10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended June 30, 2019

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, $0.10 par value	FE	New York Stock Exchange

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  ☑  No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

Yes  ☑  No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer	☑
Accelerated Filer	☐
Non-accelerated Filer	☐
Smaller Reporting Company	☐
Emerging Growth Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standard provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

Yes ☐  No ☑

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 JUNE 30, 2019
Common Stock, $0.10 par value	532,092,829

FirstEnergy Website and Other Social Media Sites and Applications

FirstEnergy’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, amendments to those reports and all other documents filed with or furnished to the SEC pursuant to Section 13(a) of the Securities Exchange Act of 1934 are made available free of charge on or through the “Investors” page of FirstEnergy’s website at www.firstenergycorp.com. These documents are also available to the public from commercial document retrieval services and the website maintained by the SEC at www.sec.gov.

These SEC filings are posted on the website as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. Additionally, FirstEnergy routinely posts additional important information, including press releases, investor presentations and notices of upcoming events under the “Investors” section of FirstEnergy’s website and recognizes FirstEnergy’s website 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 Regulation FD. Investors may be notified of postings to the website by signing up for email alerts and Rich Site Summary feeds on the “Investors” page of FirstEnergy’s website. 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 Regulation FD. Information contained on FirstEnergy’s website, 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.

Forward-Looking Statements: This Form 10-Q includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 based on information currently available to management. Such statements are subject to certain risks and uncertainties and readers are cautioned not to place undue reliance on these forward-looking statements. 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 (see Glossary of Terms for definitions of capitalized terms):

• The ability to successfully execute an exit from commodity-based generation, including, without limitation, mitigating exposure for remedial activities associated with formerly owned generation assets.

• The risks associated with the FES Bankruptcy that could adversely affect us, our liquidity or results of operations, including, without limitation, that conditions to the FES Bankruptcy settlement agreement may not be met or that the FES Bankruptcy settlement agreement may not be otherwise consummated, and if so, the potential for litigation and payment demands against us by FES or FENOC or their creditors.

• The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, our strategy to operate and grow as a fully regulated business, to execute our transmission and distribution investment plans, to continue to reduce costs through FE Tomorrow and other initiatives, and to improve our credit metrics, strengthen our balance sheet and grow earnings.

• Legislative and regulatory developments, including, but not limited to, matters related to rates, compliance and enforcement activity.

• Economic and weather conditions affecting future operating results, such as significant weather events and other natural disasters, and associated regulatory events or actions.

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

• Changes in customers’ demand for power, including, but not limited to, the impact of climate change or energy efficiency and peak demand reduction mandates.

• Changes in national and regional economic conditions affecting us and/or our major industrial and commercial customers or others with which we do business.

• The risks associated with cyber-attacks and other disruptions to our information technology system, which may compromise our operations, and data security breaches of sensitive data, intellectual property and proprietary or personally identifiable information.

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

• Changes to environmental laws and regulations, including, but not limited to, those related to climate change.

• Changing market conditions affecting the measurement of certain liabilities and the value of assets held in our pension trusts and other trust funds, or causing us to make contributions sooner, or in amounts that are larger, than currently anticipated.

• The risks associated with the decommissioning of our retired and former nuclear facilities.

• The risks and uncertainties associated with litigation, arbitration, mediation and like proceedings.

• Labor disruptions by our unionized workforce.

• Changes to significant accounting policies.

• Any changes in tax laws or regulations, including the Tax Act, or adverse tax audit results or rulings.

• 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.

• Actions that may be taken by credit rating agencies that could negatively affect either our access to or terms of financing or our financial condition and liquidity.

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

Dividends declared from time to time on our common stock, and thereby on our preferred stock, during any period may in the aggregate vary from prior periods due to circumstances considered by our 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.

These forward-looking statements are also qualified by, and should be read together with, the risk factors included in FirstEnergy’s 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 and Current Reports on Form 8-K. The foregoing review of factors also should not be construed as exhaustive. New factors emerge from time to time, and it is not possible for management to predict all such factors, nor assess the impact of any such factor on FirstEnergy’s business or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statements. FirstEnergy expressly disclaims any obligation to update or revise, except as required by law, any forward-looking statements contained herein or in the information incorporated by reference 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
Notes To Consolidated Financial Statements	5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	40
Item 3. Quantitative and Qualitative Disclosures About Market Risk	76
Item 4. Controls and Procedures	76
Part II. Other Information
Item 1. Legal Proceedings	76
Item 1A. Risk Factors	76
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	76
Item 3. Defaults Upon Senior Securities	76
Item 4. Mine Safety Disclosures	76
Item 5. Other Information	76
Item 6. Exhibits	77

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, which subsequently merged with and into FE on January 1, 2014
AE Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC	Allegheny Generating Company, formerly a generation subsidiary of AE Supply that became a wholly owned subsidiary of MP in May 2018
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
BSPC	Bay Shore Power Company
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
CES	Competitive Energy Services, formerly a reportable operating segment of FirstEnergy
FE	FirstEnergy Corp., a public utility holding company
FENOC	FirstEnergy Nuclear Operating Company, a subsidiary of FE, which operates NG’s nuclear generating facilities
FES	FirstEnergy Solutions Corp., together with its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage LLC, and FGMUC, which provides energy-related products and services
FES Debtors	FES and FENOC
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, MAIT and TrAIL, and has a joint venture in PATH
FEV	FirstEnergy Ventures Corp., which invests in certain unregulated enterprises and business ventures
FG	FirstEnergy Generation, LLC, a wholly owned subsidiary of FES, which owns and operates non-nuclear generating facilities
FGMUC	FirstEnergy Generation Mansfield Unit 1 Corp., a wholly owned subsidiary of FG, which has certain leasehold interests in a portion of Unit 1 at the Bruce Mansfield plant
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	Global Rail Group, LLC, a subsidiary of Global Holding that owns coal transportation operations near Roundup, Montana
GPU	GPU, Inc., former parent of JCP&L, ME and PN, that merged with FE on November 7, 2001
JCP&L	Jersey Central Power & Light Company, a New Jersey electric utility operating subsidiary
MAIT	Mid-Atlantic Interstate Transmission, LLC, a subsidiary of FET, which owns and operates 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 wholly owned 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
Signal Peak	Signal Peak Energy, LLC, 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
Transmission Companies	ATSI, MAIT and TrAIL
Utilities	OE, CEI, TE, Penn, JCP&L, ME, PN, MP, PE and WP
WP	West Penn Power Company, a Pennsylvania electric utility operating subsidiary

ii

The following abbreviations and acronyms are used to identify frequently used terms in this report:
ACE	Affordable Clean Energy	ESP IV	Electric Security Plan IV
ADIT	Accumulated Deferred Income Taxes	Facebook®	Facebook is a registered trademark of Facebook, Inc.
AEP	American Electric Power Company, Inc.	FASB	Financial Accounting Standards Board
AFS	Available-for-sale	FERC	Federal Energy Regulatory Commission
AFUDC	Allowance for Funds Used During Construction	FE Tomorrow	FirstEnergy’s initiative launched in late 2016 to identify its optimal organizational structure and properly align corporate costs and systems to efficiently support a fully regulated company going forward
ALJ	Administrative Law Judge	FES Bankruptcy	FES Debtors’ voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court
AOCI	Accumulated Other Comprehensive Income	Fitch	Fitch Ratings
ARO	Asset Retirement Obligation	FMB	First Mortgage Bond
ARP	Alternative Revenue Program	FPA	Federal Power Act
ASC	Accounting Standard Codification	FTR	Financial Transmission Right
ASU	Accounting Standards Update	GAAP	Accounting Principles Generally Accepted in the United States of America
Bankruptcy Court	U.S. Bankruptcy Court in the Northern District of Ohio in Akron	GHG	Greenhouse Gases
Bath County	Bath County Pumped Storage Hydro-Power Station	IIP	Infrastructure Investment Program
BGS	Basic Generation Service	kW	Kilowatt
CAA	Clean Air Act	LBR	Little Blue Run
CCR	Coal Combustion Residuals	LIBOR	London Interbank Offered Rate
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980	LOC	Letter of Credit
CFR	Code of Federal Regulations	LTIIPs	Long-Term Infrastructure Improvement Plans
CO2	Carbon Dioxide	MDPSC	Maryland Public Service Commission
CPP	EPA’s Clean Power Plan	MGP	Manufactured Gas Plants
CSAPR	Cross-State Air Pollution Rule	MISO	Midcontinent Independent System Operator, Inc.
CTA	Consolidated Tax Adjustment	mmBTU	One Million British Thermal Units
CWA	Clean Water Act	Moody’s	Moody’s Investors Service, Inc.
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit	MW	Megawatt
DCR	Delivery Capital Recovery	MWH	Megawatt-hour
DMR	Distribution Modernization Rider	NAAQS	National Ambient Air Quality Standards
DPM	Distribution Platform Modernization	NDT	Nuclear Decommissioning Trust
DSIC	Distribution System Improvement Charge	NERC	North American Electric Reliability Corporation
DSP	Default Service Plan	NJBPU	New Jersey Board of Public Utilities
EDC	Electric Distribution Company	NMB	Non-Market Based
EDCP	Executive Deferred Compensation Plan	NOAC	Northwest Ohio Aggregation Coalition
EDIS	Electric Distribution Investment Surcharge	NOI	Notice of Inquiry
EE&C	Energy Efficiency and Conservation	NOL	Net Operating Loss
EEI	Edison Electric Institute	NOPR	Notice of Proposed Rulemaking
EGS	Electric Generation Supplier	NOx	Nitrogen Oxide
EGU	Electric Generation Units	NRC	Nuclear Regulatory Commission
EmPOWER Maryland	EmPOWER Maryland Energy Efficiency Act	NUG	Non-Utility Generation
ENEC	Expanded Net Energy Cost	NYPSC	New York State Public Service Commission
EPA	United States Environmental Protection Agency	OCA	Office of Consumer Advocate
EPS	Earnings per Share	OCC	Ohio Consumers’ Counsel
ERO	Electric Reliability Organization	OEPA	Ohio Environmental Protection Agency

iii

OMAEG	Ohio Manufacturers’ Association Energy Group	ROE	Return on Equity
OPEB	Other Post-Employment Benefits	RTEP	Regional Transmission Expansion Plan
OPIC	Other Paid-in Capital	RTO	Regional Transmission Organization
OVEC	Ohio Valley Electric Corporation	S&P	Standard & Poor’s Ratings Service
PA DEP	Pennsylvania Department of Environmental Protection	SBC	Societal Benefits Charge
PJM	PJM Interconnection, LLC	SCOH	Supreme Court of Ohio
PJM Tariff	PJM Open Access Transmission Tariff	SEC	United States Securities and Exchange Commission
POLR	Provider of Last Resort	SIP	State Implementation Plan(s) Under the Clean Air Act
POR	Purchase of Receivables	SO2	Sulfur Dioxide
PPA	Purchase Power Agreement	SOS	Standard Offer Service
PPB	Parts per Billion	SPE	Special Purpose Entity
PPUC	Pennsylvania Public Utility Commission	SREC	Solar Renewable Energy Credit
PUCO	Public Utilities Commission of Ohio	SSO	Standard Service Offer
PURPA	Public Utility Regulatory Policies Act of 1978	Tax Act	Tax Cuts and Jobs Act adopted December 22, 2017
RCRA	Resource Conservation and Recovery Act	TMI-2	Three Mile Island Unit 2
Regulation FD	Regulation Fair Disclosure promulgated by the SEC	Twitter®	Twitter is a registered trademark of Twitter, Inc.
REC	Renewable Energy Credit	UCC	Official committee of unsecured creditors appointed in connection with the FES Bankruptcy
RFC	ReliabilityFirst Corporation	VIE	Variable Interest Entity
RFP	Request for Proposal	VSCC	Virginia State Corporation Commission
RGGI	Regional Greenhouse Gas Initiative	WVPSC	Public Service Commission of West Virginia
		ZEC	Zero Emissions Certificate

iv

PART I. FINANCIAL INFORMATION

ITEM I.         Financial Statements

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF INCOME

(Unaudited)

