as of March 31, 2015	$	(36	)	$	28		$	238		$	230

Reclassification out of Accumulated Other Comprehensive Income

The following amounts were reclassified from AOCI for FirstEnergy in the three months ended March 31, 2016 and 2015:

		For the Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI (2)		2016			2015
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts		$	—		$	(1	)	Other operating expenses
Long-term debt		2			2			Interest expense
		2			1			Total before taxes
		(1		)	—			Income taxes
		$	1		$	1		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities		$	(13	)	$	(10	)	Investment income
		5			4			Income taxes
		$	(8	)	$	(6	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs		$	(18	)	$	(31	)	(1)
		7			11			Income taxes
		$	(11	)	$	(20	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.

FES

Accumulated Other Comprehensive Income (Loss) [Line Items]

Schedule of Accumulated Other Comprehensive Income

The changes in AOCI, net of tax, in the three months ended March 31, 2016 and 2015, for FES are included in the following tables:

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, 2016	$	(9	)	$	16		$	39		$	46
Other comprehensive income before reclassifications	—			36			—			36
Amounts reclassified from AOCI	—			(13		)	(4		)	(17		)
Other comprehensive income (loss)	—			23			(4		)	19
Income tax (benefits) on other comprehensive income (loss)	—			9			(2		)	7
Other comprehensive income (loss), net of tax	—			14			(2		)	12
AOCI Balance as of March 31, 2016	$	(9	)	$	30		$	37		$	58
AOCI Balance as of January 1, 2015	$	(7	)	$	21		$	43		$	57
Other comprehensive income before reclassifications	—			13			—			13
Amounts reclassified from AOCI	(1		)	(10		)	(4		)	(15		)
Other comprehensive income (loss)	(1		)	3			(4		)	(2		)
Income tax (benefits) on other comprehensive income (loss)	—			—			(1		)	(1		)
Other comprehensive income (loss), net of tax	(1		)	3			(3		)	(1		)
AOCI Balance as of March 31, 2015	$	(8	)	$	24		$	40		$	56

Reclassification out of Accumulated Other Comprehensive Income

The following amounts were reclassified from AOCI for FES in the three months ended March 31, 2016 and 2015:

		For the Three Months Ended March 31						Affected Line Item in Consolidated Statements of Income (Loss)
Reclassifications from AOCI (2)		2016			2015
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts		$	—		$	(1	)	Other operating expenses
		—			—			Income taxes (benefits)
		$	—		$	(1	)	Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities		$	(13	)	$	(10	)	Investment income
		5			4			Income taxes (benefits)
		$	(8	)	$	(6	)	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs		$	(4	)	$	(4	)	(1)
		2			1			Income taxes (benefits)
		$	(2	)	$	(3	)	Net of tax
(1) These AOCI components are included in the computation of net periodic pension cost. See Note 3, Pension and Other Postemployment Benefits for additional details.
(2) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI.

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Variable Interest Entities (Tables)

3 Months Ended

Mar. 31, 2016

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, 2016:

	Maximum Exposure		Discounted Lease Payments, net		Net Exposure
	(In millions)
FirstEnergy	$	1,228	$	967	$	261
FES	1,171		949		222

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Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2016

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, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	1,264		$	—		$	1,264		$	—		$	1,245		$	—		$	1,245
Derivative assets - commodity contracts	3			290			—			293			4			224			—			228
Derivative assets - FTRs	—			—			3			3			—			—			8			8
Derivative assets - NUG contracts(1)	—			—			1			1			—			—			1			1
Equity securities(2)	628			—			—			628			576			—			—			576
Foreign government debt securities	—			73			—			73			—			75			—			75
U.S. government debt securities	—			188			—			188			—			180			—			180
U.S. state debt securities	—			245			—			245			—			246			—			246
Other(3)	146			232			—			378			105			212			—			317
Total assets	$	777		$	2,292		$	4		$	3,073		$	685		$	2,182		$	9		$	2,876
Liabilities
Derivative liabilities - commodity contracts	$	(7	)	$	(122	)	$	—		$	(129	)	$	(9	)	$	(122	)	$	—		$	(131	)
Derivative liabilities - FTRs	—			—			(9		)	(9		)	—			—			(13		)	(13		)
Derivative liabilities - NUG contracts(1)	—			—			(136		)	(136		)	—			—			(137		)	(137		)
Total liabilities	$	(7	)	$	(122	)	$	(145	)	$	(274	)	$	(9	)	$	(122	)	$	(150	)	$	(281	)
Net assets (liabilities)(4)	$	770		$	2,170		$	(141	)	$	2,799		$	676		$	2,060		$	(141	)	$	2,595

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

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the Alerian MLP Index or the Wells Fargo Hybrid and Preferred Securities REIT index.

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

⁽⁴⁾  Excludes $(6) million and $7 million as of March 31, 2016 and December 31, 2015, 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 and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended March 31, 2016 and December 31, 2015:

	NUG Contracts(1)									FTRs
	Derivative Assets			Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2015 Balance	$	2		$	(153	)	$	(151	)	$	39		$	(14	)	$	25
Unrealized gain (loss)	2			(49		)	(47		)	(5		)	(7		)	(12		)
Purchases	—			—			—			22			(11		)	11
Settlements	(3		)	65			62			(48		)	19			(29		)
December 31, 2015 Balance	$	1		$	(137	)	$	(136	)	$	8		$	(13	)	$	(5	)
Unrealized loss	—			(12		)	(12		)	—			(1		)	(1		)
Settlements	—			13			13			(5		)	5			—
March 31, 2016 Balance	$	1		$	(136	)	$	(135	)	$	3		$	(9	)	$	(6	)

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

Quantitative information for level 3 valuation

The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended March 31, 2016:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(6	)	Model	RTO auction clearing prices	($4.60) to $3.70	$0.60	Dollars/MWH
NUG Contracts	$	(135	)	Model	Generation	400 to 3,651,000	777,000	MWH
					Regional electricity prices	$37.30 to $45.60	$39.60	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, 2016 and December 31, 2015:

	March 31, 2016(1)						December 31, 2015(2)
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt securities
FirstEnergy	$	1,776	$	44	$	1,820	$	1,778	$	16	$	1,794
FES	825		26		851		801		9		810
Equity securities
FirstEnergy	$	576	$	52	$	628	$	542	$	34	$	576
FES	372		36		408		354		24		378

⁽¹⁾  Excludes short-term cash investments: FE Consolidated - $161 million; FES - $113 million.

⁽²⁾  Excludes short-term cash investments: FE Consolidated - $157 million; FES - $139 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, 2016 and 2015 were as follows:

Three Months Ended
March 31, 2016	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	465	$	61	$	(50	)	$	(9	)	$	23
FES	138		42		(29		)	(8		)	13
March 31, 2015	Sale Proceeds		Realized Gains		Realized Losses			OTTI			Interest and Dividend Income
	(In millions)
FirstEnergy	$	371	$	60	$	(50	)	$	(7	)	$	25
FES	189		38		(28		)	(6		)	14

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, 2016 and December 31, 2015:

	March 31, 2016						December 31, 2015
	Cost Basis		Unrealized Gains		Fair Value		Cost Basis		Unrealized Gains		Fair Value
	(In millions)
Debt Securities
FirstEnergy	$	6	$	1	$	7	$	6	$	2	$	8

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 debt issuance costs, premiums and discounts:

	March 31, 2016				December 31, 2015
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(In millions)
FirstEnergy	$	20,217	$	21,821	$	20,244	$	21,519
FES	3,036		3,112		3,027		3,121

FES

Fair Value of Financial Instruments [Line Items]

Assets and liabilities measured on recurring basis

FES
Recurring Fair Value Measurements	March 31, 2016												December 31, 2015
	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—		$	715		$	—		$	715		$	—		$	678		$	—		$	678
Derivative assets - commodity contracts	3			290			—			293			4			224			—			228
Derivative assets - FTRs	—			—			3			3			—			—			5			5
Equity securities(1)	408			—			—			408			378			—			—			378
Foreign government debt securities	—			58			—			58			—			59			—			59
U.S. government debt securities	—			25			—			25			—			23			—			23
U.S. state debt securities	—			4			—			4			—			4			—			4
Other(2)	—			170			—			170			—			184			—			184
Total assets	$	411		$	1,262		$	3		$	1,676		$	382		$	1,172		$	5		$	1,559
Liabilities
Derivative liabilities - commodity contracts	$	(7	)	$	(122	)	$	—		$	(129	)	$	(9	)	$	(122	)	$	—		$	(131	)
Derivative liabilities - FTRs	—			—			(7		)	(7		)	—			—			(11		)	(11		)
Total liabilities	$	(7	)	$	(122	)	$	(7	)	$	(136	)	$	(9	)	$	(122	)	$	(11	)	$	(142	)
Net assets (liabilities)(3)	$	404		$	1,140		$	(4	)	$	1,540		$	373		$	1,050		$	(6	)	$	1,417

⁽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 $1 million as of March 31, 2016 and December 31, 2015, 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, 2016 and December 31, 2015:

	Derivative Asset			Derivative Liability			Net Asset (Liability)
	(In millions)
January 1, 2015 Balance	$	27		$	(13	)	$	14
Unrealized gain (loss)	2			(5		)	(3		)
Purchases	9			(10		)	(1		)
Settlements	(33		)	17			(16		)
December 31, 2015 Balance	$	5		$	(11	)	$	(6	)
Unrealized loss	—			(1		)	(1		)
Settlements	(2		)	5			3
March 31, 2016 Balance	$	3		$	(7	)	$	(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, 2016:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	(4	)	Model	RTO auction clearing prices	($4.60) to $3.70	$0.50	Dollars/MWH

XML

Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2016

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, 2016		December 31, 2015			March 31, 2016			December 31, 2015
	(In millions)					(In millions)
Current Assets - Derivatives					Current Liabilities - Derivatives
Commodity Contracts	$	205	$	150	Commodity Contracts	$	(109	)	$	(94	)
FTRs	2		7		FTRs	(8		)	(12		)
	207		157			(117		)	(106		)
Deferred Charges and Other Assets - Other					Noncurrent Liabilities - Adverse Power Contract Liability
					NUGs(1)	(136		)	(137		)
Commodity Contracts	88		78		Noncurrent Liabilities - Other
FTRs	1		1		Commodity Contracts	(20		)	(37		)
NUGs(1)	1		1		FTRs	(1		)	(1		)
	90		80			(157		)	(175		)
Derivative Assets	$	297	$	237	Derivative Liabilities	$	(274	)	$	(281	)

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

Offsetting assets and liabilities

The following tables summarize the fair value of derivative assets and derivative liabilities 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, 2016	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged			Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	293		$	(128	)	$	(25	)	$	140
FTRs	3			(3		)	—			—
NUG contracts	1			—			—			1
	$	297		$	(131	)	$	(25	)	$	141
Derivative Liabilities
Commodity contracts	$	(129	)	$	128		$	—		$	(1	)
FTRs	(9		)	3			6			—
NUG contracts	(136		)	—			—			(136		)
	$	(274	)	$	131		$	6		$	(137	)