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(In millions, except per share amounts)	2019			2018			2019			2018
REVENUES:
Distribution services and retail generation	$	1,931		$	2,049		$	4,240		$	4,344
Transmission	367			336			719			655
Other	218			240			440			488
Total revenues(1)	2,516			2,625			5,399			5,487
OPERATING EXPENSES:
Fuel	129			128			260			267
Purchased power	611			697			1,392			1,517
Other operating expenses	606			684			1,385			1,624
Provision for depreciation	309			283			606			560
Amortization (deferral) of regulatory assets, net	37			(107		)	42			(255		)
General taxes	239			240			500			494
Total operating expenses	1,931			1,925			4,185			4,207
OPERATING INCOME	585			700			1,214			1,280
OTHER INCOME (EXPENSE):
Miscellaneous income, net	80			48			134			115
Interest expense	(259		)	(355		)	(512		)	(603		)
Capitalized financing costs	16			16			34			31
Total other expense	(163		)	(291		)	(344		)	(457		)
INCOME BEFORE INCOME TAXES	422			409			870			823
INCOME TAXES	81			101			174			334
INCOME FROM CONTINUING OPERATIONS	341			308			696			489
Discontinued operations (Note 3)(2)	(29		)	(9		)	(64		)	1,179
NET INCOME	$	312		$	299		$	632		$	1,668
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4)	4			165			9			304
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	308		$	134		$	623		$	1,364
EARNINGS PER SHARE OF COMMON STOCK (Note 4):
Basic - Continuing Operations	$	0.63		$	0.30		$	1.29		$	0.39
Basic - Discontinued Operations	(0.05		)	(0.02		)	(0.12		)	2.47
Basic - Net Income Attributable to Common Stockholders	$	0.58		$	0.28		$	1.17		$	2.86
Diluted - Continuing Operations	$	0.63		$	0.30		$	1.29		$	0.39
Diluted - Discontinued Operations	(0.05		)	(0.02		)	(0.12		)	2.46
Diluted - Net Income Attributable to Common Stockholders	$	0.58		$	0.28		$	1.17		$	2.85
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	532			477			531			477
Diluted	533			479			533			478

(1) Includes excise and gross receipts tax collections of $81 million and $87 million during the three months ended June 30, 2019 and 2018, respectively, and $183 million and $189 million during the six months ended June 30, 2019 and 2018, respectively.

(2) Net of income tax expense (benefits) of $39 million and $(16) million for the three months ended June 30, 2019 and 2018, respectively, and $44 million and $(887) million for the six months ended June 30, 2019 and 2018, respectively.

The accompanying 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 June 30,						For the Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
NET INCOME	$	312		$	299		$	632		$	1,668
OTHER COMPREHENSIVE LOSS:
Pension and OPEB prior service costs	(7		)	(19		)	(14		)	(37		)
Amortized losses on derivative hedges	—			2			1			17
Change in unrealized gains on AFS securities	—			—			—			(106		)
Other comprehensive loss	(7		)	(17		)	(13		)	(126		)
Income tax benefits on other comprehensive loss	(2		)	(4		)	(3		)	(57		)
Other comprehensive loss, net of tax	(5		)	(13		)	(10		)	(69		)
COMPREHENSIVE INCOME	$	307		$	286		$	622		$	1,599

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

2

FIRSTENERGY CORP.

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In millions, except share amounts)	June 30, 2019			December 31, 2018
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	422		$	367
Restricted cash	52			62
Receivables-
Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018	1,109			1,221
Affiliated companies, net of allowance for uncollectible accounts of $937 in 2019 and $920 in 2018	—			20
Other, net of allowance for uncollectible accounts of $3 in 2019 and $2 in 2018	218			270
Materials and supplies, at average cost	261			252
Prepaid taxes and other	280			175
Current assets - discontinued operations	44			25
	2,386			2,392
PROPERTY, PLANT AND EQUIPMENT:
In service	40,572			39,469
Less — Accumulated provision for depreciation	11,139			10,793
	29,433			28,676
Construction work in progress	1,245			1,235
	30,678			29,911
INVESTMENTS:
Nuclear plant decommissioning trusts	863			790
Nuclear fuel disposal trust	265			256
Other	275			253
	1,403			1,299
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618			5,618
Regulatory assets	94			91
Other	705			752
	6,417			6,461
	$	40,884		$	40,063
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	381		$	503
Short-term borrowings	1,250			1,250
Accounts payable	810			965
Accounts payable - affiliated companies	25			—
Accrued taxes	416			533
Accrued compensation and benefits	231			318
Collateral	30			39
Other	840			1,026
	3,983			4,634
CAPITALIZATION:
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 532,092,829 and 511,915,450 shares outstanding as of June 30, 2019 and December 31, 2018, respectively	53			51
Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - 209,822 and 704,589 shares outstanding as of June 30, 2019 and December 31, 2018, respectively	21			71
Other paid-in capital	11,411			11,530
Accumulated other comprehensive income	31			41
Accumulated deficit	(4,247		)	(4,879		)
Total stockholders’ equity	7,269			6,814
Long-term debt and other long-term obligations	19,053			17,751
	26,322			24,565
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	2,760			2,502
Retirement benefits	2,414			2,906
Regulatory liabilities	2,584			2,498
Asset retirement obligations	833			812
Adverse power contract liability	79			89
Other	1,909			2,057
	10,579			10,864
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 13)
	$	40,884		$	40,063

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

3

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months Ended June 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	632		$	1,668
Adjustments to reconcile net income to net cash from operating activities-
Loss (gain) on disposal, net of tax (Note 3)	39			(1,239		)
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs	702			604
Deferred income taxes and investment tax credits, net	162			327
Retirement benefits, net of payments	(53		)	(97		)
Pension trust contributions	(500		)	(1,250		)
Changes in current assets and liabilities-
Receivables	217			20
Materials and supplies	(29		)	28
Prepaid taxes and other	(109		)	(143		)
Accounts payable	(183		)	50
Accrued taxes	(117		)	(58		)
Accrued compensation and benefits	(126		)	(76		)
Other current liabilities	(16		)	(152		)
Collateral, net	(8		)	(15		)
Other	14			45
Net cash provided from (used for) operating activities	625			(288		)
CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
Long-term debt	1,950			450
Short-term borrowings, net	—			1,364
Preferred stock issuance	—			1,616
Common stock issuance	—			850
Redemptions and Repayments-
Long-term debt	(757		)	(2,251		)
Make-whole premiums paid on debt redemptions	—			(89		)
Preferred stock dividend payments	(6		)	(42		)
Common stock dividend payments	(403		)	(343		)
Other	(28		)	(21		)
Net cash provided from financing activities	756			1,534
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,228		)	(1,307		)
Proceeds from asset sales	12			390
Sales of investment securities held in trusts	302			475
Purchases of investment securities held in trusts	(322		)	(508		)
Notes receivable from affiliated companies	—			(500		)
Asset removal costs	(103		)	(118		)
Other	3			3
Net cash used for investing activities	(1,336		)	(1,565		)
Net change in cash, cash equivalents, and restricted cash	45			(319		)
Cash, cash equivalents, and restricted cash at beginning of period	429			643
Cash, cash equivalents, and restricted cash at end of period	$	474		$	324
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction, beneficial conversion feature (Note 4)	$	—		$	296
Non-cash transaction, deemed dividend preferred stock (Note 4)	$	—		$	(261	)

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

4

FIRSTENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note Number		Page Number
1	Organization and Basis of Presentation	6
2	Revenue	8
3	Discontinued Operations	12
4	Earnings Per Share of Common Stock	15
5	Pension and Other Postemployment Benefits	17
6	Accumulated Other Comprehensive Income	18
7	Income Taxes	19
8	Leases	19
9	Capitalization	23
10	Variable Interest Entities	25
11	Fair Value Measurements	26
12	Regulatory Matters	29
13	Commitments, Guarantees and Contingencies	34
14	Segment Information	37

5

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)

1. ORGANIZATION AND BASIS OF PRESENTATION

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

FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, AE Supply, MP, AGC, PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including: Allegheny Energy Service Corporation, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPU Nuclear, Inc., and Allegheny Ventures, Inc.

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity.

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 Annual Report on Form 10-K for the year ended December 31, 2018.

FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, 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 and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 10, “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.

Certain prior year amounts have been reclassified to conform to the current year presentation, as discussed in Note 3, “Discontinued Operations.”

FES and FENOC Chapter 11 Filing

On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). As a result of the bankruptcy filings, FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements. Since such time, FE has accounted and will account for its investments in the FES Debtors at fair values of zero. FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. See Note 3, “Discontinued Operations,” for additional information.

On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others:

• FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits.

• FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety

6

bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors’ unfunded pension obligations.

• A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.

• A $225 million cash payment from FirstEnergy.

• A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

• Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred. FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

• FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

• FirstEnergy has agreed to fund through its pension plan a pension enhancement, which is subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits (approximately $14 million recognized in 2019).

• FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018 (approximately $52 million was paid in 2018, which amount will be finalized after filing the 2018 Federal tax return).

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the FES Bankruptcy settlement agreement. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy.

As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.

On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization and which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement.

Capitalized Financing Costs

For each of the three months ended June 30, 2019 and 2018, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $9 million and $12 million, respectively, of allowance for equity funds used during construction and $7 million and $4 million, respectively, of capitalized interest. For each of the six months ended June 30, 2019 and 2018, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $22 million and $23 million, respectively, of allowance for equity funds used during construction and $12 million and $8 million, respectively, of capitalized interest.

7

Restricted Cash

Restricted cash primarily relates to the consolidated VIE’s discussed in Note 10, “Variable Interest Entities.” The cash collected from JCP&L, MP, PE and the Ohio Companies’ customers is used to service debt of their respective funding companies.

New Accounting Pronouncements

Recently Adopted Pronouncements

ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires 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, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

2. REVENUE

FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.

FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.

8

The following tables represent a disaggregation of revenue from contracts with customers for the three months ended June 30, 2019 and 2018, by type of service from each reportable segment:

	For the Three Months Ended June 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services	$	1,160	$	—	$	(21	)	$	1,139
Retail generation	806		—		(14		)	792
Wholesale sales	110		—		3			113
Transmission(2)	—		367		—			367
Other	37		—		—			37
Total revenues from contracts with customers	$	2,113	$	367	$	(32	)	$	2,448
ARP	55		—		—			55
Other non-customer revenue	24		5		(16		)	13
Total revenues	$	2,192	$	372	$	(48	)	$	2,516

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $2 million in reductions at Regulated Transmission to revenue related to amounts subject to refund resulting from the Tax Act.

	For the Three Months Ended June 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	1,228	$	—	$	(47	)	$	1,181
Retail generation	882		—		(14		)	868
Wholesale sales	121		—		5			126
Transmission(2)	—		336		—			336
Other	35		—		3			38
Total revenues from contracts with customers	$	2,266	$	336	$	(53	)	$	2,549
ARP	60		—		—			60
Other non-customer revenue	26		5		(15		)	16
Total revenues	$	2,352	$	341	$	(68	)	$	2,625

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $8 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($10 million at Regulated Distribution, partially offset by $2 million subject to recovery at Regulated Transmission).

Other non-customer revenue includes revenue from late payment charges of $9 million for both the three months ended June 30, 2019 and 2018, as well as revenue from derivatives of $3 million and $4 million, for the three months ended June 30, 2019 and 2018, respectively.

9

The following tables represent a disaggregation of revenue from contracts with customers for the six months ended June 30, 2019 and 2018, by type of service from each reportable segment:

	For the Six Months Ended June 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	2,446	$	—	$	(42	)	$	2,404
Retail generation	1,864		—		(28		)	1,836
Wholesale sales	216		—		7			223
Transmission(2)	—		719		—			719
Other	71		—		1			72
Total revenues from contracts with customers	$	4,597	$	719	$	(62	)	$	5,254
ARP	117		—		—			117
Other non-customer revenue	51		9		(32		)	28
Total revenues	$	4,765	$	728	$	(94	)	$	5,399

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $34 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($27 million at Regulated Distribution and $7 million at Regulated Transmission).

	For the Six Months Ended June 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	2,509	$	—	$	(59	)	$	2,450
Retail generation	1,922		—		(28		)	1,894
Wholesale sales	244		—		10			254
Transmission(2)	—		655		—			655
Other	70		—		4			74
Total revenues from contracts with customers	$	4,745	$	655	$	(73	)	$	5,327
ARP	124		—		—			124
Other non-customer revenue	59		9		(32		)	36
Total revenues	$	4,928	$	664	$	(105	)	$	5,487

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $84 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($82 million at Regulated Distribution and $2 million at Regulated Transmission).