				Amounts Not Offset in Consolidated Balance Sheet
December 31, 2015	Fair Value			Derivative Instruments			Cash Collateral (Received)/Pledged		Net Fair Value
	(In millions)
Derivative Assets
Commodity contracts	$	228		$	(125	)	$	—	$	103
FTRs	8			(8		)	—		—
NUG contracts	1			—			—		1
	$	237		$	(133	)	$	—	$	104
Derivative Liabilities
Commodity contracts	$	(131	)	$	125		$	3	$	(3	)
FTRs	(13		)	8			5		—
NUG contracts	(137		)	—			—		(137		)
	$	(281	)	$	133		$	8	$	(140	)

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, 2016:

	Purchases	Sales	Net		Units
	(In millions)
Power Contracts	14	42	(28	)	MWH
FTRs	15	—	15		MWH
NUGs	4	—	4		MWH
Natural Gas	81	1	80		mmBTU

Effect of derivative instruments on statements of income and comprehensive income

The effect of active derivative instruments not in a hedging relationship on the Consolidated Statements of Income during the three months ended March 31, 2016 and 2015, are summarized in the following tables:

	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2016
Unrealized Gain Recognized in:
Other Operating Expense (1)	$	62		$	2		$	64
Realized Gain (Loss) Reclassified to:
Revenues (1)	$	71		$	2		$	73
Purchased Power Expense (1)	(45		)	—			(45		)
Other Operating Expense (1)	—			(12		)	(12		)
Fuel Expense	(8		)	—			(8		)
(1) All amounts are associated with FES.
	Three Months Ended March 31
	Commodity Contracts			FTRs			Total
	(In millions)
2015
Unrealized Gain (Loss) Recognized in:
Other Operating Expense (2)	$	11		$	(13	)	$	(2	)
Realized Gain (Loss) Reclassified to:
Revenues (3)	$	(1	)	$	37		$	36
Purchased Power Expense (4)	(3		)	—			(3		)
Other Operating Expense (5)	—			(13		)	(13		)
Fuel Expense	(16		)	—			(16		)
(2) Includes $11 million for commodity contracts and ($12) million for FTRs associated with FES.
(3) Represents losses on structured financial contracts. Includes ($1) million for commodity contracts and $36 million for FTRs associated with FES.
(4) Realized losses on financially settled wholesale sales contracts of $22 million were netted in purchased power. Includes ($3) million for commodity contracts associated with FES.
(5) Includes ($13) million for FTRs associated with FES.

Reconciliation of changes in the fair value of certain contracts that are deferred

The following table provides a reconciliation of changes in the fair value of FirstEnergy's derivative instruments subject to regulatory accounting during the three months endedMarch 31, 2016 and 2015. Changes in the value of these instruments are deferred for future recovery from (or credit to) customers:

	Three Months Ended March 31
Derivatives Not in a Hedging Relationship with Regulatory Offset	NUGs			Regulated FTRs			Total
	(In millions)
Outstanding net asset (liability) as of January 1, 2016	$	(136	)	$	1		$	(135	)
Unrealized loss	(12		)	(1		)	(13		)
Settlements	13			(2		)	11
Outstanding net asset (liability) as of March 31, 2016	$	(135	)	$	(2	)	$	(137	)
Outstanding net asset (liability) as of January 1, 2015	$	(151	)	$	11		$	(140	)
Unrealized gain (loss)	(8		)	1			(7		)
Settlements	11			(11		)	—
Outstanding net asset (liability) as of March 31, 2015	$	(148	)	$	1		$	(147	)

XML

Commitments, Guarantees and Contingencies (Tables)

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations

The following table discloses the additional credit contingent contractual obligations that may be required under certain events as ofMarch 31, 2016:

Collateral Provisions	FES/ AE Supply (Tied to FE Corp. Rating)		FES/ AE Supply (Tied to FES Rating)		Utilities		Total
	(In millions)
Split Rating (One rating agency's rating below investment grade)	$	25	$	173	$	40	$	238
Non-Investment Grade Ratings (All Rating Agencies at or below BB+/Ba1)	$	25	$	200	$	40	$	265
Total Exposure from Contractual Obligations	$	25	$	341	$	40	$	406

XML

Supplemental Guarantor Information (Tables)

3 Months Ended

Mar. 31, 2016

Supplemental Guarantor Information [Abstract]

Condensed Consolidating Statements of Income and Comprehensive Income

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2016	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME
REVENUES	$	1,155		$	415		$	531		$	(902	)	$	1,199
OPERATING EXPENSES:
Fuel	—			119			46			—			165
Purchased power from affiliates	927			—			57			(902		)	82
Purchased power from non-affiliates	377			—			—			—			377
Other operating expenses	4			71			153			12			240
Provision for depreciation	3			31			50			(1		)	83
General taxes	8			10			8			—			26
Total operating expenses	1,319			231			314			(891		)	973
OPERATING INCOME (LOSS)	(164		)	184			217			(11		)	226
OTHER INCOME (EXPENSE):
Investment income, including net income from equity investees	251			6			17			(259		)	15
Interest expense — affiliates	(9		)	(2		)	(2		)	11			(2		)
Interest expense — other	(13		)	(26		)	(11		)	14			(36		)
Capitalized interest	—			2			8			—			10
Total other income (expense)	229			(20		)	12			(234		)	(13		)
INCOME BEFORE INCOME TAXES (BENEFITS)	65			164			229			(245		)	213
INCOME TAXES (BENEFITS)	(66		)	61			86			1			82
NET INCOME	$	131		$	103		$	143		$	(246	)	$	131
STATEMENTS OF COMPREHENSIVE INCOME
NET INCOME	$	131		$	103		$	143		$	(246	)	$	131
OTHER COMPREHENSIVE INCOME (LOSS):
Pensions and OPEB prior service costs	(4		)	(3		)	—			3			(4		)
Change in unrealized gain on available-for-sale securities	23			—			23			(23		)	23
Other comprehensive income (loss)	19			(3		)	23			(20		)	19
Income taxes (benefits) on other comprehensive income (loss)	7			(1		)	8			(7		)	7
Other comprehensive income (loss), net of tax	12			(2		)	15			(13		)	12
COMPREHENSIVE INCOME	$	143		$	101		$	158		$	(259	)	$	143

FIRSTENERGY SOLUTIONS CORP.
CONDENSED CONSOLIDATING STATEMENTS OF INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)
For the Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
STATEMENTS OF INCOME (LOSS)
REVENUES	$	1,332		$	493		$	507		$	(955	)	$	1,377
OPERATING EXPENSES:
Fuel	—			180			50			—			230
Purchased power from affiliates	957			—			68			(955		)	70
Purchased power from non-affiliates	543			—			—			—			543
Other operating expenses	180			67			154			12			413
Provision for depreciation	3			30			48			(1		)	80
General taxes	15			8			6			—			29
Total operating expenses	1,698			285			326			(944		)	1,365
OPERATING INCOME (LOSS)	(366		)	208			181			(11		)	12
OTHER INCOME (EXPENSE):
Investment income, including net income from equity investees	241			3			14			(245		)	13
Interest expense — affiliates	(6		)	(2		)	(1		)	7			(2		)
Interest expense — other	(13		)	(26		)	(13		)	15			(37		)
Capitalized interest	—			1			8			—			9
Total other income (expense)	222			(24		)	8			(223		)	(17		)
INCOME (LOSS) BEFORE INCOME TAXES (BENEFITS)	(144		)	184			189			(234		)	(5		)
INCOME TAXES (BENEFITS)	(141		)	67			70			2			(2		)
NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
NET INCOME (LOSS)	$	(3	)	$	117		$	119		$	(236	)	$	(3	)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(4		)	(4		)	3			1			(4		)
Amortized gain on derivative hedges	(1		)	—			—			—			(1		)
Change in unrealized gain on available-for-sale securities	3			—			—			—			3
Other comprehensive income (loss)	(2		)	(4		)	3			1			(2		)
Income taxes (benefits) on other comprehensive income (loss)	(1		)	(1		)	1			—			(1		)
Other comprehensive income (loss), net of tax	(1		)	(3		)	2			1			(1		)
COMPREHENSIVE INCOME (LOSS)	$	(4	)	$	114		$	121		$	(235	)	$	(4	)

Condensed Consolidating Balance Sheets

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of March 31, 2016	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	229		—		—		—			229
Affiliated companies	442		310		305		(610		)	447
Other	32		1		74		—			107
Notes receivable from affiliated companies	394		1,429		889		(2,712		)	—
Materials and supplies	39		191		216		—			446
Derivatives	207		—		—		—			207
Collateral	80		—		—		—			80
Prepayments and other	69		11		—		—			80
	1,492		1,944		1,484		(3,322		)	1,598
PROPERTY, PLANT AND EQUIPMENT:
In service	92		6,389		8,277		(382		)	14,376
Less — Accumulated provision for depreciation	43		2,163		3,863		(195		)	5,874
	49		4,226		4,414		(187		)	8,502
Construction work in progress	30		271		972		—			1,273
	79		4,497		5,386		(187		)	9,775
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,372		—			1,372
Investment in affiliated companies	7,712		—		—		(7,712		)	—
Other	—		10		—		—			10
	7,712		10		1,372		(7,712		)	1,382
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	276		—		—		(276		)	—
Customer intangibles	57		—		—		—			57
Goodwill	23		—		—		—			23
Property taxes	—		9		21		—			30
Derivatives	89		—		—		—			89
Other	24		301		4		56			385
	469		310		25		(220		)	584
	$	9,752	$	6,761	$	8,267	$	(11,441	)	$	13,339
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—	$	266	$	308	$	(25	)	$	549
Short-term borrowings-
Affiliated companies	2,373		386		2		(2,712		)	49
Accounts payable-
Affiliated companies	619		190		172		(619		)	362
Other	26		90		—		—			116
Accrued taxes	3		52		101		(85		)	71
Derivatives	115		—		—		—			115
Other	75		74		15		77			241
	3,211		1,058		598		(3,364		)	1,503
CAPITALIZATION:
Total equity	5,749		3,046		4,634		(7,680		)	5,749
Long-term debt and other long-term obligations	690		2,067		840		(1,117		)	2,480
	6,439		5,113		5,474		(8,797		)	8,229
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		782			782
Accumulated deferred income taxes	6		35		743		(62		)	722
Retirement benefits	28		311		—		—			339
Asset retirement obligations	—		188		650		—			838
Derivatives	21		—		—		—			21
Other	47		56		802		—			905
	102		590		2,195		720			3,607
	$	9,752	$	6,761	$	8,267	$	(11,441	)	$	13,339

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING BALANCE SHEETS

As of December 31, 2015	FES		FG		NG		Eliminations			Consolidated
	(In millions)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	2	$	—	$	—		$	2
Receivables-
Customers	275		—		—		—			275
Affiliated companies	433		403		461		(846		)	451
Other	36		4		19		—			59
Notes receivable from affiliated companies	406		1,210		805		(2,410		)	11
Materials and supplies	53		204		213		—			470
Derivatives	154		—		—		—			154
Collateral	70		—		—		—			70
Prepayments and other	48		18		—		—			66
	1,475		1,841		1,498		(3,256		)	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	93		6,367		8,233		(382		)	14,311
Less — Accumulated provision for depreciation	40		2,144		3,775		(194		)	5,765
	53		4,223		4,458		(188		)	8,546
Construction work in progress	30		249		878		—			1,157
	83		4,472		5,336		(188		)	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	—		—		1,327		—			1,327
Investment in affiliated companies	7,452		—		—		(7,452		)	—
Other	—		10		—		—			10
	7,452		10		1,327		(7,452		)	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	300		16		—		(316		)	—
Customer intangibles	61		—		—		—			61
Goodwill	23		—		—		—			23
Property taxes	—		12		28		—			40
Derivatives	79		—		—		—			79
Other	29		312		14		12			367
	492		340		42		(304		)	570
	$	9,502	$	6,663	$	8,203	$	(11,200	)	$	13,168
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	—	$	229	$	308	$	(25	)	$	512
Short-term borrowings-
Affiliated companies	2,021		389		—		(2,410		)	—
Other	—		8		—		—			8
Accounts payable-
Affiliated companies	884		146		368		(856		)	542
Other	21		118		—		—			139
Accrued taxes	7		93		62		(86		)	76
Derivatives	103		1		—		—			104
Other	66		61		9		45			181
	3,102		1,045		747		(3,332		)	1,562
CAPITALIZATION:
Total equity	5,605		2,944		4,476		(7,420		)	5,605
Long-term debt and other long-term obligations	690		2,116		840		(1,136		)	2,510
	6,295		5,060		5,316		(8,556		)	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	—		—		—		791			791
Accumulated deferred income taxes	6		—		697		(103		)	600
Retirement benefits	27		305		—		—			332
Asset retirement obligations	—		191		640		—			831
Derivatives	37		1		—		—			38
Other	35		61		803		—			899
	105		558		2,140		688			3,491
	$	9,502	$	6,663	$	8,203	$	(11,200	)	$	13,168

Condensed Consolidating Statements of Cash Flows

FIRSTENERGY SOLUTIONS CORP.

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2016	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(356	)	$	277		$	307		$	—		$	228
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	352			8			1			(312		)	49
Redemptions and Repayments-
Short-term borrowings, net	—			(11		)	—			11			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	352			(5		)	1			(301		)	47
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27		)	(53		)	(63		)	—			(143		)
Nuclear fuel	—			—			(149		)	—			(149		)
Sales of investment securities held in trusts	—			—			138			—			138
Purchases of investment securities held in trusts	—			—			(151		)	—			(151		)
Cash investments	10			—			—			—			10
Loans to affiliated companies, net	12			(219		)	(83		)	301			11
Other	9			—			—			—			9
Net cash provided from (used for) investing activities	4			(272		)	(308		)	301			(275		)
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

For the Three Months Ended March 31, 2015	FES			FG			NG			Eliminations			Consolidated
	(In millions)
NET CASH PROVIDED FROM (USED FOR) OPERATING ACTIVITIES	$	(662	)	$	222		$	545		$	—		$	105
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Short-term borrowings, net	674			—			—			(524		)	150
Redemptions and Repayments-
Long-term debt	(17		)	—			—			—			(17		)
Short-term borrowings, net	—			(5		)	(28		)	33			—
Other	—			(2		)	—			—			(2		)
Net cash provided from (used for) financing activities	657			(7		)	(28		)	(491		)	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1		)	(36		)	(82		)	—			(119		)
Nuclear fuel	—			—			(60		)	—			(60		)
Sales of investment securities held in trusts	—			—			189			—			189
Purchases of investment securities held in trusts	—			—			(202		)	—			(202		)
Loans to affiliated companies, net	6			(179		)	(362		)	491			(44		)
Net cash provided from (used for) investing activities	5			(215		)	(517		)	491			(236		)
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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Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Segment Financial Information

Segment Financial Information

Three Months Ended	Regulated Distribution		Regulated Transmission		Competitive Energy Services			Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)
March 31, 2016
External revenues	$	2,521	$	275	$	1,152		$	(42	)	$	(37	)	$	3,869
Internal revenues	—		—		152			—			(152		)	—
Total revenues	2,521		275		1,304			(42		)	(189		)	3,869
Depreciation	169		43		102			15			—			329
Amortization of regulatory assets, net	59		2		—			—			—			61
Investment income	11		—		15			11			(9		)	28
Interest expense	147		43		47			51			—			288
Income taxes (benefits)	98		43		85			(13		)	—			213
Net income (loss)	165		74		144			(55		)	—			328
Total assets	27,907		7,679		16,578			531			—			52,695
Total goodwill	5,092		526		800			—			—			6,418
Property additions	262		258		169			9			—			698
March 31, 2015
External revenues	$	2,562	$	238	$	1,175		$	(42	)	$	(36	)	$	3,897
Internal revenues	—		—		260			—			(260		)	—
Total revenues	2,562		238		1,435			(42		)	(296		)	3,897
Depreciation	172		37		96			14			—			319
Amortization of regulatory assets, net	29		3		—			—			—			32
Investment income	13		—		12			2			(10		)	17
Interest expense	144		39		48			47			1			279
Income taxes (benefits)	122		42		(4		)	(18		)	2			144
Net income (loss)	208		72		(8		)	(50		)	—			222
Total assets	27,974		6,601		16,497			807			—			51,879
Total goodwill	5,092		526		800			—			—			6,418
Property additions	280		254		126			8			—			668

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Organization and Basis of Presentation (Details Textuals) mi in Thousands, MW in Thousands, customer in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) customer transmission_center company mi MW	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Property, Plant and Equipment [Line Items]
Aggregate amount of capacity | MW	17
Length of transmission lines | mi	24
Number of regional transmission centers | transmission_center	2
Capitalized cost of equity	$ 8	$ 16
Capitalized interest	$ 17	$ 18
New Accounting Pronouncement, Early Adoption, Effect | Deferred Charges and Other Assets
Property, Plant and Equipment [Line Items]
Debt issuance costs			$ 93
Regulated Distribution
Property, Plant and Equipment [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
FES | New Accounting Pronouncement, Early Adoption, Effect | Deferred Charges and Other Assets
Property, Plant and Equipment [Line Items]
Debt issuance costs			$ 17

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Earnings Per Share Of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
NET INCOME	$ 328	$ 222
Weighted average number of basic shares outstanding	424	421
Assumed exercise of dilutive stock options and awards	2	2
Weighted average number of diluted shares outstanding	426	423
Basic earnings per share of common stock (in dollars per share)	$ 0.78	$ 0.53
Diluted earnings per share of common stock (in dollars per share)	$ 0.77	$ 0.53
Shares excluded from the calculation of diluted shares outstanding, in shares	1	1

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Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Minimum required funding obligations	$ 381
Pension contributions	160	$ 143
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	48	48
Interest costs	100	96
Expected return on plan assets	(97)	(111)
Amortization of prior service costs (credits)	2	2
Net periodic costs (credits)	53	35
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs	1	1
Interest costs	7	7
Expected return on plan assets	(8)	(8)
Amortization of prior service costs (credits)	(20)	(33)
Net periodic costs (credits)	(20)	(33)
FirstEnergy | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	37	25
FirstEnergy | OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic benefit expense (credit)	(15)	(23)
FES | Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits)	6	4
Net periodic benefit expense (credit)	6	4
FES | OPEB
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)	$ (4)

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Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 171	$ 246
Other comprehensive income (loss) before reclassifications	41	14
Amounts reclassified from AOCI	(29)	(40)
Other comprehensive income (loss)	12	(26)
Income taxes (benefits) on other comprehensive income (loss)	4	(10)
Other comprehensive income (loss), net of tax	8	(16)
AOCI Ending Balance	179	230
FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	46	57
Other comprehensive income (loss) before reclassifications	36	13
Amounts reclassified from AOCI	(17)	(15)
Other comprehensive income (loss)	19	(2)
Income taxes (benefits) on other comprehensive income (loss)	7	(1)
Other comprehensive income (loss), net of tax	12	(1)
AOCI Ending Balance	58	56
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(33)	(37)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	2	1
Other comprehensive income (loss)	2	1
Income taxes (benefits) on other comprehensive income (loss)	1	0
Other comprehensive income (loss), net of tax	1	1
AOCI Ending Balance	(32)	(36)
Gains & Losses on Cash Flow Hedges | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(9)	(7)
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	0	(1)
Other comprehensive income (loss)	0	(1)
Income taxes (benefits) on other comprehensive income (loss)	0	0
Other comprehensive income (loss), net of tax	0	(1)
AOCI Ending Balance	(9)	(8)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	18	25
Other comprehensive income (loss) before reclassifications	41	14
Amounts reclassified from AOCI	(13)	(10)
Other comprehensive income (loss)	28	4
Income taxes (benefits) on other comprehensive income (loss)	10	1
Other comprehensive income (loss), net of tax	18	3
AOCI Ending Balance	36	28
Unrealized Gains on AFS Securities | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	16	21
Other comprehensive income (loss) before reclassifications	36	13
Amounts reclassified from AOCI	(13)	(10)
Other comprehensive income (loss)	23	3
Income taxes (benefits) on other comprehensive income (loss)	9	0
Other comprehensive income (loss), net of tax	14	3
AOCI Ending Balance	30	24
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	186	258
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(18)	(31)
Other comprehensive income (loss)	(18)	(31)
Income taxes (benefits) on other comprehensive income (loss)	(7)	(11)
Other comprehensive income (loss), net of tax	(11)	(20)
AOCI Ending Balance	175	238
Defined Benefit Pension & OPEB Plans | FES
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	39	43
Other comprehensive income (loss) before reclassifications	0	0
Amounts reclassified from AOCI	(4)	(4)
Other comprehensive income (loss)	(4)	(4)
Income taxes (benefits) on other comprehensive income (loss)	(2)	(1)
Other comprehensive income (loss), net of tax	(2)	(3)
AOCI Ending Balance	$ 37	$ 40