Other non-customer revenue includes revenue from late payment charges of $20 million and $19 million, as well as revenue from derivatives of $5 million and $14 million, for the six months ended June 30, 2019 and 2018, respectively.

Regulated Distribution

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 12, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.

Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail

10

tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer.

The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the three and six months ended June 30, 2019 and 2018, by class:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Revenues by Customer Class	2019		2018		2019		2018
	(In millions)
Residential	$	1,123	$	1,255	$	2,607	$	2,718
Commercial	572		570		1,159		1,150
Industrial	251		262		500		516
Other	20		23		44		47
Total Revenues	$	1,966	$	2,110	$	4,310	$	4,431

Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported gross as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and incremental auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur.

The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days.

ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy currently has ARPs in Ohio, primarily under Rider DMR, and in New Jersey.

Regulated Transmission

The Regulated Transmission segment provides transmission infrastructure owned and operated by ATSI, TrAIL, MAIT and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at ATSI, TrAIL and MAIT, as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.

Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million, which is recognized ratably as revenue over time.

11

The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the three and six months ended June 30, 2019 and 2018, by transmission owner:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Transmission Owner	2019		2018		2019		2018
	(In millions)
ATSI	$	184	$	167	$	358	$	325
TrAIL	59		63		117		123
MAIT	50		34		99		64
Other	74		72		145		143
Total Revenues	$	367	$	336	$	719	$	655

3. DISCONTINUED OPERATIONS

FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. Prior period results have been reclassified to conform with such presentation as discontinued operations.

FES and FENOC Chapter 11 Bankruptcy Filing

As discussed in Note 1, “Organization and Basis of Presentation,” on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors, as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements, and FirstEnergy has accounted and will account for its investments in the FES Debtors at fair values of zero. In connection with the disposal and the FES Bankruptcy settlement agreement approved by the Bankruptcy Court in September 2018, as further discussed in Note 1, “Organization and Basis of Presentation,” FE recorded an after-tax gain on disposal of $435 million in 2018.

By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company.

FES Borrowings from FE

On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility.

On March 16, 2018, the FES Debtors withdrew from the unregulated companies’ money pool, which included FE, and the FES Debtors. Under the terms of the FES Bankruptcy settlement agreement, FE reinstated $88 million for 2018 estimated payments for NOLs applied against the FES Debtor’s position in the unregulated companies’ money pool prior to their withdrawal on March 16, 2018, which increased the amount the FES Debtors owed FE under the money pool to $92 million. In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of the FES Debtors on March 31, 2018, and given the terms of the FES Bankruptcy settlement agreement, FE fully reserved the $92 million associated with the outstanding unsecured borrowings under the unregulated companies’ money pool and the $102 million associated with the AE Supply unsecured promissory note, under the terms of the FES Bankruptcy settlement agreement, FirstEnergy will release any and all claims against the FES Debtors with respect to the $92 million owed under the unregulated money pool and $102 million unsecured promissory note. For the six months ended June 30, 2019 and 2018, approximately $18 million and $8 million of interest was accrued and subsequently reserved, respectively.

12

Services Agreements

Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until no later than June 30, 2020, subject to reductions in services if requested by the FES Debtors. Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost. In addition to providing for certain notice requirements and other terms and conditions, the agreement provided for a credit to the FES Debtors in an amount up to $112.5 million for charges incurred for services provided under prior shared services agreements and the amended shared services agreement from April 1, 2018 through December 31, 2018. The entire credit for shared services provided to the FES Debtors ($112.5 million) has been recognized by FE and was included within the loss from discontinued operations as of December 31, 2018. The FES Debtors have paid approximately $67 million and $101 million for shared services for the three and six months ended June 30, 2019, respectively.

Benefit Obligations

FirstEnergy will retain certain obligations for the FES Debtors’ employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a net liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. EDCP and pension/OPEB service costs earned by the FES Debtors’ employees during bankruptcy are billed under the shared services agreement. As FE continues to provide pension benefits to FES/FENOC employees, certain components of pension cost, including the mark to market, are seen as providing ongoing services and are reported in the continuing operations of FE, subsequent to the bankruptcy filing. FE has billed the FES Debtors approximately $9 million and $19 million for their share of pension and OPEB service costs for the three and six months ended June 30, 2019, respectively.

Purchase Power

FES at times provides power through affiliated company power sales to meet a portion of the Utilities’ POLR and default service requirements and provides power to certain affiliates’ facilities. As of June 30, 2019, the Utilities owed FES approximately $7 million related to these purchases. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. The Utilities purchased and recognized in continuing operations approximately $43 million and $71 million of power purchases from FES for the three months ended June 30, 2019 and 2018, respectively, and $126 million and $174 million for the six months ended June 30, 2019 and 2018, respectively.

Income Taxes

For U.S. federal income taxes, until emergence from bankruptcy, the FES Debtors will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return NOL as a future worthless stock deduction. FirstEnergy currently estimates a future worthless stock deduction of approximately $4.8 billion ($1.0 billion, net of tax) and is net of unrecognized tax benefits of $418 million ($88 million, net of tax). The estimated worthless stock deduction is contingent upon the emergence of the FES Debtors from the FES Bankruptcy and such amounts may be materially impacted by future events.

Additionally, discontinued operations include tax expense of approximately $14 million and $20 million for the three months ended June 30, 2019 and 2018, respectively, and $28 million and $36 million for the six months ended June 30, 2019 and 2018, respectively, due to certain aspects of the Tax Act that apply as a result of the FES Debtors remaining a part of FirstEnergy’s consolidated tax return.

See Note 1, “Organization and Basis of Presentation,” for further discussion of the settlement among FirstEnergy, the FES Key Creditor Groups, the FES Debtors and the UCC.

Competitive Generation Asset Sales

FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power Equity Partners III, LP, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply’s interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants. On March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility. On May 3, 2018, AE Supply and AGC completed the sale of approximately 59% of AGC’s interest in Bath County. Also, on May 3, 2018, following the closing of the sale by AGC of a portion of its ownership interest in Bath County, AGC completed the redemption of AE Supply’s shares in AGC and AGC became a wholly owned subsidiary of MP.

On March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Power, LLC (formerly Walleye Energy, LLC), for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The Bankruptcy Court approved the sale on July 13, 2018, and the transaction was completed on July 31, 2018.

As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate

13

Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.

Individually, the AE Supply and BSPC asset sales and Pleasants Power Station transfer did not qualify for reporting as discontinued operations. However, in the aggregate, the transactions were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES’ and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations.

Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the three and six months ended June 30, 2019 and 2018, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Revenues	$	31		$	90		$	85		$	826
Fuel	(20		)	(54		)	(55		)	(218		)
Purchased power	—			(1		)	—			(59		)
Other operating expenses	(16		)	(21		)	(26		)	(390		)
Provision for depreciation	—			(16		)	—			(79		)
General taxes	(5		)	(5		)	(9		)	(28		)
Other income (expense) (1)	10			(18		)	8			(80		)
Income (loss) from discontinued operations, before tax	—			(25		)	3			(28		)
Income tax expense (benefit)	14			(16		)	28			32
Loss from discontinued operations, net of tax	(14		)	(9		)	(25		)	(60		)
Gain (loss) on disposal of FES and FENOC, net of tax	(15		)	—			(39		)	1,239
Income (loss) from discontinued operations	$	(29	)	$	(9	)	$	(64	)	$	1,179

⁽¹⁾ Other income (expense) for the three and six months ended June 30, 2019, reflects the amounts owed to or from FG for its economic interests in Pleasants effective January 1, 2019, as further discussed above.

The gain (loss) on disposal of FES and FENOC recognized in the three and six months ended June 30, 2019 and 2018, consisted of the following:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
(In millions)	2019			2018		2019			2018
Removal of investment in FES and FENOC	$	—		$	—	$	—		$	2,193
Assumption of benefit obligations retained at FE	—			—		—			(820		)
Guarantees and credit support provided by FE	—			—		—			(139		)
Reserve on receivables and allocated pension/OPEB mark-to-market	—			—		—			(914		)
Settlement consideration and services credit	10			—		(23		)	—
Gain (loss) on disposal of FES and FENOC, before tax	10			—		(23		)	320
Income tax benefit (expense), including estimated worthless stock deduction	(25		)	—		(16		)	919
Gain (loss) on disposal of FES and FENOC, net of tax	$	(15	)	$	—	$	(39	)	$	1,239

As of June 30, 2019, and December 31, 2018, material and supplies of $44 million and $25 million, respectively, are included in FirstEnergy’s Consolidated Balance Sheets as Current assets - discontinued operations.

14

FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the six months ended June 30, 2019 and 2018:

	For the Six Months Ended June 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	$	(64	)	$	1,179
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs	—			80
Unrealized gain on derivative transactions	—			(10		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	—			(23		)
Sales of investment securities held in trusts	—			109
Purchases of investment securities held in trusts	—			(122		)

4. EARNINGS PER SHARE OF COMMON STOCK

The convertible preferred stock issued in January 2018 (see Note 9, “Capitalization”) is considered participating securities since these shares participate in dividends on common stock on an “as-converted” basis. As a result, EPS of common stock is computed using the two-class method required for participating securities.

The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations:

• preferred stock dividends,

• deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and

• an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends.

Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations.

The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend and was fully amortized in 2018.

Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive.

Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.

15

The following table reconciles basic and diluted EPS of common stock:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Reconciliation of Basic and Diluted EPS of Common Stock	2019			2018			2019			2018
(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	341		$	308		$	696		$	489
Less: Preferred dividends	—			—			(3		)	(43		)
Less: Amortization of beneficial conversion feature	—			(148		)	—			(261		)
Less: Undistributed earnings allocated to preferred stockholders(1)	(5		)	(18		)	(7		)	—
Income from continuing operations available to common stockholders	336			142			686			185
Discontinued operations, net of tax	(29		)	(9		)	(64		)	1,179
Less: Undistributed earnings allocated to preferred stockholders (1)	1			1			1			—
Income (loss) from discontinued operations available to common stockholders	(28		)	(8		)	(63		)	1,179
Income available to common stockholders, basic and diluted	$	308		$	134		$	623		$	1,364
Share Count information:
Weighted average number of basic shares outstanding	532			477			531			477
Assumed exercise of dilutive stock options and awards	1			2			2			1
Weighted average number of diluted shares outstanding	533			479			533			478
Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic	$	0.63		$	0.30		$	1.29		$	0.39
Discontinued operations, basic	(0.05		)	(0.02		)	(0.12		)	2.47
Income available to common stockholders, basic	$	0.58		$	0.28		$	1.17		$	2.86
Income from continuing operations, diluted	$	0.63		$	0.30		$	1.29		$	0.39
Discontinued operations, diluted	(0.05		)	(0.02		)	(0.12		)	2.46
Income available to common stockholders, diluted	$	0.58		$	0.28		$	1.17		$	2.85

⁽¹⁾  Undistributed earnings were not allocated to participating securities for the six months ended June 30, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss.

For the three and six months ended June 30, 2018, 1 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be anti-dilutive to basic EPS from continuing operations. For the three and six months ended June 30, 2019, no shares from stock options and awards were excluded from the calculation of diluted shares outstanding. Also, 8 million shares associated with the assumed conversion of preferred stock were excluded for the three and six months ended June 30, 2019, and 59 million shares for the three and six months ended June 30, 2018, as their inclusion would be anti-dilutive to basic EPS from continuing operations.

16

5. PENSION AND OTHER POSTEMPLOYMENT BENEFITS

The components of the consolidated net periodic costs (credits) for pension and OPEB were as follows:

Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended June 30,	2019			2018			2019			2018
	(In millions)
Service costs (1)	$	48		$	56		$	1		$	1
Interest costs (2)	93			93			5			6
Expected return on plan assets (2)	(135		)	(144		)	(7		)	(7		)
Amortization of prior service costs (credits) (2)	2			2			(9		)	(20		)
Special termination costs (2) (3)	(1		)	—			—			—
Net periodic costs (credits), including amounts capitalized	$	7		$	7		$	(10	)	$	(20	)
Net periodic costs (credits), recognized in earnings	$	(14	)	$	(18	)	$	(10	)	$	(21	)
Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Six Months Ended June 30,	2019			2018			2019			2018
	(In millions)
Service costs (1)	$	96		$	112		$	2		$	2
Interest costs (2)	186			186			10			12
Expected return on plan assets (2)	(270		)	(288		)	(14		)	(15		)
Amortization of prior service costs (credits) (2)	4			4			(18		)	(40		)
Special termination costs (2) (3)	14			—			—			—
Net periodic costs (credits), including amounts capitalized	$	30		$	14		$	(20	)	$	(41	)
Net periodic costs (credits), recognized in earnings	$	(8	)	$	(32	)	$	(20	)	$	(42	)

⁽¹⁾ Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income.