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Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ 918	$ 1,057
Interest expense	288	279
Investment income (loss)	(28)	(17)
Total before taxes	(541)	(366)
Income taxes (benefits)	213	144
Net of tax	(328)	(222)
FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	240	413
Investment income (loss)	(15)	(13)
Total before taxes	(213)	5
Income taxes (benefits)	82	(2)
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes	2	1
Income taxes (benefits)	(1)	0
Net of tax	1	1
Reclassifications from AOCI | Gains & losses on cash flow hedges | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes (benefits)	0	0
Net of tax	0	(1)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	0	(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	0	(1)
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	2	2
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(13)	(10)
Income taxes (benefits)	5	4
Net of tax	(8)	(6)
Reclassifications from AOCI | Unrealized gains on AFS securities | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income (loss)	(13)	(10)
Income taxes (benefits)	5	4
Net of tax	(8)	(6)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(18)	(31)
Income taxes (benefits)	7	11
Net of tax	(11)	(20)
Reclassifications from AOCI | Defined benefit pension and OPEB plans | FES
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(4)	(4)
Income taxes (benefits)	2	1
Net of tax	$ (2)	$ (3)

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Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	39.40%	39.30%
Unrecognized tax benefits from lapse of statute of limitations	$ 54
Unrecognized tax benefits that would impact effective tax rate	$ 16
FES
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	38.50%	40.00%
State and Local Jurisdiction
Income Taxes (Textuals) [Abstract]
Increase resulting from settlements with taxing authorities	$ 69

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Variable Interest Entities (Details) $ in Millions	Mar. 31, 2016 USD ($)
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	$ 1,228
Discounted Lease Payments, net	967
Net Exposure	261
FES
Net exposure to loss based upon the casualty value provisions
Maximum Exposure	1,171
Discounted Lease Payments, net	949
Net Exposure	$ 222

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Variable Interest Entities (Details Textuals)	3 Months Ended
	Mar. 31, 2016 USD ($) agreement entities	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Variable Interest Entities (Textuals) [Abstract]
Equity interest by unaffiliated third party in PNBV (percent)	3.00%
Long-term transition bond	$ 118,000,000		$ 128,000,000
Long-term pollution control bond	419,000,000		429,000,000
Guarantor obligations	$ 406,000,000
Number of contracts that may contain variable interest | entities	1
Purchased power	$ 1,124,000,000	$ 1,113,000,000
Perry Power Plant Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	3.75%
Bruce Mansfield Unit 1
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	93.83%
Beaver Valley Unit 2
Variable Interest Entities (Textuals) [Abstract]
Percentage of undivided interest of non guarantor subsidiary	2.60%
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement	14
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 350,000,000		$ 362,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees	$ 445,000
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 31,000,000	$ 31,000,000
Path-WV
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series	100.00%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series	50.00%
Global Holding | Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations	$ 300,000,000
Signal Peak | Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	33.33%

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Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Assets
Fair value, assets	$ 3,073	$ 2,876
Liabilities
Fair value, liabilities	(274)	(281)
Net assets (liabilities)	2,799	2,595
FES
Assets
Fair value, assets	1,676	1,559
Liabilities
Fair value, liabilities	(136)	(142)
Net assets (liabilities)	1,540	1,417
Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(129)	(131)
Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(129)	(131)
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(9)	(13)
FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(11)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(136)	(137)
Corporate debt securities
Assets
Fair value, assets	1,264	1,245
Corporate debt securities | FES
Assets
Fair value, assets	715	678
Commodity contracts | Derivative Assets
Assets
Fair value, assets	293	228
Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	293	228
FTRs | Derivative Assets
Assets
Fair value, assets	3	8
FTRs | Derivative Assets | FES
Assets
Fair value, assets	3	5
NUG contracts | Derivative Assets
Assets
Fair value, assets	1	1
Equity securities
Assets
Fair value, assets	628	576
Equity securities | FES
Assets
Fair value, assets	408	378
Foreign government debt securities
Assets
Fair value, assets	73	75
Foreign government debt securities | FES
Assets
Fair value, assets	58	59
U.S. government debt securities
Assets
Fair value, assets	188	180
U.S. government debt securities | FES
Assets
Fair value, assets	25	23
U.S. state debt securities
Assets
Fair value, assets	245	246
U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Other
Assets
Fair value, assets	378	317
Other | FES
Assets
Fair value, assets	170	184
Level 1
Assets
Fair value, assets	777	685
Liabilities
Fair value, liabilities	(7)	(9)
Net assets (liabilities)	770	676
Level 1 | FES
Assets
Fair value, assets	411	382
Liabilities
Fair value, liabilities	(7)	(9)
Net assets (liabilities)	404	373
Level 1 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(7)	(9)
Level 1 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(9)
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	0
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	3	4
Level 1 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	3	4
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	0
Level 1 | Equity securities
Assets
Fair value, assets	628	576
Level 1 | Equity securities | FES
Assets
Fair value, assets	408	378
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	146	105
Level 1 | Other | FES
Assets
Fair value, assets	0	0
Level 2
Assets
Fair value, assets	2,292	2,182
Liabilities
Fair value, liabilities	(122)	(122)
Net assets (liabilities)	2,170	2,060
Level 2 | FES
Assets
Fair value, assets	1,262	1,172
Liabilities
Fair value, liabilities	(122)	(122)
Net assets (liabilities)	1,140	1,050
Level 2 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(122)	(122)
Level 2 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(122)	(122)
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	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	1,264	1,245
Level 2 | Corporate debt securities | FES
Assets
Fair value, assets	715	678
Level 2 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	290	224
Level 2 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	290	224
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	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Equity securities | FES
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	73	75
Level 2 | Foreign government debt securities | FES
Assets
Fair value, assets	58	59
Level 2 | U.S. government debt securities
Assets
Fair value, assets	188	180
Level 2 | U.S. government debt securities | FES
Assets
Fair value, assets	25	23
Level 2 | U.S. state debt securities
Assets
Fair value, assets	245	246
Level 2 | U.S. state debt securities | FES
Assets
Fair value, assets	4	4
Level 2 | Other
Assets
Fair value, assets	232	212
Level 2 | Other | FES
Assets
Fair value, assets	170	184
Level 3
Assets
Fair value, assets	4	9
Liabilities
Fair value, liabilities	(145)	(150)
Net assets (liabilities)	(141)	(141)
Level 3 | FES
Assets
Fair value, assets	3	5
Liabilities
Fair value, liabilities	(7)	(11)
Net assets (liabilities)	(4)	(6)
Level 3 | Commodity contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 3 | Commodity contracts | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	0	0
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(9)	(13)
Level 3 | FTRs | Derivative Liabilities | FES
Liabilities
Fair value, liabilities	(7)	(11)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(136)	(137)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | Corporate debt securities | FES
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets
Assets
Fair value, assets	0	0
Level 3 | Commodity contracts | Derivative Assets | FES
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	3	8
Level 3 | FTRs | Derivative Assets | FES
Assets
Fair value, assets	3	5
Level 3 | NUG contracts | Derivative Assets
Assets
Fair value, assets	1	1
Level 3 | Equity securities
Assets
Fair value, assets	0	0
Level 3 | Equity securities | FES
Assets
Fair value, assets	0	0
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	0
Level 3 | Other | FES
Assets
Fair value, assets	$ 0	$ 0

XML

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
NUG contracts
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	$ 1	$ 2
Beginning Balance, Derivative Liabilities	(137)	(153)
Beginning Balance, Net	(136)	(151)
Unrealized gain (loss), Derivative Assets	0	2
Unrealized gain (loss), Derivative Liabilities	(12)	(49)
Unrealized gain (loss), Net	(12)	(47)
Purchases, Derivative Assets		0
Purchases, Derivative Liabilities		0
Purchases, Net		0
Settlements, Derivative Assets	0	(3)
Settlements, Derivative Liabilities	13	65
Settlements, Net	13	62
Ending Balance, Derivative Assets	1	1
Ending Balance, Derivative Liabilities	(136)	(137)
Ending Balance, Net	(135)	(136)
FTRs
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	8	39
Beginning Balance, Derivative Liabilities	(13)	(14)
Beginning Balance, Net	(5)	25
Unrealized gain (loss), Derivative Assets	0	(5)
Unrealized gain (loss), Derivative Liabilities	(1)	(7)
Unrealized gain (loss), Net	(1)	(12)
Purchases, Derivative Assets		22
Purchases, Derivative Liabilities		(11)
Purchases, Net		11
Settlements, Derivative Assets	(5)	(48)
Settlements, Derivative Liabilities	5	19
Settlements, Net	0	(29)
Ending Balance, Derivative Assets	3	8
Ending Balance, Derivative Liabilities	(9)	(13)
Ending Balance, Net	(6)	(5)
FTRs | FES
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	5	27
Beginning Balance, Derivative Liabilities	(11)	(13)
Beginning Balance, Net	(6)	14
Unrealized gain (loss), Derivative Assets	0	2
Unrealized gain (loss), Derivative Liabilities	(1)	(5)
Unrealized gain (loss), Net	(1)	(3)
Purchases, Derivative Assets		9
Purchases, Derivative Liabilities		(10)
Purchases, Net		(1)
Settlements, Derivative Assets	(2)	(33)
Settlements, Derivative Liabilities	5	17
Settlements, Net	3	(16)
Ending Balance, Derivative Assets	3	5
Ending Balance, Derivative Liabilities	(7)	(11)
Ending Balance, Net	$ (4)	$ (6)

XML

Fair Value Measurements (Details 2) - Level 3 $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) MWh $ / MWh	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (6)	$ (5)	$ 25
FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(4)	(6)	14
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(135)	$ (136)	$ (151)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(6)
Model | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(4)
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (135)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(4.60)
Model | Minimum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(4.60)
Model | Minimum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	400
Fair Value Inputs, Power, Regional Prices (in $/MWH)	37.30
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	3.70
Model | Maximum | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	3.70
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	3,651,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	45.60
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.60
Model | Weighted Average | FTRs | FES
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.50
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	777,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	39.60

XML

Fair Value Measurements (Details 3) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	$ 1,776	$ 1,778
Unrealized Gain	44	16
Fair Value	1,820	1,794
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	576	542
Unrealized Gains	52	34
Fair Value	628	576
FES | Debt Securities
Schedule of Available-for-sale Securities [Line Items]
Cost Basis	825	801
Unrealized Gain	26	9
Fair Value	851	810
FES | Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	372	354
Unrealized Gains	36	24
Fair Value	$ 408	$ 378

XML

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
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	$ 465	$ 371
Realized Gains	61	60
Realized Losses	(50)	(50)
OTTI	(9)	(7)
Interest and Dividend Income	23	25
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	138	189
Realized Gains	42	38
Realized Losses	(29)	(28)
OTTI	(8)	(6)
Interest and Dividend Income	$ 13	$ 14

XML

Fair Value Measurements (Details 5) - Debt Securities - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Amortized cost basis, unrealized gains and losses, and approximate fair values of investments in held-to-maturity securities
Cost Basis	$ 6	$ 6
Unrecognized Gains	1	2
Fair Value	$ 7	$ 8

XML

Fair Value Measurements (Details 6) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
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	$ 20,217	$ 20,244
Carrying Value | FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	3,036	3,027
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	21,821	21,519
Fair Value | FES
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 3,112	$ 3,121