⁽²⁾ Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.

⁽³⁾ FirstEnergy has agreed to fund through its pension plan a pension enhancement, which is subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits (approximately $14 million recognized in the first six months of 2019).

Amounts in the tables above include the FES Debtors’ share of the net periodic pension and OPEB costs (credits) of $11 million and $(1) million, respectively, for the three months ended June 30, 2019, and $22 million and $(2) million, respectively, for the six months ended June 30, 2019. The FES Debtors’ share of the net periodic pension and OPEB costs (credits) were $13 million and $(10) million, respectively, for the three months ended June 30, 2018, and $26 million and $(20) million, respectively, for the six months ended June 30, 2018. The 2019 special termination costs associated with FES’ voluntary enhanced retirement package are a component of Discontinued operations in FirstEnergy’s Consolidated Statements of Income. Following the FES Debtors’ voluntary bankruptcy filing, FE has billed the FES Debtors approximately $9 million and $19 million for their share of pension and OPEB service costs for the three and six months ended June 30, 2019, respectively.

On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021.

17

6. ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables show the changes in AOCI for the three and six months ended June 30, 2019 and 2018, for FirstEnergy:

	Gains & Losses on Cash Flow Hedges (1)			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, April 1, 2019	$	(10	)	$	—		$	46		$	36
Amounts reclassified from AOCI	—			—			(7		)	(7		)
Other comprehensive loss	—			—			(7		)	(7		)
Income tax benefits on other comprehensive loss	—			—			(2		)	(2		)
Other comprehensive loss, net of tax	—			—			(5		)	(5		)
AOCI Balance, June 30, 2019	$	(10	)	$	—		$	41		$	31
AOCI Balance, April 1, 2018	$	(15	)	$	—		$	101		$	86
Amounts reclassified from AOCI	2			—			(19		)	(17		)
Other comprehensive income (loss)	2			—			(19		)	(17		)
Income taxes (benefits) on other comprehensive income (loss)	1			—			(5		)	(4		)
Other comprehensive income (loss), net of tax	1			—			(14		)	(13		)
AOCI Balance, June 30, 2018	$	(14	)	$	—		$	87		$	73
	Gains & Losses on Cash Flow Hedges (1)			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, January 1, 2019	$	(11	)	$	—		$	52		$	41
Amounts reclassified from AOCI	1			—			(14		)	(13		)
Other comprehensive income (loss)	1			—			(14		)	(13		)
Income tax benefits on other comprehensive income (loss)	—			—			(3		)	(3		)
Other comprehensive income (loss), net of tax	1			—			(11		)	(10		)
AOCI Balance, June 30, 2019	$	(10	)	$	—		$	41		$	31
AOCI Balance, January 1, 2018	$	(22	)	$	67		$	97		$	142
Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI	4			(1		)	(37		)	(34		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	17			(106		)	(37		)	(126		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(27		)	(57		)
Other comprehensive income (loss), net of tax	8			(67		)	(10		)	(69		)
AOCI Balance, June 30, 2018	$	(14	)	$	—		$	87		$	73

⁽¹⁾ Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance.

18

The following amounts were reclassified from AOCI for FirstEnergy in the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI(1)	2019			2018			2019			2018 (2)
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	—		$	—		$	—		$	1		Other operating expenses
Long-term debt	—			2			1			3			Interest expense
	—			—			—			(1		)	Income taxes
	$	—		$	2		$	1		$	3		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	—		$	—		$	(1	)	Discontinued operations
Defined benefit pension and OPEB plans
Prior-service costs	$	(7	)	$	(19	)	$	(14	)	$	(37	)	(3)
	2			4			3			9			Income taxes
	$	(5	)	$	(15	)	$	(11	)	$	(28	)	Net of tax
(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
(2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”.
(3)  Prior-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, “Pension and Other Postemployment Benefits.”

7. INCOME TAXES

FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2019 and 2018. 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 for the three months ended June 30, 2019 and 2018, was 19.2% and 24.7%, respectively. The decrease in effective tax rate was primarily due to an income tax benefit from the re-measurement of reserves for uncertain tax positions and an increase in the amortization of net excess deferred income taxes. See Note 12, “Regulatory Matters,” for additional details.

FirstEnergy’s effective tax rate for the six months ended June 30, 2019 and 2018, was 20.0% and 40.6%, respectively. In addition to the factors mentioned above, the decrease in the effective tax rate was primarily due to the absence of a one-time charge of approximately $126 million to income tax expense in continuing operations associated with the re-measurement of West Virginia state deferred income taxes, resulting from the legal and financial separation of FES and FENOC from FirstEnergy, which occurred in the first quarter of 2018. See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations.

During the six months ended June 30, 2019, FirstEnergy increased its reserve for uncertain tax positions taken in the current year by approximately $7 million, none of which had an impact on the effective tax rate as the full amount was recorded to discontinued operations. In the three months ended June 30, 2019, FirstEnergy remeasured its reserve for uncertain tax positions, which resulted in a decrease to the reserve of approximately $10 million. As of June 30, 2019, it is reasonably possible that FirstEnergy could record a net decrease to its reserve for uncertain tax positions by approximately $54 million within the next twelve months due to the statute of limitations expiring or resolution with taxing authorities, of which approximately $51 million would impact FirstEnergy’s effective tax rate.

In June 2019, the Internal Revenue Service completed its examination of FirstEnergy’s 2017 federal income tax return and issued a full acceptance letter with no changes or adjustments to FirstEnergy’s taxable income.

8. LEASES

FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.

19

FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material.

Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants.

For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of June 30, 2019, the maximum potential loss for these lease agreements at the end of the lease term is approximately $16 million.

Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:

	For the Three Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	8	$	1	$	3	$	12
Finance lease costs:
Amortization of right-of-use assets	4		—		—		4
Interest on lease liabilities	1		1		—		2
Total finance lease cost	5		1		—		6
Total lease cost	$	13	$	2	$	3	$	18

⁽¹⁾ Includes $2 million of short-term lease costs.

	For the Six Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	15	$	3	$	6	$	24
Finance lease costs:
Amortization of right-of-use assets	8		—		1		9
Interest on lease liabilities	2		2		—		4
Total finance lease cost	10		2		1		13
Total lease cost	$	25	$	5	$	7	$	37

⁽¹⁾ Includes $6 million of short-term lease costs.

20

Supplemental cash flow information related to leases was as follows:

(In millions)	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	7	$	15
Operating cash flows from finance leases	2		3
Finance cash flows from finance leases	5		9
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	20	$	26
Finance leases	1		2

Lease terms and discount rates were as follows:

	As of June 30, 2019
Weighted-average remaining lease terms (years)
Operating leases	8.57
Finance leases	4.75
Weighted-average discount rate (1)
Operating leases	4.91	%
Finance leases	3.45	%

⁽¹⁾ When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.

Supplemental balance sheet information related to leases was as follows:

(In millions)	Financial Statement Line Item	As of June 30, 2019
Assets
Operating lease assets, net of accumulated amortization of $11 million	Deferred charges and other assets	$	188
Finance lease assets, net of accumulated amortization of $89 million	Property, plant and equipment	74
Total leased assets		$	262
Liabilities
Current:
Operating	Other current liabilities	$	31
Finance	Currently payable long-term debt	16
Noncurrent:
Operating	Other noncurrent liabilities	196
Finance	Long-term debt and other long-term obligations	51
Total leased liabilities		$	294

21

Maturities of lease liabilities as of June 30, 2019, were as follows:

(In millions)	Operating Leases			Finance Leases			Total
2019	$	18		$	11		$	29
2020	38			19			57
2021	36			17			53
2022	35			15			50
2023	32			8			40
2024	27			4			31
Thereafter	99			12			111
Total lease payments (1)	285			86			371
Less imputed interest	(58		)	(19		)	(77		)
Total net present value	$	227		$	67		$	294

⁽¹⁾ Operating lease payments for certain leases are offset by sublease receipts of $13 million over 14 years.

As of June 30, 2019, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $16 million. These leases are expected to commence within the next 18 months with lease terms of 3 to 10 years.

The future minimum capital lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Capital Leases
	(In millions)
2019	$	24
2020	19
2021	16
2022	13
2023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23		)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	$	55

The future minimum operating lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Operating Leases
	(In millions)
2019	$	34
2020	36
2021	34
2022	30
2023	28
Years thereafter	127
Total minimum lease payments	$	289

22

9. CAPITALIZATION

Stockholders’ Equity

The changes in stockholders’ equity for the three and six months ended June 30, 2019 and 2018 for FirstEnergy are included in the following tables:

	Series A Convertible Preferred Stock					Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares		Amount			Shares	Amount
Balance, January 1, 2019	0.7		$	71		512	$	51	$	11,530		$	41		$	(4,879	)	$	6,814
Net income															320			320
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									7									7
Stock Investment Plan and certain share-based benefit plans						1			1									1
Cash dividends declared on common stock									(202		)							(202		)
Cash dividends declared on preferred stock									(3		)							(3		)
Conversion of Series A Convertible Preferred Stock	(0.5	)	(50		)	18	2		48									—
Balance, March 31, 2019	0.2		$	21		531	$	53	$	11,381		$	36		$	(4,559	)	$	6,932
Net income															$	312		$	312
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									9									9
Stock Investment Plan and certain share-based benefit plans						1			21									21
Balance, June 30, 2019	0.2		$	21		532	$	53	$	11,411		$	31		$	(4,247	)	$	7,269

	Series A Convertible Preferred Stock			Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares	Amount		Shares	Amount
Balance, January 1, 2018	—	$	—	445	$	44	$	10,001		$	142		$	(6,262	)	$	3,925
Net income													1,369			1,369
Other comprehensive loss, net of tax										(56		)				(56		)
Stock-based compensation							19									19
Stock Investment Plan and certain share-based benefit plans				2	1		5									6
Cash dividends declared on common stock							(343		)							(343		)
Cash dividends declared on preferred stock							(42		)							(42		)
Stock issuance (1)	1.6	162		30	3		2,297									2,462
Impact of adopting new accounting pronouncements (2)													35			35
Balance, March 31, 2018	1.6	$	162	477	$	48	$	11,937		$	86		$	(4,858	)	$	7,375
Net income													$	299		$	299
Other comprehensive loss, net of tax										(13		)				(13		)
Stock-based compensation							19									19
Stock Investment Plan and certain share-based benefit plans				1			19									19
Balance, June 30, 2018	1.6	$	162	478	$	48	$	11,975		$	73		$	(4,559	)	$	7,699

⁽¹⁾ The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature (BCF), which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend of $261 million for the six months ended June 30, 2018) through the period from the issue date to the first allowable conversion

23

date (July 22, 2018). There is no net impact to OPIC for the three and six months ended June 30, 2018. Please see below for additional information on the issuance.

⁽²⁾ FirstEnergy adopted ASU 2016-01, “Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities” standard on January 1, 2018, and subsequently recorded a cumulative effect adjustment to retained earnings of $57 million representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. In addition, FirstEnergy adopted ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” and upon adoption, recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018. These amounts are offset in other comprehensive loss and do not have an impact on total stockholders’ equity.

Dividends declared for each share of common stock and as-converted share of preferred stock was $0.38 and $0.72 during the first quarter of 2019 and 2018, respectively. There were no dividends declared during the second quarter of 2019 or 2018.

Preferred Stock

On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in FE. FE entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). FE also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of Common Stock and $847 million of OPIC).

The preferred stock participates in dividends on the common stock on an as-converted basis based on the number of shares of common stock a holder of preferred stock would receive if its shares of preferred stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends are paid at the same time that the dividends on common stock are paid.

Subject to certain exceptions noted below, all shares of preferred stock outstanding on July 22, 2019, were automatically converted. Further, the preferred stock will automatically convert to common stock upon certain events of bankruptcy or liquidation of FE. FE may elect to convert the preferred stock if, at any time, fewer than 323,200 shares of preferred stock are outstanding. However, no shares of preferred stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding common stock. Furthermore, in no event shall FE issue more than 58,964,222 shares of common stock (the Share Cap) in the aggregate upon conversion of the convertible preferred stock. From and after the time at which the aggregate number of shares of common stock issued upon conversion of the preferred stock equals the Share Cap, each holder electing to convert convertible preferred stock will be entitled to receive a cash payment equal to the market value of the common stock such holder does not receive upon conversion.