XML

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ (6)	$ 7
Cash balance excluded from available for sale securities	161	157
Investments not required to be disclosed	$ 271	255
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	3 years
FES
Fair Value of Financial Instruments [Line Items]
Investment excludes Receivables, Payables and Accrued income	$ (8)	1
Cash balance excluded from available for sale securities	$ 113	$ 139

XML

Derivative Instruments (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair value of commodity derivatives
Derivative Assets	$ 297	$ 237
Derivative Liabilities	(274)	(281)
Current Assets
Fair value of commodity derivatives
Derivative Assets	207	157
Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	90	80
Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(117)	(106)
Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(157)	(175)
Commodity contracts | Current Assets
Fair value of commodity derivatives
Derivative Assets	205	150
Commodity contracts | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	88	78
Commodity contracts | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(109)	(94)
Commodity contracts | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(20)	(37)
FTRs | Current Assets
Fair value of commodity derivatives
Derivative Assets	2	7
FTRs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	1
FTRs | Current Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(8)	(12)
FTRs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	(1)	(1)
NUGs | Noncurrent Assets
Fair value of commodity derivatives
Derivative Assets	1	1
NUGs | Noncurrent Liabilities
Fair value of commodity derivatives
Derivative Liabilities	$ (136)	$ (137)

XML

Derivative Instruments (Details 1) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative Assets
Fair Value	$ 297	$ 237
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(131)	(133)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(25)	0
Net Fair Value	141	104
Derivative Liabilities
Fair Value	(274)	(281)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	131	133
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	6	8
Net Fair Value	(137)	(140)
Commodity contracts
Derivative Assets
Fair Value	293	228
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(128)	(125)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	(25)	0
Net Fair Value	140	103
Derivative Liabilities
Fair Value	(129)	(131)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	128	125
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	3
Net Fair Value	(1)	(3)
FTRs
Derivative Assets
Fair Value	3	8
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	(3)	(8)
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	0	0
Net Fair Value	0	0
Derivative Liabilities
Fair Value	(9)	(13)
Amounts Not Offset in Consolidated Balance Sheet, Derivative Instruments	3	8
Amounts Not Offset in Consolidated Balance Sheet, Cash Collateral (Received)/Pledged	6	5
Net Fair Value	0	0
NUGs
Derivative Assets
Fair Value	1	1
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	1	1
Derivative Liabilities
Fair Value	(136)	(137)
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	$ (136)	$ (137)

XML

Derivative Instruments (Details 2) MWh in Millions, MMBTU in Millions	Mar. 31, 2016 MMBTU MWh
Power Contracts
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	14
Sales (in MWH or mmBTUs)	42
Net (in MWH or mmBTUs)	(28)
FTRs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	15
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	15
NUGs
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs)	4
Sales (in MWH or mmBTUs)	0
Net (in MWH or mmBTUs)	4
Natural Gas
Volume of First Energy's outstanding derivative transactions
Purchases (in MWH or mmBTUs) | MMBTU	81
Sales (in MWH or mmBTUs) | MMBTU	1
Net (in MWH or mmBTUs) | MMBTU	80

XML

Derivative Instruments (Details 3) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
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	$ 73	$ 36
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	(45)	(3)
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	64	(2)
Realized Gain (Loss) Reclassified	(12)	(13)
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	(8)	(16)
Commodity 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	71	(1)
Commodity 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	(45)	(3)
Commodity 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	62	11
Realized Gain (Loss) Reclassified	0	0
Commodity 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	(8)	(16)
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	2	37
FTRs | Purchase Power Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Realized Gain (Loss) Reclassified	0	0
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	2	(13)
Realized Gain (Loss) Reclassified	(12)	(13)
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 | Commodity 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		(1)
FES | Commodity 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		(3)
FES | Commodity contracts | Other Operating Expense
Effect of derivative instruments on the statements of income and comprehensive income for instruments designated in cash flow hedging relationships and not in hedging relationships
Unrealized Gain (Loss) Recognized		11
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		36
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		(12)
Realized Gain (Loss) Reclassified		(13)
FES | Wholesale Sales Contract | 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		$ 22

XML

Derivative Instruments (Details 4) - Not Designated as Hedging Instrument - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	$ (135)	$ (140)
Unrealized gain (loss)	(13)	(7)
Settlements	11	0
Outstanding net asset (liability), Ending Balance	(137)	(147)
NUGs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	(136)	(151)
Unrealized gain (loss)	(12)	(8)
Settlements	13	11
Outstanding net asset (liability), Ending Balance	(135)	(148)
Regulated FTRs
Outstanding net asset (liability) [Roll Forward]
Outstanding net asset (liability), Beginning Balance	1	11
Unrealized gain (loss)	(1)	1
Settlements	(2)	(11)
Outstanding net asset (liability), Ending Balance	$ (2)	$ 1

XML

Derivative Instruments (Details Textuals) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) agreement	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($) agreement
Derivative [Line Items]
Unamortized gains or losses associated with designated cash flow hedges	$ 11		$ 11
Less than 1 million dollar loss on cash flow hedge expected to be reclassified to earnings in next twelve months	1
Unamortized gains or losses associated with prior interest rate hedges	39		42
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	17		20
Collateral received	$ 25		$ 0
Possible adverse change in quoted market prices of derivative instruments	10.00%
Possible increase net income due to ten percent adverse change in commodity prices	$ (22)
Cash Flow Hedges
Derivative [Line Items]
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | agreement	0		0
Losses to be amortized to interest expenses during next twelve months	$ 9
Number of outstanding commodity or interest rate derivatives | agreement			0
Fair Value Hedging
Derivative [Line Items]
Losses to be amortized to interest expenses during next twelve months	$ (10)
Number of outstanding commodity or interest rate derivatives | agreement	0		0
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0		0
Reclassifications from long-term debt	$ 3	$ 3
Commodity contracts
Derivative [Line Items]
Net asset position under commodity derivative contracts	164
Collateral received	25		$ 0
Commodity contracts | FES
Derivative [Line Items]
Net asset position under commodity derivative contracts	164
Collateral posted	4
Collateral received	25
Additional collateral related to commodity derivatives	5
NUGs
Derivative [Line Items]
Collateral received	0		0
Liability position	135
FTRs
Derivative [Line Items]
Collateral received	0		$ 0
Liability position	6
FTRs | FES
Derivative [Line Items]
Collateral posted	6
Liability position	$ 4

XML

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions			1 Months Ended	3 Months Ended	12 Months Ended
	Jul. 16, 2015	Feb. 27, 2013 USD ($)	Apr. 26, 2016 USD ($)	Mar. 31, 2016 USD ($) component bgs	Dec. 31, 2015	Jan. 28, 2016 USD ($)
Maryland
Regulatory Matters [Line Items]
Expenditures for cost recovery program				$ 66.0
Expenditures for cost recovery program incurred				$ 26.0
Incremental energy savings goal next 12 months (percent)	0.20%
Incremental energy savings goal thereafter (percent)	2.00%
Recovery period for expenditures for cost recovery program				5 years	3 years
Requested increase in expenditures for cost recovery program						$ 2.0
Expected infrastructure investments		$ 2,700.0
Period of expected infrastructure investments		15 years
New Jersey
Regulatory Matters [Line Items]
Number of supply components | component				2
Number of basic generation services | bgs				1
JCP&L | NJBPU | New Jersey | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)			$ 142.1

XML

Regulatory Matters - Ohio (Details) MWh in Thousands, $ in Millions			3 Months Ended
	Aug. 07, 2013 USD ($) auctions	Mar. 20, 2013	Mar. 31, 2016 USD ($) MWh MW	Mar. 31, 2015 USD ($)	Apr. 15, 2016 USD ($)
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)			90.00%
Amortization (deferral) of regulatory assets, net			$ 61.0	$ 32.0
Ohio
Regulatory Matters [Line Items]
ESP extension term			2 years
Generation discount for low income customers (percent)			6.00%
Recovery period			5 years
Costs avoided by customers			$ 360.0
Proposed goal to reduce CO2 pollution (percent)			90.00%
Generation supply auction period, after approval			3 years
Generation supply auction period, before approval			1 year
Term of proposed purchase power agreement			8 years
Term of economic development and assistance plan			3 years
Annual revenue cap for rider			$ 30.0
Guaranteed credits, year seven			$ 30.0
Energy efficient portfolio plan term		3 years
Credit to non-shopping customers	$ 43.4
Ohio | Year 2015
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh			2,266
Ohio | Year 2016
Regulatory Matters [Line Items]
Annual energy savings (in GWH) | MWh			2,288
Ohio | Year 2017
Regulatory Matters [Line Items]
Annual increase in energy savings (percent)			1.00%
Ohio | Annually Through 2020
Regulatory Matters [Line Items]
Utilities required to additionally reduce peak demand			0.75%
Ohio | Wind or Solar Power
Regulatory Matters [Line Items]
Proposed potential plant acquisition (MW) | MW			100
Ohio | PUCO
Regulatory Matters [Line Items]
Number of renewable energy auctions | auctions	1
Approved period to limit average customer bill			2 years
Ohio | Ohio Companies | PUCO | Subsequent Event
Regulatory Matters [Line Items]
Expenditures for cost recovery program					$ 323.0
Ohio | Retail Rate Stability Rider
Regulatory Matters [Line Items]
Guaranteed credits, year five			$ 10.0
Guaranteed credits, year six			20.0
Guaranteed credits, year eight			$ 40.0
Ohio | Retail Rate Stability Rider | FES
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Ohio | Delivery Capital Recovery Rider
Regulatory Matters [Line Items]
Annual revenue cap for rider			$ 30.0
Annual revenue cap for rider for years three through six			20.0
Annual revenue cap for rider for years six through eight			$ 15.0
Ohio | Customary Advisory Council
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Annual contribution amount			$ 1.0
Contribution amount			$ 8.0
Ohio | Energy Conservation, Economic Development and Job Retention | Ohio Companies
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Annual contribution amount			$ 3.0
Contribution amount			$ 24.0
Ohio | Fuel-Fund | Ohio Companies
Regulatory Matters [Line Items]
Term of proposed purchase power agreement			8 years
Annual contribution amount			$ 2.4
Contribution amount			$ 19.0

XML

Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Thousands					1 Months Ended
	Oct. 19, 2015 USD ($)	Jun. 19, 2015	May. 19, 2015	Oct. 10, 2013 proposal	Apr. 26, 2016 USD ($)	Mar. 31, 2016 USD ($) program
Pennsylvania
Regulatory Matters [Line Items]
Number of requests for proposal | proposal				1
Request for proposal project term				2 years
Pennsylvania | Unfavorable Regulatory Action
Regulatory Matters [Line Items]
Maximum range of possible loss						$ 175,000
Revised implementation plan granted extension period			45 days
Pennsylvania | Three month period
Regulatory Matters [Line Items]
Term of energy contract				3 months
Pennsylvania | Twelve month period
Regulatory Matters [Line Items]
Term of energy contract				12 months
Pennsylvania | Twenty-four month period
Regulatory Matters [Line Items]
Term of energy contract				24 months
Pennsylvania | PPUC
Regulatory Matters [Line Items]
LTIIP recovery period	5 years
Pennsylvania | ME | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					$ 140,200
Pennsylvania | ME | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		1.80%
Energy consumption reduction targets proposed return on equity (percent)		4.00%
Amount of requested rate increase (decrease)	$ 43,440
Pennsylvania | Penn | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					42,000
Pennsylvania | Penn | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		1.70%
Energy consumption reduction targets proposed return on equity (percent)		3.30%
Amount of requested rate increase (decrease)	56,350
Pennsylvania | WP | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					98,200
Pennsylvania | WP | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		1.80%
Energy consumption reduction targets proposed return on equity (percent)		2.60%
Amount of requested rate increase (decrease)	88,340
Pennsylvania | PN | Subsequent Event
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)					$ 158,800
Pennsylvania | PN | PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed return on equity (percent)		0.00%
Energy consumption reduction targets proposed return on equity (percent)		3.90%
Amount of requested rate increase (decrease)	$ 56,740
West Virginia | MP and PE | WVPSC
Regulatory Matters [Line Items]
Number of proposed efficient programs | program						3
Energy efficient reduction requirement (percent)						0.50%
Expenditures for cost recovery program						$ 9,900

XML

Regulatory Matters - Reliability Matters and FERC (Details) $ in Millions			1 Months Ended	3 Months Ended
	Sep. 14, 2015	Aug. 24, 2012 USD ($)	Oct. 31, 2006 proceeding	Mar. 31, 2016 USD ($) entities subsidiary
Regulatory Matters [Line Items]
Regional enforcement entities | entities				8
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees				$ 78.8
FERC | California Claims Matters
Regulatory Matters [Line Items]
Settlement proposal claims				$ 190.0
Court proceedings from filed claims | proceeding			1
FERC | PATH-Allegheny | PATH Transmission Project
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets		$ 62.0
FERC | Path-WV | PATH Transmission Project
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets		$ 59.0
FERC | PATH | PATH Transmission Project
Regulatory Matters [Line Items]
Proposed return on equity		10.90%
Requested return on equity (percent)		10.40%
Return on equity granted for regional transmission organization participation		0.50%
Remaining recovery period of regulatory assets	5 years
FERC | FET
Regulatory Matters [Line Items]
Number of stand-alone transmission subsidiaries | subsidiary				2

XML

Commitments, Guarantees and Contingencies (Details) $ in Millions	Mar. 31, 2016 USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 406
FES/AE Supply (Tied to FE Corp Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	25
FES/AE Supply (Tied to FES Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	341
Utilities
Guarantor Obligations [Line Items]
Guarantor obligations	40
Split Rating
Guarantor Obligations [Line Items]
Guarantor obligations	238
Split Rating | FES/AE Supply (Tied to FE Corp Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	25
Split Rating | FES/AE Supply (Tied to FES Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	173
Split Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations	40
Non-Investment Grade Rating
Guarantor Obligations [Line Items]
Guarantor obligations	265
Non-Investment Grade Rating | FES/AE Supply (Tied to FE Corp Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	25
Non-Investment Grade Rating | FES/AE Supply (Tied to FES Rating)
Guarantor Obligations [Line Items]
Guarantor obligations	200
Non-Investment Grade Rating | Utilities
Guarantor Obligations [Line Items]
Guarantor obligations	$ 40

XML

Commitments, Guarantees and Contingencies (Details Textuals)				1 Months Ended		3 Months Ended		12 Months Ended	51 Months Ended
	Oct. 01, 2015	Aug. 03, 2015 T	Apr. 19, 2013	Jun. 30, 2014	May. 31, 2014	Mar. 31, 2016 USD ($) phases T	Mar. 31, 2015 USD ($) T	Dec. 31, 2014 USD ($)	Mar. 31, 2016 USD ($) T	Dec. 31, 2015 USD ($)	Jun. 30, 2013	Oct. 31, 2012 USD ($)
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated						$ 3,700,000,000			$ 3,700,000,000
New syndicated senior secured term loan facility						$ 406,000,000			406,000,000
Proposed goal to reduce CO2 pollution (percent)						90.00%
Nuclear plant decommissioning trusts						$ 2,360,000,000			2,360,000,000	$ 2,282,000,000
Clean Water Act
Guarantor Obligations [Line Items]
Waste water discharge permit renewal cycle			5 years
Regulation of Waste Disposal
Guarantor Obligations [Line Items]
Bond closure and post closure period						45 years
Period to complete closure						12 years
Accrual for environmental loss contingencies						$ 123,000,000			123,000,000
Environmental liabilities former gas facilities						87,000,000			87,000,000
Nuclear Plant Matters
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts						2,400,000,000			2,400,000,000
Parental guarantee						$ 24,500,000			24,500,000
Renewal length of operating license for Davis-Besse Nuclear Power Station						20 years
Caa Compliance
Guarantor Obligations [Line Items]
Loss in period									$ 226,000,000
Amount remaining under contract | T						5,500,000			5,500,000
National Ambient Air Quality Standards
Guarantor Obligations [Line Items]
Capping of SO2 emissions under CSAPR | T						2,400,000
Capping of NOx emissions under CSAPR | T						1,200,000
National Ambient Air Quality Standards | CSAPR
Guarantor Obligations [Line Items]
Number of phases under the EPA’s CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides | phases						2
Hazardous Air Pollutant Emissions
Guarantor Obligations [Line Items]
Potential cost of compliance, MATS						$ 345,000,000			$ 345,000,000
Climate Change
Guarantor Obligations [Line Items]
Percent reduction in GHG emissions between 2005 and 2012											10.00%
Annual percentage that fish impingement should be reduced to, per CWA					12.00%
Climate Change | Year 2016
Guarantor Obligations [Line Items]
Anticipated reduction in CO2 emissions (percent)											25.00%
Regulated Distribution
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions						1,000,000			1,000,000
Regulated Distribution | Caa Compliance
Guarantor Obligations [Line Items]
Loss in period									130,000,000
Regulated Distribution | Hazardous Air Pollutant Emissions
Guarantor Obligations [Line Items]
Potential cost of compliance, MATS						177,000,000			177,000,000
Competitive Energy Services | Caa Compliance
Guarantor Obligations [Line Items]
Loss in period									96,000,000
Competitive Energy Services | Hazardous Air Pollutant Emissions
Guarantor Obligations [Line Items]
Potential cost of compliance, MATS						168,000,000			168,000,000
FES
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions						180,000,000			180,000,000
Potential collateral posted related to net liability positions						3,000,000			3,000,000
New syndicated senior secured term loan facility						25,000,000			25,000,000
Settlement amount								$ 70,000,000
Nuclear plant decommissioning trusts						1,372,000,000			1,372,000,000	$ 1,327,000,000
Global Holding | Senior Secured Term Loan | Senior Loans
Guarantor Obligations [Line Items]
New syndicated senior secured term loan facility						$ 300,000,000	$ 300,000,000		$ 300,000,000			$ 350,000,000
Global Holding | Senior Secured Term Loan | Senior Loans | Signal Peak, Global Rail and Affiliates
Guarantor Obligations [Line Items]
Investment ownership percentage						69.99%			69.99%
FEV | Global Holding
Guarantor Obligations [Line Items]
Loss in period							$ 24,000,000
FEV | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding
Guarantor Obligations [Line Items]
Investment ownership percentage						33.33%			33.33%
WMB Marketing Ventures, LLC | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding
Guarantor Obligations [Line Items]
Investment ownership percentage						33.33%			33.33%
Environmental Protection Agency | Caa Compliance
Guarantor Obligations [Line Items]
Period of time to implement plan	3 years
Minimum | Clean Water Act
Guarantor Obligations [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits						$ 150,000,000
Maximum | Clean Water Act
Guarantor Obligations [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits						300,000,000
Maximum | State and Local Agencies | Climate Change
Guarantor Obligations [Line Items]
Potential MATS extension period				2 years
Put Option | FEV | Signal Peak
Guarantor Obligations [Line Items]
Derivative notional amount mass (tons) | T							2,000,000
Certain Coal-Fired Power Plant | FirstEnergy Generation LLC | Mercury and Air Toxic Standards
Guarantor Obligations [Line Items]
Minimum coal supply commitment (ton) | T		3,500,000.0
Another Coal-Fired Power Plant | FirstEnergy Generation LLC | Mercury and Air Toxic Standards
Guarantor Obligations [Line Items]
Minimum coal supply commitment (ton) | T		2,500,000.0
FirstEnergy
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated						591,000,000			$ 591,000,000
Subsidiaries
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated						2,100,000,000			2,100,000,000
Other Guarantee
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated						300,000,000			300,000,000
Other Assurances
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated						$ 669,000,000			$ 669,000,000