The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature will be reflected in net income attributable to common stockholders as a deemed dividend. The amount amortized for the six months ended June 30, 2018, was $261 million. The BCF was fully amortized as of December 31, 2018.

The preferred stockholders have limited class voting rights related to the creation of additional securities that are senior or equal with the preferred stock, as well as certain reclassifications and amendments that would affect the rights of the preferred stockholders. The preferred stockholders also have the right to approve issuances of securities convertible or exchangeable for common stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans.

Each share of preferred stock is convertible at the holder’s option into a number of shares of common stock equal to the $1,000 liquidation preference, divided by the conversion price then in effect. As of June 30, 2019, the conversion price in effect was $27.42 per share. The conversion price is subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the common stock, as well as dividends on the common stock paid in common stock and for certain equity issuances below the conversion price then in effect.

During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. Also at the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019, resulting in 209,822 shares of preferred stock outstanding and yet to be converted as of June 30, 2019. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. All remaining outstanding shares of preferred stock will be automatically converted on January 22, 2020.

24

10. 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.

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):

• Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly owned limited liability company 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 June 30, 2019, and December 31, 2018, $280 million and $292 million of the phase-in recovery bonds were outstanding, respectively.

• JCP&L Securitization - 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 Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of June 30, 2019, and December 31, 2018, $33 million and $41 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 limited liability company SPEs 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 limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of June 30, 2019, and December 31, 2018, $345 million and $358 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 ventures economic performance. FEV’s ownership interest is subject to the equity method of accounting. As of June 30, 2019, the carrying value of the equity method investment was $14 million.

As discussed in Note 13, “Commitments, Guarantees and Contingencies,” FE is the guarantor under Global Holding’s $300 million term loan facility, which matures in March 2020, and has an outstanding principal balance of $180 million as of June 30, 2019. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to perform its obligations under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

• PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland, which PJM cancelled in 2012, 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. As of June 30, 2019, the carrying value of the equity method investment was $17 million.

25

• Purchase Power Agreements - FirstEnergy evaluated its PPAs 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 11 long-term PPAs 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 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 contract that may contain a variable interest during the three months ended June 30, 2019 and 2018, were $30 million and $26 million, respectively, and $61 million and $58 million during the six months ended June 30, 2019 and 2018, respectively.

• FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, “Discontinued Operations,” FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court. The carrying values of the equity investments in FES and FENOC were zero at June 30, 2019.

11. 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 are used to measure fair value.

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. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.

NUG contracts represent PPAs 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 two 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 Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and

26

historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of June 30, 2019, from those used as of December 31, 2018. 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.

The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

	June 30, 2019										December 31, 2018
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	439	$	—		$	439		$	—	$	405	$	—		$	405
Derivative assets FTRs(1)	—		—		6			6			—		—		10			10
Equity securities(2)	395		—		—			395			339		—		—			339
Foreign government debt securities	—		16		—			16			—		13		—			13
U.S. government debt securities	—		19		—			19			—		20		—			20
U.S. state debt securities	—		263		—			263			—		250		—			250
Other(3)	422		36		—			458			367		34		—			401
Total assets	$	817	$	773	$	6		$	1,596		$	706	$	722	$	10		$	1,438
Liabilities
Derivative liabilities FTRs(1)	$	—	$	—	$	(4	)	$	(4	)	$	—	$	—	$	(1	)	$	(1	)
Derivative liabilities NUG contracts(1)	—		—		(35		)	(35		)	—		—		(44		)	(44		)
Total liabilities	$	—	$	—	$	(39	)	$	(39	)	$	—	$	—	$	(45	)	$	(45	)
Net assets (liabilities)(4)	$	817	$	773	$	(33	)	$	1,557		$	706	$	722	$	(35	)	$	1,393

⁽¹⁾  Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index.

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

⁽⁴⁾  Excludes $(15) million and $4 million as of June 30, 2019 and December 31, 2018, 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 June 30, 2019, and December 31, 2018:

	NUG Contracts(1)								FTRs(1)
	Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2018 Balance	$	—	$	(79	)	$	(79	)	$	3		$	—		$	3
Unrealized gain	—		2			2			8			1			9
Purchases	—		—			—			5			(5		)	—
Settlements	—		33			33			(6		)	3			(3		)
December 31, 2018 Balance	$	—	$	(44	)	$	(44	)	$	10		$	(1	)	$	9
Unrealized loss	—		(11		)	(11		)	—			—			—
Purchases	—		—			—			6			(4		)	2
Settlements	—		20			20			(10		)	1			(9		)
June 30, 2019 Balance	$	—	$	(35	)	$	(35	)	$	6		$	(4	)	$	2

(1)Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

27

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 June 30, 2019:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	2		Model	RTO auction clearing prices	$.50 to $2.70	$1.00	Dollars/MWH
NUG Contracts	$	(35	)	Model	Generation	400 to 776,000	160,000	MWH
					Regional electricity prices	$33.50 to $34.10	$33.80	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 equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.

Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities 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.

Nuclear Decommissioning and Nuclear Fuel Disposal Trusts

JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value.

The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of June 30, 2019, and December 31, 2018:

	June 30, 2019(1)									December 31, 2018(1)
	Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value		Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)
Debt securities	$	730	$	22	$	(15	)	$	737	$	714	$	2	$	(28	)	$	688
Equity securities	$	346	$	48	$	(1	)	$	393	$	339	$	15	$	(16	)	$	338

⁽¹⁾ Excludes $(2) million and $20 million as of June 30, 2019 and December 31, 2018, respectively, of short-term cash investments, taxes, receivables, payables and accrued income.

Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three and six months ended June 30, 2019 and 2018, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Sale Proceeds	$	149		$	175		$	302		$	366
Realized Gains	5			9			12			28
Realized Losses	(5		)	(11		)	(11		)	(27		)
Interest and Dividend Income	11			10			20			20

Other Investments

Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Other investments were $275 million and $253 million as of June 30, 2019, and December 31, 2018, respectively, and are excluded from the amounts reported above.

28

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, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Carrying Value (1)	$	19,508	$	18,315
Fair Value	$	21,890	$	19,266

⁽¹⁾ The carrying value as of June 30, 2019, includes $1,950 million of debt issuances and $757 million of redemptions that occurred in the first six months of 2019.

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 June 30, 2019, and December 31, 2018.

12. REGULATORY MATTERS

STATE REGULATION

Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, 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. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also 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 EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE’s 2016 starting goal under this requirement was 0.97%. PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers 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 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.

On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised

29

its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.

NEW JERSEY

JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L 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. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.

In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey.

Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications.

On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.

OHIO

The Ohio Companies currently operate under ESP IV through May 31, 2024. ESP IV includes Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years beginning in 2017, with the possibility of a two-year extension and is grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. On February 1, 2019, the Ohio Companies filed with the PUCO an application requesting a two-year extension of Rider DMR at the same amount and conditions.

30

ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year 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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval, which was filed in February 2016, and remains pending as part of the grid modernization settlement described below; (3) a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers’ base distribution rates, which filing the PUCO denied on June 13, 2018.

Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. The Ohio Companies then filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure, which the PUCO denied. In October 2017, the Sierra Club and the OMAEG filed notices of appeal with the SCOH appealing various PUCO entries on their applications for rehearing. The Ohio Companies intervened in the appeal, and additional parties subsequently filed notices of appeal with the SCOH challenging various PUCO entries on their applications for rehearing. On September 26, 2018, the SCOH denied a July 30, 2018 joint motion filed by the OCC, the NOAC, and the OMAEG to stay the portions of the PUCO’s orders and entries under appeal that authorized Rider DMR. On June 19, 2019, the SCOH reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On July 1, 2019, the Ohio Companies filed a motion with the SCOH requesting reconsideration of the SCOH decision. Also, on July 1, 2019, the Ohio Companies filed revised tariffs with the PUCO providing that while the motion for reconsideration is pending, Rider DMR is being collected subject to refund. On July 2, 2019, the PUCO approved the Ohio Companies’ revised tariffs. On July 11, 2019, various parties filed a memorandum with the SCOH in opposition to the motion for reconsideration.

Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan, as proposed in April 2016, includes 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. In December 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plans with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modifications, which the PUCO denied on January 10, 2018. On March 12, 2018, the Ohio Companies appealed to the SCOH challenging the PUCO’s imposition of a 4% cost cap. Various other parties also appealed challenging various PUCO entries on their applications for rehearing. Oral argument on the appeals was held on February 20, 2019.

On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. Should the Ohio Companies elect to apply to the PUCO for approval of the decoupling mechanism, it would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. FirstEnergy is reviewing the potential impacts to customers and the Ohio Companies, and may seek approval for this mechanism later this year.

On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act, discussed below, to flow back to customers. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications.

On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies, effective January 1, 2018, were required to establish a regulatory

31

liability for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. On October 24, 2018, the PUCO entered an Order in its investigation into the impacts of the Tax Act on Ohio’s utilities directing that by January 1, 2019, all Ohio rate-regulated utility companies, unless ordered otherwise, file applications not for an increase in rates to reflect the impact of the Tax Act on each specific utility’s current rates. On October 30, 2018, the Ohio Companies filed an application to open a new proceeding for the implementation of matters relating to the impact of the Tax Act. As discussed further above, on November 9, 2018, the Ohio Companies filed a settlement agreement that provides for all tax savings associated with the Tax Act to flow back to customers and for the implementation of the first phase of grid modernization plans. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On December 19, 2018, the PUCO upheld its January 10, 2018 ruling that utilities should be required to establish a deferred tax liability, effective January 1, 2018, in response to the Tax Act. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The PUCO conducted a hearing on February 5 and 6, 2019. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications.

The Ohio Companies’ Rider NMB is designed to recover non-market-based transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019.

On April 19, 2019, OCC filed an application for rehearing alleging Rider DMR revenues should not have been excluded from the determination of the existence of Significantly Excessive Earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. On May 15, 2019, the PUCO denied OCC’s application for rehearing, and on July 15, 2019, OCC filed a Notice of Appeal with the SCOH. The Ohio Companies intend to contest this appeal but are unable to predict the outcome of this matter.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 must also be separately tracked for treatment in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which 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 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. The PPUC directed a working group to further discuss the implementation of customer assistance program shopping limitations and appropriate scripting for the Pennsylvania Companies’ customer referral programs, and in November 2018, issued a subsequent order to approve additional customer assistance program shopping parameters and further limit the scope of the working group discussion. On December 21, 2018, the PPUC issued a tentative order proposing a model to incorporate the directed shopping restrictions. Comments on the proposal were filed January 22, 2019. On February 28, 2019, the PPUC issued a final order approving the Pennsylvania Companies’ proposal on customer assistance programs shopping limitations and directing script modifications to the Pennsylvania Companies’ customer referral programs. 

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.

Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate

32

those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed.

The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018, and remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Pennsylvania Companies are reviewing the Commonwealth Court’s opinion and order.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates under rates approved by the WVPSC effective February 2015. 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.

FERC REGULATORY MATTERS

Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply, AGC, and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to regulation by the relevant state commissions.

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of the facilities that FirstEnergy operates 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 material 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, or obligations to upgrade or build transmission facilities that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 million until 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

33

ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.

FERC Actions on Tax Act

On March 15, 2018, FERC issued a NOI seeking information regarding whether and how FERC should address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.

Transmission ROE Methodology

In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to rely on three financial models-discounted cash flow, capital-asset pricing, and expected earnings to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the NOI comments, and any subsequent rulemaking and other proceedings.

13. COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

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

As of June 30, 2019, outstanding guarantees and other assurances aggregated approximately $1.7 billion, consisting of guarantees on behalf of FES and FENOC ($350 million), parental guarantees on behalf of its consolidated subsidiaries’ guarantees ($1 billion), other guarantees ($180 million) and other assurances ($140 million). FirstEnergy has also committed to provide additional guarantees to the FES Debtors for certain retained environmental liabilities of AE Supply related to the Pleasants Power Station and McElroy’s Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy.

COLLATERAL AND CONTINGENT-RELATED FEATURES

Certain bilateral agreements 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 ratings 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 entered into by FE and its subsidiaries have margining provisions that require posting of collateral. The Utilities have posted collateral totaling $2 million.

34

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. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2019:

Potential Collateral Obligations		AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating		$	1	$	—	$	—	$	1
Upon Further Downgrade		—		43		—		43
Surety Bonds (Collateralized Amount)(1)		1		59		246		306
Total Exposure from Contractual Obligations		$	2	$	102	$	246	$	350

⁽¹⁾  Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global Holding’s outstanding principal balance is $180 million as of June 30, 2019. 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 respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

FirstEnergy complies with SO₂ and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.

CSAPR requires reductions of NOx and SO₂ emissions in two phases (2015 and 2017), ultimately capping SO₂ emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂ emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry’s bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy’s operations, cash flows and financial condition.

In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO₂, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of June 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.

In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility’s NOx emissions significantly contribute to Delaware’s inability to attain the ozone NAAQS. The petition sought a short-term NOx

35

emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland’s inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland’s petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 9 states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018 but has not taken any further action. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

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 GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO₂ emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO₂ emissions by approximately 62 percent. In September 2016, the U.S. 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’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. 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.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” 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 CPP regulations in August 2015 to reduce CO₂ emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO₂ emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. 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. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

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 facilities. 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. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.

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 phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. 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 operations may result.

36

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 CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for 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. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment.

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 of June 30, 2019, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $119 million have been accrued through June 30, 2019. Included in the total are accrued liabilities of approximately $83 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE 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, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of June 30, 2019, JCP&L, ME and PN had in total approximately $863 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN 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.

On May 10, 2019, FirstEnergy signed a non-binding term sheet with EnergySolutions, LLC. concerning the transfer of TMI-2. This transfer of TMI-2 to EnergySolutions, LLC. will also include the transfer of the external trusts for the decommissioning and environmental remediation of TMI-2 and related liabilities of approximately $900 million as of June 30, 2019. The term sheet also contemplates EnergySolutions, LLC. decommissioning of TMI-2. EnergySolutions, LLC. nuclear decommissioning experience includes the nearly completed Zion Nuclear Power Station in Illinois and the La Crosse Boiling Water Reactor in Wisconsin. There can be no assurance that a definitive agreement will be finalized by the parties and subsequently approved by the NRC and, even if approved, whether the conditions to the closing of the transfer will be satisfied.

FES Bankruptcy

On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, “Discontinued Operations,” for additional information.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “Regulatory Matters.”

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 FE 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 FE’s or its subsidiaries’ financial condition, results of operations and cash flows.

14. SEGMENT INFORMATION

37

Regulated Distribution and Regulated Transmission are FirstEnergy’s reportable segments.

On March 31, 2018, as discussed in Note 3, “Discontinued Operations,” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at certain of JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.

The Corporate/Other segment reflects corporate support not charged to FE’s subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are shown separately in the following table of Segment Financial Information. As of June 30, 2019, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of June 30, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt.

38

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below:

Segment Financial Information

For the Three Months Ended	Regulated Distribution			Regulated Transmission		Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)
June 30, 2019
External revenues	$	2,145		$	368	$	3		$	—		$	2,516
Internal revenues	47			4		—			(51		)	—
Total revenues	$	2,192		$	372	$	3		$	(51	)	$	2,516
Depreciation	220			71		1			17			309
Amortization of regulatory assets, net	34			3		—			—			37
Miscellaneous income, net	46			4		38			(8		)	80
Interest expense	124			48		95			(8		)	259
Income taxes (benefits)	67			30		(16		)	—			81
Income (loss) from continuing operations	258			116		(33		)	—			341
Property additions	354			300		20			—			674
June 30, 2018
External revenues	$	2,285		$	336	$	4		$	—		$	2,625
Internal revenues	67			5		7			(79		)	—
Total revenues	$	2,352		$	341	$	11		$	(79	)	$	2,625
Depreciation	200			62		3			18			283
Deferral of regulatory assets, net	(107		)	—		—			—			(107		)
Miscellaneous income (expense), net	56			3		(1		)	(10		)	48
Interest expense	129			42		194			(10		)	355
Income taxes (benefits)	138			38		(75		)	—			101
Income (loss) from continuing operations	377			104		(173		)	—			308
Property additions	391			282		44			7			724
For the Six Months Ended
June 30, 2019
External revenues	$	4,671		$	720	$	8		$	—		$	5,399
Internal revenues	94			8		—			(102		)	—
Revenues	$	4,765		$	728	$	8		$	(102	)	$	5,399
Depreciation	429			140		3			34			606
Amortization of regulatory assets, net	37			5		—			—			42
Miscellaneous income, net	92			8		49			(15		)	134
Interest expense	246			93		188			(15		)	512
Income taxes (benefits)	156			61		(43		)	—			174
Income (loss) from continuing operations	587			220		(111		)	—			696
Property additions	672			531		25			—			1,228
June 30, 2018
External revenues	$	4,823		$	655	$	9		$	—		$	5,487
Internal revenues	105			9		13			(127		)	—
Revenues	$	4,928		$	664	$	22		$	(127	)	$	5,487
Depreciation	396			123		5			36			560
Amortization (deferral) of regulatory assets, net	(259		)	4		—			—			(255		)
Miscellaneous income, net	112			7		15			(19		)	115
Interest expense	257			81		284			(19		)	603
Income taxes	231			70		33			—			334
Income (loss) from continuing operations	699			203		(413		)	—			489
Property additions	655			574		55			23			1,307
As of June 30, 2019
Total assets	$	29,240		$	11,070	$	574		$	—		$	40,884
Total goodwill	5,004			614		—			—			5,618
As of December 31, 2018
Total assets	$	28,690		$	10,404	$	969		$	—		$	40,063
Total goodwill	5,004			614		—			—			5,618

39

ITEM 2.        Management’s Discussion and Analysis of Financial Condition and Results of Operations

FIRSTENERGY CORP.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FIRSTENERGY’S BUSINESS

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity through its reportable segments, Regulated Distribution and Regulated Transmission.

On March 31, 2018, FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at certain of JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.

The Corporate/Other segment reflects corporate support not charged to FE’s subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Additionally, reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are included in Corporate/Other. As of June 30, 2019, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of June 30, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt.

40

EXECUTIVE SUMMARY

FirstEnergy’s strategy is to be a fully regulated utility company, focusing on stable and predictable earnings and cash flow from its regulated business units - Regulated Distribution and Regulated Transmission - through delivering enhanced customer service and reliability. Together, the Regulated Distribution and Regulated Transmission businesses are expected to provide stable, predictable earnings and cash flows that support FE’s dividend.

The scale and diversity of the ten Utilities that comprise the Regulated Distribution business uniquely position this business for growth through opportunities for additional investment. Over the past several years, Regulated Distribution has experienced rate base growth through investments that have improved reliability and added operating flexibility to the distribution infrastructure, which provide benefits to the customers and communities those Utilities serve. Based on its current capital plan, which includes $6.2 to $6.7 billion in forecasted capital investments from 2018 through 2021, Regulated Distribution’s rate base growth rate is expected to be approximately 5% from 2018 through 2021. Additionally, this business is exploring other opportunities for growth, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on the electrification of customers’ homes and businesses by providing a full range of products and services.

With approximately 24,500 miles in operations, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with approximately 80% of its capital investments recovered under the forward-looking formula rates at ATSI, TrAIL and MAIT. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest up to $4.8 billion in capital from 2018 to 2021, which is expected to result in Regulated Transmission rate base growth of approximately 11% through 2021.

As part of the Energizing the Future initiative, a Center for Advanced Technology was opened in Akron, Ohio in April 2019. The 88,000 square feet facility was designed to be a hands-on environment where engineers and technicians can develop and evaluate new technology and grid solutions and simulate a variety of real-world conditions.

FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2021, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

On December 22, 2017, the President signed the Tax Act into law. Substantially all of the provisions of the Tax Act are effective for taxable years beginning after December 31, 2017. As discussed below, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. FirstEnergy continues to work with various state regulatory commissions to determine appropriate changes to customer rates resulting from the Tax Act. Several states have since implemented rate reductions to reflect the impact of the Tax Act, while in the remaining states, FirstEnergy continues to track and apply regulatory accounting treatment for the expected rate impact of changes resulting from the Tax Act. FERC also recently took action to address the impact of the Tax Act on FERC-jurisdictional rates, including transmission and electric wholesale rates. FirstEnergy has reflected the impact of changes to current taxes in its normal update to FERC-jurisdictional transmission rates and will continue to work with FERC regarding whether and how it should address possible changes to transmission and wholesale rates resulting from the Tax Act.

As previously disclosed, on January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The equity investment strengthened the Company’s balance sheet, supports the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participate in the dividend paid on common stock on an as-converted basis and are non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of its regular stock investment and employee benefit plans. As of June 30, 2019, 1,406,178 shares of preferred stock have been converted to 51,282,928 shares of common stock at the option of the holders. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. All remaining outstanding shares of preferred stock will be automatically converted on January 22, 2020.

On March 31, 2018, FirstEnergy’s competitive subsidiary FES and FENOC voluntarily filed petitions under Chapter 11 of the Federal Bankruptcy Code with the U.S. Bankruptcy Court. FirstEnergy and its other subsidiaries - including its Utilities and AE Supply - are not part of the filing and are not subject to the Chapter 11 process. The voluntary bankruptcy filings by the FES Debtors represented a significant event in FirstEnergy’s previously announced strategy to exit the competitive generation business and become a fully regulated utility company with a stronger balance sheet, solid cash flows and more predictable earnings. As a result of the bankruptcy filings, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s financial statements. Additionally, the operating results of the FES Debtors, as well as BSPC and a portion of AE Supply (including the Pleasants Power Station) that were subject to completed or pending asset sales, collectively representing substantially all of FirstEnergy’s operations that comprised the CES reportable segment, are presented as discontinued operations. Prior periods have been reclassified to conform with such presentation as discontinued operations.

41

On April 23, 2018, FirstEnergy and the FES Key Creditor Groups reached an agreement in principle to resolve certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others:

• FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits.

• A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.

• A $225 million cash payment from FirstEnergy.

• A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

• Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred. FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility

• FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

• FirstEnergy has agreed to fund through its pension plan a pension enhancement, which is subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits (approximately $14 million recognized in 2019).

• FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018 (approximately $52 million was paid in 2018, which amount will be finalized after filing the 2018 Federal tax return).

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the FES Bankruptcy settlement agreement. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization and which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement.

In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy.

With the bankruptcy filings of FES and FENOC, and the completed sale of the previously announced competitive Bath hydroelectric station, FirstEnergy’s electric generation fleet is now made up of 3,790 MW of regulated generation, including four plants in West Virginia, Virginia and New Jersey. This excludes AE Supply’s remaining competitive generation assets - the 1,300 MW Pleasants Power Station, which will be transferred to FG pursuant to the settlement agreement, and its 67 MW OVEC capacity entitlement.

42

FINANCIAL OVERVIEW AND RESULTS OF OPERATIONS

(In millions)	For the Three Months Ended June 30,											For the Six Months Ended June 30,
	2019			2018			Change					2019			2018			Change
Revenues	$	2,516		$	2,625		$	(109	)	(4	)%	$	5,399		$	5,487		$	(88	)	(2	)%
Operating expenses	1,931			1,925			6			—	%	4,185			4,207			(22		)	(1	)%
Operating income	585			700			(115		)	(16	)%	1,214			1,280			(66		)	(5	)%
Other expenses, net	(163		)	(291		)	128			(44	)%	(344		)	(457		)	113			(25	)%
Income before income taxes	422			409			13			3	%	870			823			47			6	%
Income taxes	81			101			(20		)	(20	)%	174			334			(160		)	(48	)%
Income from continuing operations	341			308			33			11	%	696			489			207			42	%
Discontinued operations, net of tax	(29		)	(9		)	(20		)	NM		(64		)	1,179			(1,243		)	NM
Net income	$	312		$	299		$	13		4	%	$	632		$	1,668		$	(1,036	)	(62	)%

* NM = not meaningful

The financial results discussed below include revenues and expenses from transactions among FirstEnergy’s business segments. A reconciliation of segment financial results is provided in Note 14, “Segment Information,” of the Notes to Consolidated Financial Statements.