XML

Supplemental Guarantor Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Consolidating Statements of Income
Revenues	[1]	$ 3,869	$ 3,897
OPERATING EXPENSES:
Fuel		381	513
Purchased power		1,124	1,113
Other operating expenses		918	1,057
Provision for depreciation		329	319
General taxes		280	269
Total operating expenses		3,093	3,303
OPERATING INCOME		776	594
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		28	17
Interest expense		(288)	(279)
Capitalized interest		25	34
Total other income (expense)		(235)	(228)
INCOME BEFORE INCOME TAXES		541	366
INCOME TAXES (BENEFITS)		213	144
NET INCOME (LOSS)		328	222
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		328	222
Pension and OPEB prior service costs		(18)	(31)
Amortized gains on derivative hedges		2	1
Change in unrealized gain on available-for-sale securities		28	4
Other comprehensive income (loss)		12	(26)
Income taxes (benefits) on other comprehensive income (loss)		4	(10)
Other comprehensive income (loss), net of tax		8	(16)
COMPREHENSIVE INCOME (LOSS)		336	206
FES
Consolidating Statements of Income
Revenues		1,155	1,332
OPERATING EXPENSES:
Fuel		0	0
Other operating expenses		4	180
Provision for depreciation		3	3
General taxes		8	15
Total operating expenses		1,319	1,698
OPERATING INCOME		(164)	(366)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		251	241
Capitalized interest		0	0
Total other income (expense)		229	222
INCOME BEFORE INCOME TAXES		65	(144)
INCOME TAXES (BENEFITS)		(66)	(141)
NET INCOME (LOSS)		131	(3)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		131	(3)
Pension and OPEB prior service costs		(4)	(4)
Amortized gains on derivative hedges			(1)
Change in unrealized gain on available-for-sale securities		23	3
Other comprehensive income (loss)		19	(2)
Income taxes (benefits) on other comprehensive income (loss)		7	(1)
Other comprehensive income (loss), net of tax		12	(1)
COMPREHENSIVE INCOME (LOSS)		143	(4)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		927	957
OTHER INCOME (EXPENSE):
Interest expense		(9)	(6)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		377	543
OTHER INCOME (EXPENSE):
Interest expense		(13)	(13)
FGCO
Consolidating Statements of Income
Revenues		415	493
OPERATING EXPENSES:
Fuel		119	180
Other operating expenses		71	67
Provision for depreciation		31	30
General taxes		10	8
Total operating expenses		231	285
OPERATING INCOME		184	208
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		6	3
Capitalized interest		2	1
Total other income (expense)		(20)	(24)
INCOME BEFORE INCOME TAXES		164	184
INCOME TAXES (BENEFITS)		61	67
NET INCOME (LOSS)		103	117
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		103	117
Pension and OPEB prior service costs		(3)	(4)
Amortized gains on derivative hedges			0
Change in unrealized gain on available-for-sale securities		0	0
Other comprehensive income (loss)		(3)	(4)
Income taxes (benefits) on other comprehensive income (loss)		(1)	(1)
Other comprehensive income (loss), net of tax		(2)	(3)
COMPREHENSIVE INCOME (LOSS)		101	114
FGCO | Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FGCO | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(26)	(26)
Nuclear Generation Corp
Consolidating Statements of Income
Revenues		531	507
OPERATING EXPENSES:
Fuel		46	50
Other operating expenses		153	154
Provision for depreciation		50	48
General taxes		8	6
Total operating expenses		314	326
OPERATING INCOME		217	181
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		17	14
Capitalized interest		8	8
Total other income (expense)		12	8
INCOME BEFORE INCOME TAXES		229	189
INCOME TAXES (BENEFITS)		86	70
NET INCOME (LOSS)		143	119
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		143	119
Pension and OPEB prior service costs		0	3
Amortized gains on derivative hedges			0
Change in unrealized gain on available-for-sale securities		23	0
Other comprehensive income (loss)		23	3
Income taxes (benefits) on other comprehensive income (loss)		8	1
Other comprehensive income (loss), net of tax		15	2
COMPREHENSIVE INCOME (LOSS)		158	121
Nuclear Generation Corp | Affiliates
OPERATING EXPENSES:
Purchased power		57	68
OTHER INCOME (EXPENSE):
Interest expense		(2)	(1)
Nuclear Generation Corp | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		(11)	(13)
Eliminations
Consolidating Statements of Income
Revenues		(902)	(955)
OPERATING EXPENSES:
Fuel		0	0
Other operating expenses		12	12
Provision for depreciation		(1)	(1)
General taxes		0	0
Total operating expenses		(891)	(944)
OPERATING INCOME		(11)	(11)
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		(259)	(245)
Capitalized interest		0	0
Total other income (expense)		(234)	(223)
INCOME BEFORE INCOME TAXES		(245)	(234)
INCOME TAXES (BENEFITS)		1	2
NET INCOME (LOSS)		(246)	(236)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		(246)	(236)
Pension and OPEB prior service costs		3	1
Amortized gains on derivative hedges			0
Change in unrealized gain on available-for-sale securities		(23)	0
Other comprehensive income (loss)		(20)	1
Income taxes (benefits) on other comprehensive income (loss)		(7)	0
Other comprehensive income (loss), net of tax		(13)	1
COMPREHENSIVE INCOME (LOSS)		(259)	(235)
Eliminations | Affiliates
OPERATING EXPENSES:
Purchased power		(902)	(955)
OTHER INCOME (EXPENSE):
Interest expense		11	7
Eliminations | Non-Affiliates
OPERATING EXPENSES:
Purchased power		0	0
OTHER INCOME (EXPENSE):
Interest expense		14	15
FES
Consolidating Statements of Income
Revenues		1,199	1,377
OPERATING EXPENSES:
Fuel		165	230
Other operating expenses		240	413
Provision for depreciation		83	80
General taxes		26	29
Total operating expenses		973	1,365
OPERATING INCOME		226	12
OTHER INCOME (EXPENSE):
Investment income (loss), including net income from equity investees		15	13
Capitalized interest		10	9
Total other income (expense)		(13)	(17)
INCOME BEFORE INCOME TAXES		213	(5)
INCOME TAXES (BENEFITS)		82	(2)
NET INCOME (LOSS)		131	(3)
OTHER COMPREHENSIVE INCOME (LOSS):
NET INCOME (LOSS)		131	(3)
Pension and OPEB prior service costs		(4)	(4)
Amortized gains on derivative hedges		0	(1)
Change in unrealized gain on available-for-sale securities		23	3
Other comprehensive income (loss)		19	(2)
Income taxes (benefits) on other comprehensive income (loss)		7	(1)
Other comprehensive income (loss), net of tax		12	(1)
COMPREHENSIVE INCOME (LOSS)		143	(4)
FES | Affiliates
OPERATING EXPENSES:
Purchased power		82	70
OTHER INCOME (EXPENSE):
Interest expense		(2)	(2)
FES | Non-Affiliates
OPERATING EXPENSES:
Purchased power		377	543
OTHER INCOME (EXPENSE):
Interest expense		$ (36)	$ (37)
Bruce Mansfield Unit 1
Condensed Financial Statements, Captions [Line Items]
Percentage of undivided interest of non guarantor subsidiary		93.83%

[1] Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

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Supplemental Guarantor Information (Details 1) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014
CURRENT ASSETS:
Cash and cash equivalents	$ 146	$ 131		$ 85	$ 90
Receivables-
Customers	1,432	1,415
Other	162	180
Materials and supplies	781	785
Derivatives	207	157
Collateral	80	70
Prepayments and other	155	167
Total current assets	3,230	3,040
PROPERTY, PLANT AND EQUIPMENT:
In service	50,371	49,952
Less - Accumulated provision for depreciation	15,421	15,160
Property, plant and equipment in service net of accumulated provision for depreciation	34,950	34,792
Construction work in progress	2,694	2,422
Total net property, plant and equipment	37,644	37,214
INVESTMENTS:
Nuclear plant decommissioning trusts	2,360	2,282
Other	526	506
Total other property and investments	2,886	2,788
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	6,418	6,418	$ 6,418
Other	1,238	1,286
Total deferred charges and other assets	8,935	9,052
Total assets	52,695	52,094	51,879
CURRENT LIABILITIES:
Currently payable long-term debt	1,355	1,166
Other	2,125	1,708
Accounts payable-
Accrued taxes	513	519
Derivatives	117	106
Other	970	694
Total current liabilities	6,389	5,602
CAPITALIZATION:
Total common stockholders' equity	12,463	12,421
Long-term debt and other long-term obligations	18,878	19,099
Total capitalization	31,342	31,521
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	6,996	6,773
Retirement benefits	4,135	4,245
Asset retirement obligations	1,427	1,410
Other	1,430	1,555
Total noncurrent liabilities	14,964	14,971
Total liabilities and capitalization	52,695	52,094
FES
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	229	275
Affiliated companies	442	433
Other	32	36
Notes receivable from affiliated companies	394	406
Materials and supplies	39	53
Derivatives	207	154
Collateral	80	70
Prepayments and other	69	48
Total current assets	1,492	1,475
PROPERTY, PLANT AND EQUIPMENT:
In service	92	93
Less - Accumulated provision for depreciation	43	40
Property, plant and equipment in service net of accumulated provision for depreciation	49	53
Construction work in progress	30	30
Total net property, plant and equipment	79	83
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	7,712	7,452
Other	0	0
Total other property and investments	7,712	7,452
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	276	300
Customer intangibles	57	61
Goodwill	23	23
Property taxes	0	0
Derivatives	89	79
Other	24	29
Total deferred charges and other assets	469	492
Total assets	9,752	9,502
CURRENT LIABILITIES:
Currently payable long-term debt	0	0
Other		0
Accounts payable-
Affiliated companies	619	884
Other	26	21
Accrued taxes	3	7
Derivatives	115	103
Other	75	66
Total current liabilities	3,211	3,102
CAPITALIZATION:
Total common stockholders' equity	5,749	5,605
Long-term debt and other long-term obligations	690	690
Total capitalization	6,439	6,295
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	6	6
Retirement benefits	28	27
Asset retirement obligations	0	0
Derivatives	21	37
Other	47	35
Total noncurrent liabilities	102	105
Total liabilities and capitalization	9,752	9,502
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	2,373	2,021
FGCO
CURRENT ASSETS:
Cash and cash equivalents	2	2	2	2
Receivables-
Customers	0	0
Affiliated companies	310	403
Other	1	4
Notes receivable from affiliated companies	1,429	1,210
Materials and supplies	191	204
Derivatives	0	0
Collateral	0	0
Prepayments and other	11	18
Total current assets	1,944	1,841
PROPERTY, PLANT AND EQUIPMENT:
In service	6,389	6,367
Less - Accumulated provision for depreciation	2,163	2,144
Property, plant and equipment in service net of accumulated provision for depreciation	4,226	4,223
Construction work in progress	271	249
Total net property, plant and equipment	4,497	4,472
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	10	10
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	16
Customer intangibles	0	0
Goodwill	0	0
Property taxes	9	12
Derivatives	0	0
Other	301	312
Total deferred charges and other assets	310	340
Total assets	6,761	6,663
CURRENT LIABILITIES:
Currently payable long-term debt	266	229
Other		8
Accounts payable-
Affiliated companies	190	146
Other	90	118
Accrued taxes	52	93
Derivatives	0	1
Other	74	61
Total current liabilities	1,058	1,045
CAPITALIZATION:
Total common stockholders' equity	3,046	2,944
Long-term debt and other long-term obligations	2,067	2,116
Total capitalization	5,113	5,060
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	35	0
Retirement benefits	311	305
Asset retirement obligations	188	191
Derivatives	0	1
Other	56	61
Total noncurrent liabilities	590	558
Total liabilities and capitalization	6,761	6,663
FGCO | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	386	389
Nuclear Generation Corp
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	305	461
Other	74	19
Notes receivable from affiliated companies	889	805
Materials and supplies	216	213
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	1,484	1,498
PROPERTY, PLANT AND EQUIPMENT:
In service	8,277	8,233
Less - Accumulated provision for depreciation	3,863	3,775
Property, plant and equipment in service net of accumulated provision for depreciation	4,414	4,458
Construction work in progress	972	878
Total net property, plant and equipment	5,386	5,336
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372	1,327
Investment in affiliated companies	0	0
Other	0	0
Total other property and investments	1,372	1,327
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	0	0
Goodwill	0	0
Property taxes	21	28
Derivatives	0	0
Other	4	14
Total deferred charges and other assets	25	42
Total assets	8,267	8,203
CURRENT LIABILITIES:
Currently payable long-term debt	308	308
Other		0
Accounts payable-
Affiliated companies	172	368
Other	0	0
Accrued taxes	101	62
Derivatives	0	0
Other	15	9
Total current liabilities	598	747
CAPITALIZATION:
Total common stockholders' equity	4,634	4,476
Long-term debt and other long-term obligations	840	840
Total capitalization	5,474	5,316
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	0	0
Accumulated deferred income taxes	743	697
Retirement benefits	0	0
Asset retirement obligations	650	640
Derivatives	0	0
Other	802	803
Total noncurrent liabilities	2,195	2,140
Total liabilities and capitalization	8,267	8,203
Nuclear Generation Corp | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	2	0
Eliminations
CURRENT ASSETS:
Cash and cash equivalents	0	0	0	0
Receivables-
Customers	0	0
Affiliated companies	(610)	(846)
Other	0	0
Notes receivable from affiliated companies	(2,712)	(2,410)
Materials and supplies	0	0
Derivatives	0	0
Collateral	0	0
Prepayments and other	0	0
Total current assets	(3,322)	(3,256)
PROPERTY, PLANT AND EQUIPMENT:
In service	(382)	(382)
Less - Accumulated provision for depreciation	(195)	(194)
Property, plant and equipment in service net of accumulated provision for depreciation	(187)	(188)
Construction work in progress	0	0
Total net property, plant and equipment	(187)	(188)
INVESTMENTS:
Nuclear plant decommissioning trusts	0	0
Investment in affiliated companies	(7,712)	(7,452)
Other	0	0
Total other property and investments	(7,712)	(7,452)
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	(276)	(316)
Customer intangibles	0	0
Goodwill	0	0
Property taxes	0	0
Derivatives	0	0
Other	56	12
Total deferred charges and other assets	(220)	(304)
Total assets	(11,441)	(11,200)
CURRENT LIABILITIES:
Currently payable long-term debt	(25)	(25)
Other		0
Accounts payable-
Affiliated companies	(619)	(856)
Other	0	0
Accrued taxes	(85)	(86)
Derivatives	0	0
Other	77	45
Total current liabilities	(3,364)	(3,332)
CAPITALIZATION:
Total common stockholders' equity	(7,680)	(7,420)
Long-term debt and other long-term obligations	(1,117)	(1,136)
Total capitalization	(8,797)	(8,556)
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	(62)	(103)
Retirement benefits	0	0
Asset retirement obligations	0	0
Derivatives	0	0
Other	0	0
Total noncurrent liabilities	720	688
Total liabilities and capitalization	(11,441)	(11,200)
Eliminations | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	(2,712)	(2,410)
FES
CURRENT ASSETS:
Cash and cash equivalents	2	2	$ 2	$ 2
Receivables-
Customers	229	275
Affiliated companies	447	451
Other	107	59
Notes receivable from affiliated companies	0	11
Materials and supplies	446	470
Derivatives	207	154
Collateral	80	70
Prepayments and other	80	66
Total current assets	1,598	1,558
PROPERTY, PLANT AND EQUIPMENT:
In service	14,376	14,311
Less - Accumulated provision for depreciation	5,874	5,765
Property, plant and equipment in service net of accumulated provision for depreciation	8,502	8,546
Construction work in progress	1,273	1,157
Total net property, plant and equipment	9,775	9,703
INVESTMENTS:
Nuclear plant decommissioning trusts	1,372	1,327
Investment in affiliated companies	0	0
Other	10	10
Total other property and investments	1,382	1,337
DEFERRED CHARGES AND OTHER ASSETS:
Accumulated deferred income tax benefits	0	0
Customer intangibles	57	61
Goodwill	23	23
Property taxes	30	40
Derivatives	89	79
Other	385	367
Total deferred charges and other assets	584	570
Total assets	13,339	13,168
CURRENT LIABILITIES:
Currently payable long-term debt	549	512
Other		8
Accounts payable-
Affiliated companies	362	542
Other	116	139
Accrued taxes	71	76
Derivatives	115	104
Other	241	181
Total current liabilities	1,503	1,562
CAPITALIZATION:
Total common stockholders' equity	5,749	5,605
Long-term debt and other long-term obligations	2,480	2,510
Total capitalization	8,229	8,115
NONCURRENT LIABILITIES:
Deferred gain on sale and leaseback transaction	782	791
Accumulated deferred income taxes	722	600
Retirement benefits	339	332
Asset retirement obligations	838	831
Derivatives	21	38
Other	905	899
Total noncurrent liabilities	3,607	3,491
Total liabilities and capitalization	13,339	13,168
FES | Affiliates
CURRENT LIABILITIES:
Short-term borrowings	$ 49	$ 0