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

43

Summary of Results of Operations — Second Quarter 2019 Compared with Second Quarter 2018

Financial results for FirstEnergy’s business segments in the second quarter of 2019 and 2018 were as follows:

Second Quarter 2019 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	2,131		$	367		$	(32	)	$	2,466
Other	61			5			(16		)	50
Total Revenues	2,192			372			(48		)	2,516
Operating Expenses:
Fuel	129			—			—			129
Purchased power	606			—			5			611
Other operating expenses	630			64			(88		)	606
Provision for depreciation	220			71			18			309
Amortization of regulatory assets, net	34			3			—			37
General taxes	177			52			10			239
Total Operating Expenses	1,796			190			(55		)	1,931
Operating Income	396			182			7			585
Other Income (Expense):
Miscellaneous income, net	46			4			30			80
Interest expense	(124		)	(48		)	(87		)	(259		)
Capitalized financing costs	7			8			1			16
Total Other Expense	(71		)	(36		)	(56		)	(163		)
Income (Loss) Before Income Taxes (Benefits)	325			146			(49		)	422
Income taxes (benefits)	67			30			(16		)	81
Income (Loss) From Continuing Operations	258			116			(33		)	341
Discontinued operations, net of tax	—			—			(29		)	(29		)
Net Income (Loss)	$	258		$	116		$	(62	)	$	312

44

Second Quarter 2018 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	2,291		$	336		$	(56	)	$	2,571
Other	61			5			(12		)	54
Total Revenues	2,352			341			(68		)	2,625
Operating Expenses:
Fuel	128			—			—			128
Purchased power	699			—			(2		)	697
Other operating expenses	666			60			(42		)	684
Provision for depreciation	200			62			21			283
Deferral of regulatory assets, net	(107		)	—			—			(107		)
General taxes	184			48			8			240
Total Operating Expenses	1,770			170			(15		)	1,925
Operating Income (Loss)	582			171			(53		)	700
Other Income (Expense):
Miscellaneous income (expense), net	56			3			(11		)	48
Interest expense	(129		)	(42		)	(184		)	(355		)
Capitalized financing costs	6			10			—			16
Total Other Expense	(67		)	(29		)	(195		)	(291		)
Income (Loss) Before Income Taxes (Benefits)	515			142			(248		)	409
Income taxes (benefits)	138			38			(75		)	101
Income (Loss) From Continuing Operations	377			104			(173		)	308
Discontinued operations, net of tax	—			—			(9		)	(9		)
Net Income (Loss)	$	377		$	104		$	(182	)	$	299

45

Changes Between Second Quarter 2019 and Second Quarter 2018 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	(160	)	$	31		$	24		$	(105	)
Other	—			—			(4		)	(4		)
Total Revenues	(160		)	31			20			(109		)
Operating Expenses:
Fuel	1			—			—			1
Purchased power	(93		)	—			7			(86		)
Other operating expenses	(36		)	4			(46		)	(78		)
Provision for depreciation	20			9			(3		)	26
Amortization (deferral) of regulatory assets, net	141			3			—			144
General taxes	(7		)	4			2			(1		)
Total Operating Expenses	26			20			(40		)	6
Operating Income (Loss)	(186		)	11			60			(115		)
Other Income (Expense):
Miscellaneous income, net	(10		)	1			41			32
Interest expense	5			(6		)	97			96
Capitalized financing costs	1			(2		)	1			—
Total Other Expense	(4		)	(7		)	139			128
Income (Loss) Before Income Taxes (Benefits)	(190		)	4			199			13
Income taxes (benefits)	(71		)	(8		)	59			(20		)
Income (Loss) From Continuing Operations	(119		)	12			140			33
Discontinued operations, net of tax	—			—			(20		)	(20		)
Net Income (Loss)	$	(119	)	$	12		$	120		$	13

46

Regulated Distribution — Second Quarter 2019 Compared with Second Quarter 2018

Regulated Distribution’s operating results decreased $119 million in the second quarter of 2019, as compared to the same period of 2018, primarily reflecting the absence of the reversal of a reserve on recoverability of certain REC purchases in Ohio, the net impact of a FERC settlement that reallocated certain transmission costs, and lower revenues associated with decreased weather-related usage.

Revenues —

The $160 million decrease in total revenues resulted from the following sources:

	For the Three Months Ended June 30,
Revenues by Type of Service	2019		2018		Decrease
	(In millions)
Distribution services(1)	$	1,215	$	1,288	$	(73	)
Generation sales:
Retail	806		882		(76		)
Wholesale	110		121		(11		)
Total generation sales	916		1,003		(87		)
Other	61		61		—
Total Revenues	$	2,192	$	2,352	$	(160	)

⁽¹⁾ Includes $55 million and $60 million of ARP revenues for the three months ended June 30, 2019 and 2018, respectively.

Distribution services revenues decreased $73 million in the second quarter of 2019, as compared to the same period of 2018, primarily resulting from lower weather-related customer usage and the implementation of rate orders and settlements related to the Tax Act. Distribution deliveries by customer class are summarized in the following table:

	For the Three Months Ended June 30,
Electric Distribution MWH Deliveries	2019	2018	Decrease
	(In thousands)
Residential	10,900	12,074	(9.7	)%
Commercial	9,622	10,197	(5.6	)%
Industrial	12,976	13,201	(1.7	)%
Other	138	140	(1.4	)%
Total Electric Distribution MWH Deliveries	33,636	35,612	(5.5	)%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 28% below 2018, and 4% below normal, as well as heating degree days that were 23% below 2018, and 20% below normal. Deliveries to industrial customers reflect higher shale customer usage offset by lower steel and automotive customer usage.

47

The following table summarizes the price and volume factors contributing to the $87 million decrease in generation revenues for the second quarter of 2019, as compared to the same period of 2018:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Change in sales volumes	$	(44	)
Change in prices	(32		)
	(76		)
Wholesale:
Change in sales volumes	(16		)
Change in prices	6
Capacity revenue	(1		)
	(11		)
Decrease in Generation Revenues	$	(87	)

The decrease in retail generation sales volumes was primarily due to lower weather-related usage, as described above. Total generation provided by alternative suppliers as a percentage of total MWH deliveries was flat. The decrease in retail generation prices primarily resulted from a lower ENEC rate in West Virginia and rate reductions resulting from the Tax Act.

Wholesale generation revenues decreased $11 million in the second quarter of 2019, as compared to the same period in 2018, primarily due to lower wholesale sales volumes related to lower generation output. 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.

Operating Expenses —

Total operating expenses increased $26 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to the following:

• Purchased power costs were $93 million lower in the second quarter of 2019, as compared to the same period in 2018, primarily due to lower customer weather-related usage and lower unit costs, partially offset by the implementation of the NJ Zero Emission Program in June 2019.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(46	)
Change due to volumes	(19		)
	(65		)
Purchases from affiliates:
Change due to decreased unit costs	(2		)
Change due to volumes	(27		)
	(29		)
Capacity expense	1
Decrease in Purchased Power Costs	$	(93	)

48

• Other operating expenses decreased $36 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to the following:

• Decreased storm restoration costs of $30 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.

• Lower operating and maintenance expense of $41 million, primarily associated with lower employee benefit and corporate support costs, lower regulated generation maintenance activities and transactions now accounted for as finance leases. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense in 2019.

• Lower energy efficiency program costs of $5 million, which are deferred for future recovery, resulting in no material impact on current period earnings.

• Higher network transmission expenses of $40 million, reflecting increased transmission costs as well as the absence of the FERC settlement during the second quarter of 2018, which reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the Ohio Companies recognized in 2018, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

• Depreciation expense increased $20 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to a higher asset base and transactions now accounted for as finance leases, as discussed above.

• Amortization expense increased $141 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to lower storm restoration cost deferrals, the absence of the reversal of a liability at the Ohio Companies for an Ohio Supreme Court ruling regarding the purchase of RECs that occurred in 2018, as well as lower deferrals of generation and transmission expenses, including the FERC settlement discussed above.

Other Expense —

Other Expense increased $4 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to lower net miscellaneous income resulting from higher pension and OPEB non-service costs. Interest expense decreased due to lower expense from debt maturities and refinancings and higher capitalized financing costs, partially offset by transactions now accounted for as finance leases, as discussed above.

Income Taxes —

Regulated Distribution’s effective tax rate was 20.6% and 26.8% for the three months ended June 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions since June 30, 2018, and the remeasurement of uncertain tax positions during the second quarter of 2019.

Regulated Transmission — Second Quarter 2019 Compared with Second Quarter 2018

Regulated Transmission’s operating results increased $12 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.

Revenues —

Total revenues increased $31 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.

The following table shows revenues by transmission asset owner:

	For the Three Months Ended June 30,				Increase
Revenues by Transmission Asset Owner	2019		2018		(Decrease)
	(In millions)
ATSI	$	185	$	168	$	17
TrAIL	61		65		(4		)
MAIT	51		35		16
Other	75		73		2
Total Revenues	$	372	$	341	$	31

49

Operating Expenses —

Total operating expenses increased $20 million in the second quarter of 2019, as compared to the same period of 2018, primarily due to higher operating and maintenance expenses as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases were recovered through formula rates at ATSI and MAIT, resulting in no material impact on current period earnings.

Income Taxes —

Regulated Transmission’s effective tax rate was 20.5% and 26.8% for the three months ended June 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act occurring since June 30, 2018.

Corporate / Other — Second Quarter 2019 Compared with Second Quarter 2018

Financial results from the Corporate/Other operating segment resulted in a $140 million increase in income from continuing operations in the second quarter of 2019, as compared to the same period of 2018, primarily due to lower interest expense of $97 million from the absence of make-whole payments and higher net miscellaneous income from higher returns on certain equity method investments and lower non-operating expenses.

For the three months ended June 30, 2019 and 2018, FirstEnergy recorded a loss from discontinued operations, net of tax of $29 million and $9 million, respectively. 

50

Summary of Results of Operations — First Six Months of 2019 Compared with First Six Months of 2018

Financial results for FirstEnergy’s business segments in the first six months of 2019 and 2018 were as follows:

First Six Months 2019 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	4,643		$	719		$	(63	)	$	5,299
Other	122			9			(31		)	100
Total Revenues	4,765			728			(94		)	5,399
Operating Expenses:
Fuel	260			—			—			260
Purchased power	1,383			—			9			1,392
Other operating expenses	1,401			130			(146		)	1,385
Provision for depreciation	429			140			37			606
Amortization of regulatory assets, net	37			5			—			42
General taxes	375			103			22			500
Total Operating Expenses	3,885			378			(78		)	4,185
Operating Income (Loss)	880			350			(16		)	1,214
Other Income (Expense):
Miscellaneous income, net	92			8			34			134
Interest expense	(246		)	(93		)	(173		)	(512		)
Capitalized financing costs	17			16			1			34
Total Other Expense	(137		)	(69		)	(138		)	(344		)
Income (Loss) Before Income Taxes (Benefits)	743			281			(154		)	870
Income taxes (benefits)	156			61			(43		)	174
Income (Loss) From Continuing Operations	587			220			(111		)	696
Discontinued operations, net of tax	—			—			(64		)	(64		)
Net Income (Loss)	$	587		$	220		$	(175	)	$	632

51

First Six Months 2018 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	4,799		$	655		$	(77	)	$	5,377
Other	129			9			(28		)	110
Total Revenues	4,928			664			(105		)	5,487
Operating Expenses:
Fuel	267			—			—			267
Purchased power	1,518			—			(1		)	1,517
Other operating expenses	1,564			114			(54		)	1,624
Provision for depreciation	396			123			41			560
Amortization (deferral) of regulatory assets, net	(259		)	4			—			(255		)
General taxes	379			95			20			494
Total Operating Expenses	3,865			336			6			4,207
Operating Income (Loss)	1,063			328			(111		)	1,280
Other Income (Expense):
Miscellaneous income (expense), net	112			7			(4		)	115
Interest expense	(257		)	(81		)	(265		)	(603		)
Capitalized financing costs	12			19			—			31
Total Other Expense	(133		)	(55		)	(269		)	(457		)
Income (Loss) Before Income Taxes	930			273			(380		)	823
Income taxes	231			70			33			334
Income (Loss) From Continuing Operations	699			203			(413		)	489
Discontinued operations, net of tax	—			—			1,179			1,179
Net Income	$	699		$	203		$	766		$	1,668

52

Changes Between First Six Months 2019 and First Six Months 2018 Financial Results	Regulated Distribution			Regulated Transmission			Corporate/Other and Reconciling Adjustments			FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	(156	)	$	64		$	14		$	(78	)
Other	(7		)	—			(3		)	(10		)
Total Revenues	(163		)	64			11			(88		)
Operating Expenses:
Fuel	(7		)	—			—			(7		)
Purchased power	(135		)	—			10			(125		)
Other operating expenses	(163		)	16			(92		)	(239		)
Provision for depreciation	33			17			(4		)	46
Amortization (deferral) of regulatory assets, net	296			1			—			297
General taxes	(4		)	8			2			6
Total Operating Expenses	20			42			(84		)	(22		)
Operating Income (Loss)	(183		)	22			95			(66		)
Other Income (Expense):
Miscellaneous income (expense), net	(20		)	1			38			19
Interest expense	11			(12		)	92			91
Capitalized financing costs	5			(3		)	1			3
Total Other Expense	(4		)	(14		)	131			113
Income (Loss) Before Income Taxes (Benefits)	(187		)	8			226			47
Income taxes (benefits)	(75		)	(9		)	(76		)	(160		)
Income (Loss) From Continuing Operations	(112		)	17			302			207
Discontinued operations, net of tax	—			—			(1,243		)	(1,243		)
Net Income (Loss)	$	(112	)	$	17		$	(941	)	$	(1,036	)

53

Regulated Distribution — First Six Months of 2019 Compared with First Six Months of 2018

Regulated Distribution’s net income decreased $112 million in the first six months of 2019, as compared to the same period of 2018, primarily reflecting the absence of the reversal of a reserve on recoverability of certain REC purchases in Ohio, the net impact of a FERC settlement that reallocated certain transmission costs, and lower revenues associated with decreased weather-related usage.