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Supplemental Guarantor Information (Details 2) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	$ 638	$ 193
New Financing-
Short-term borrowings, net	425	760
Redemptions and Repayments-
Long-term debt	(31)	(48)
Net cash provided from (used for) financing activities	242	560
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(698)	(668)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	465	371
Purchases of investment securities held in trusts	(488)	(394)
Cash investments	30	21
Other	9	10
Net cash used for investing activities	(865)	(748)
Net change in cash and cash equivalents	15	5
Cash and cash equivalents at beginning of period	131	85
Cash and cash equivalents at end of period	146
FES
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	(356)	(662)
New Financing-
Short-term borrowings, net	352	674
Redemptions and Repayments-
Long-term debt		(17)
Short-term borrowings, net	0	0
Other		0
Net cash provided from (used for) financing activities	352	657
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27)	(1)
Nuclear fuel	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Cash investments	10
Loans to affiliated companies, net	12	6
Other	9
Net cash used for investing activities	4	5
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	277	222
New Financing-
Short-term borrowings, net	8	0
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	(11)	(5)
Other	(2)	(2)
Net cash provided from (used for) financing activities	(5)	(7)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(53)	(36)
Nuclear fuel	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Cash investments	0
Loans to affiliated companies, net	(219)	(179)
Other	0
Net cash used for investing activities	(272)	(215)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	2	2
Nuclear Generation Corp
Consolidated Statements of Cash Flows [Abstract]
Net cash provided from operating activities	307	545
New Financing-
Short-term borrowings, net	1	0
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	0	(28)
Other		0
Net cash provided from (used for) financing activities	1	(28)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(63)	(82)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	138	189
Purchases of investment securities held in trusts	(151)	(202)
Cash investments	0
Loans to affiliated companies, net	(83)	(362)
Other	0
Net cash used for investing activities	(308)	(517)
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-
Short-term borrowings, net	(312)	(524)
Redemptions and Repayments-
Long-term debt		0
Short-term borrowings, net	11	33
Other		0
Net cash provided from (used for) financing activities	(301)	(491)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	0	0
Nuclear fuel	0	0
Sales of investment securities held in trusts	0	0
Purchases of investment securities held in trusts	0	0
Cash investments	0
Loans to affiliated companies, net	301	491
Other	0
Net cash used for investing activities	301	491
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	228	105
New Financing-
Short-term borrowings, net	49	150
Redemptions and Repayments-
Long-term debt	0	(17)
Short-term borrowings, net	0	0
Other	(2)	(2)
Net cash provided from (used for) financing activities	47	131
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(143)	(119)
Nuclear fuel	(149)	(60)
Sales of investment securities held in trusts	138	189
Purchases of investment securities held in trusts	(151)	(202)
Cash investments	10	0
Loans to affiliated companies, net	11	(44)
Other	9	0
Net cash used for investing activities	(275)	(236)
Net change in cash and cash equivalents	0	0
Cash and cash equivalents at beginning of period	2	2
Cash and cash equivalents at end of period	$ 2	$ 2

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Segment Information (Details) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Segment Financial Information
Revenues		$ 3,869	$ 3,897
Revenues	[1]	3,869	3,897
Depreciation		329	319
Amortization of regulatory assets, net		61	32
Investment income (loss)		28	17
Interest expense		288	279
Income taxes (benefits)		213	144
NET INCOME (LOSS)		328	222
Total assets		52,695	51,879	$ 52,094
Goodwill		6,418	6,418	$ 6,418
Property additions		698	668
Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Regulated Distribution
Segment Financial Information
Revenues		2,521	2,562
Revenues		2,521	2,562
Depreciation		169	172
Amortization of regulatory assets, net		59	29
Investment income (loss)		11	13
Interest expense		147	144
Income taxes (benefits)		98	122
NET INCOME (LOSS)		165	208
Total assets		27,907	27,974
Goodwill		5,092	5,092
Property additions		262	280
Regulated Distribution | Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Regulated Transmission
Segment Financial Information
Revenues		275	238
Revenues		275	238
Depreciation		43	37
Amortization of regulatory assets, net		2	3
Investment income (loss)		0	0
Interest expense		43	39
Income taxes (benefits)		43	42
NET INCOME (LOSS)		74	72
Total assets		7,679	6,601
Goodwill		526	526
Property additions		258	254
Regulated Transmission | Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Competitive Energy Services
Segment Financial Information
Revenues		1,152	1,175
Revenues		1,304	1,435
Depreciation		102	96
Amortization of regulatory assets, net		0	0
Investment income (loss)		15	12
Interest expense		47	48
Income taxes (benefits)		85	(4)
NET INCOME (LOSS)		144	(8)
Total assets		16,578	16,497
Goodwill		800	800
Property additions		169	126
Competitive Energy Services | Intersegment Eliminations
Segment Financial Information
Revenues		152	260
Other/Corporate
Segment Financial Information
Revenues		(42)	(42)
Revenues		(42)	(42)
Depreciation		15	14
Amortization of regulatory assets, net		0	0
Investment income (loss)		11	2
Interest expense		51	47
Income taxes (benefits)		(13)	(18)
NET INCOME (LOSS)		(55)	(50)
Total assets		531	807
Goodwill		0	0
Property additions		9	8
Other/Corporate | Intersegment Eliminations
Segment Financial Information
Revenues		0	0
Reconciling Adjustments
Segment Financial Information
Revenues		(37)	(36)
Revenues		(189)	(296)
Depreciation		0	0
Amortization of regulatory assets, net		0	0
Investment income (loss)		(9)	(10)
Interest expense		0	1
Income taxes (benefits)		0	2
NET INCOME (LOSS)		0	0
Total assets		0	0
Goodwill		0	0
Property additions		0	0
Reconciling Adjustments | Intersegment Eliminations
Segment Financial Information
Revenues		$ (152)	$ (260)

[1] Includes excise tax collections of $107 million and $115 million in the three months ended March 31, 2016 and 2015, respectively.

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Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Billions	3 Months Ended
	Mar. 31, 2016 USD ($) mi² customer company MW
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
Number of square miles in service area | mi²	65
Megawatts of net demonstrated capacity of competitive segment | MW	3,790
Competitive Energy Services
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment | MW	13,162
Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 4.2
Long-term debt percentage bearing variable interest (percent)	28.00%
FirstEnergy | Revolving Credit Facility | Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit | $	$ 2.1