Revenues —

The $163 million decrease in total revenues resulted from the following sources:

	For the Six Months Ended June 30,
Revenues by Type of Service	2019		2018		Decrease
	(In millions)
Distribution services(1)	$	2,563	$	2,633	$	(70	)
Generation sales:
Retail	1,864		1,922		(58		)
Wholesale	216		244		(28		)
Total generation sales	2,080		2,166		(86		)
Other	122		129		(7		)
Total Revenues	$	4,765	$	4,928	$	(163	)

⁽¹⁾ Includes $117 million and $124 million of ARP revenues for the six months ended June 30, 2019 and 2018, respectively.

Distribution services revenues decreased $70 million in the first six months of 2019, as compared to the same period of 2018, primarily resulting from lower weather-related customer usage and the implementation of rate orders and settlements related to the Tax Act. Distribution deliveries by customer class are summarized in the following table:

	For the Six Months Ended June 30,
Electric Distribution MWH Deliveries	2019	2018	Decrease
	(In thousands)
Residential	26,003	27,073	(4.0	)%
Commercial	20,002	20,723	(3.5	)%
Industrial	26,032	26,275	(0.9	)%
Other	279	281	(0.7	)%
Total Electric Distribution MWH Deliveries	72,316	74,352	(2.7	)%

Lower distribution deliveries to residential and commercial customers primarily reflect lower weather-related usage resulting from cooling degree days that were 28% below 2018, and 4% below normal, as well as, heating degree days that were 3% below 2018, and 4% below normal. Deliveries to industrial customers reflect higher shale customer usage offset by lower steel and automotive customer usage.

54

The following table summarizes the price and volume factors contributing to the $86 million decrease in generation revenues for the first six months of 2019, as compared to the same period of 2018:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Change in sales volumes	$	2
Change in prices	(60		)
	(58		)
Wholesale:
Change in sales volumes	(32		)
Change in prices	(4		)
Capacity Revenue	8
	(28		)
Decrease in Generation Revenues	$	(86	)

The change in retail generation sales volumes was primarily due to lower customer weather-related usage, offset by decreased customer shopping in New Jersey and Pennsylvania. Total generation provided by alternative suppliers as a percentage of total MWH deliveries decreased to 49% from 52% in New Jersey and to 66% from 67% in Pennsylvania. The decrease in retail generation prices primarily resulted from a lower ENEC rate in West Virginia and rate reductions resulting from the Tax Act.

Wholesale generation revenues decreased $28 million in the first six months of 2019, as compared to the same period in 2018, primarily due to lower wholesale sales volumes related to lower generation output. 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.

Operating Expenses —

Total operating expenses increased $20 million, primarily due to the following:

• Fuel costs were $7 million lower during the first six months of 2019, as compared to the same period of 2018, primarily due to lower unit costs.

• Purchased power costs decreased $135 million during the first six months of 2019, as compared to the same period of 2018, primarily due to lower unit costs and lower customer weather-related usage, partially offset by the implementation of the NJ Zero Emission Program in June 2019.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases from non-affiliates:
Change due to decreased unit costs	$	(108	)
Change due to volumes	10
	(98		)
Purchases from affiliates:
Change due to decreased unit costs	(3		)
Change due to volumes	(46		)
	(49		)
Capacity	12
Decrease in Purchased Power Costs	$	(135	)

55

• Other operating expenses decreased $163 million in the first six months of 2019, as compared to the same period of 2018, primarily due to:

• Decreased storm restoration costs of $146 million, which were deferred for future recovery, resulting in no material impact on current period earnings.

• Higher net network transmission expenses of $38 million, reflecting increased transmission costs as well as the absence of the FERC settlement during the second quarter of 2018, which reallocated certain transmission costs across utilities in PJM and resulted in a refund to the Ohio Companies. Except for certain transmission costs and credits at the Ohio Companies recognized in 2018, the difference between current revenues and transmission costs incurred are deferred for future recovery or refund, resulting in no material impact on current period earnings.

• Lower energy efficiency and other program costs of $16 million, which are deferred for future recovery, resulting in no material impact on current period earnings.

• Lower operating and maintenance expenses of $39 million, primarily associated with lower employee benefit and general corporate support costs, lower regulated generation maintenance activities and transactions now accounted for as finance leases. As a result of the adoption of the new lease accounting standard, financing lease expenses that were recognized in other operating expenses are now recognized in depreciation and interest expense in 2019.

• Depreciation expense increased $33 million in the first six months of 2019, as compared to the same period of 2018, primarily due to a higher rate base and transactions now accounted for as finance leases, as discussed above.

• Amortization expense increased $296 million in the first six months of 2019, as compared to the same period of 2018, primarily due to decreased deferral of storm restoration costs, the absence of the reversal of a liability at the Ohio Companies for an Ohio Supreme Court ruling regarding purchase of RECs, as well as lower deferrals of generation and transmission expenses, including the FERC settlement discussed above.

Other Expense —

Total other expense increased $4 million in the first six months of 2019, as compared to the same period of 2018, primarily due lower miscellaneous income due to higher pension and OPEB non-service costs. Interest expense decreased primarily due to lower expense from debt maturities and refinancings, and higher capitalized financing costs, partially offset by transactions now accounted for as finance leases, as discussed above.

Income Taxes —

Regulated Distribution’s effective tax rate was 21.0% and 24.8% for the six months ended June 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from Tax Act settlements and orders with certain regulatory commissions since June 30, 2018, and the remeasurement of uncertain tax positions during the second quarter of 2019.

Regulated Transmission — First Six Months of 2019 Compared with First Six Months of 2018

Regulated Transmission’s net income increased $17 million in the first six months of 2019, as compared to the same period of 2018, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.

Revenues —

Total revenues increased $64 million, primarily due to the recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by a lower rate base at TrAIL.

The following table shows revenues by transmission asset owner:

	For the Six Months Ended June 30,
Revenues by Transmission Asset Owner	2019		2018		Increase (Decrease)
	(In millions)
ATSI	$	360	$	327	$	33
TrAIL	121		127		(6		)
MAIT	101		66		35
Other	146		144		2
Total Revenues	$	728	$	664	$	64

56

Operating Expenses —

Total operating expenses increased $42 million in the first six months of 2019, as compared to the same period of 2018, primarily due to higher operating and maintenance expenses as well as higher property taxes and depreciation due to a higher asset base. The majority of the increases were recovered through formula rates at ATSI and MAIT, resulting in no material impact on current period earnings.

Other Expense —

Total other expense increased $14 million in the first six months of 2019, as compared to the same period of 2018, primarily due to higher interest expense associated with new debt issuances at MAIT and FET.

Income Taxes —

Regulated Transmission’s effective tax rate was 21.7% and 25.6% for the six months ended June 30, 2019 and 2018, respectively. The lower effective tax rate in 2019 was primarily due to the amortization of net excess deferred income taxes resulting from FERC guidance related to the Tax Act occurring since June 30, 2018.

Corporate / Other — First Six Months of 2019 Compared with First Six Months of 2018

Financial results from the Corporate/Other operating segment and reconciling adjustments resulted in a $302 million increase in income from continuing operations in the first six months of 2019, as compared to the same period of 2018, primarily due to lower income taxes from the absence of a $126 million charge in the first quarter of 2018 associated with the remeasurement of state deferred taxes in West Virginia when FES and FENOC were removed from the unitary group following their bankruptcy filing on March 31, 2018. Lower interest expense of $92 million was due to the absence of make-whole payments, and lower other operating expenses of $92 million was primarily due to lower incurred corporate support costs in continuing operations related to FES and FENOC. Although the operations of FES and FENOC for the first quarter of 2018 (prior to deconsolidation on March 31, 2018) are reflected as discontinued operations, certain allocated corporate support costs to FES and FENOC continue to be reflected in continued operations. Additionally, higher net miscellaneous income was primarily due to higher returns on certain equity method investments and lower non-operating expenses.

For the six months ended June 30, 2019, FirstEnergy recorded a loss from discontinued operations, net of tax of $64 million compared to income of $1,179 million, for the six months ended June 30, 2018. The change in discontinued operations, net of tax was primarily due to the absence of a $1.2 billion gain on deconsolidation of FES and FENOC recorded in the first quarter of 2018 following their bankruptcy filing on March 31, 2018.

Regulatory Assets and Liabilities

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, the Utilities and the Transmission Companies net their regulatory assets and liabilities based on federal and state jurisdictions.

The following table provides information about the composition of net regulatory assets and liabilities as of June 30, 2019, and December 31, 2018, and the changes during the six months ended June 30, 2019:

Net Regulatory Assets (Liabilities) by Source	June 30, 2019			December 31, 2018			Change
	(In millions)
Regulatory transition costs	$	(11	)	$	49		$	(60	)
Customer payables for future income taxes	(2,708		)	(2,725		)	17
Nuclear decommissioning and spent fuel disposal costs	(194		)	(148		)	(46		)
Asset removal costs	(770		)	(787		)	17
Deferred transmission costs	167			170			(3		)
Deferred generation costs	197			202			(5		)
Deferred distribution costs	182			208			(26		)
Contract valuations	62			62			—
Storm-related costs	537			500			37
Other	48			62			(14		)
Net Regulatory Liabilities included on the Consolidated Balance Sheets	$	(2,490	)	$	(2,407	)	$	(83	)

57

The following is a description of the regulatory assets and liabilities described above:

Regulatory transition costs - Includes the recovery of PN above-market NUG costs; JCP&L costs incurred during the transition to a competitive retail market and under-recovered during the period from August 1, 1999 through July 31, 2003; and JCP&L costs associated with basic generation service, capacity and ancillary services, net of revenues from the sale of the committed supply in the wholesale market. Amounts are amortized through 2021.

Customer payables for future income taxes - Reflects amounts to be recovered or refunded through future rates to pay income taxes that become payable when rate revenue is provided to recover items such as AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes such as tax reform. These amounts are being amortized over the period in which the related deferred tax assets reverse, which is generally over the expected life of the underlying asset.

Nuclear decommissioning and spent fuel disposal costs - Reflects a regulatory liability representing amounts collected from customers and placed in external trusts including income, losses and changes in fair value thereon (as well as accretion of the related ARO) primarily for the future decommissioning of TMI-2.

Asset removal costs - Primarily represents the rates charged to customers that include a provision for the cost of future activities to remove assets, including obligations for which an ARO has been recognized, that are expected to be incurred at the time of retirement.

Deferred transmission costs - Principally represents differences between revenues earned based on actual costs for the formula-rate Transmission Companies and the amounts billed. Amounts are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.

Deferred generation costs - Primarily relates to regulatory assets associated with the securitized recovery of certain electric customer heating discounts, fuel and purchased power regulatory assets at the Ohio Companies (amortized through 2034) as well as the ENEC at MP and PE. 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. The ENEC rate is updated annually.

Deferred distribution costs - Primarily relates to the Ohio Companies’ deferral of certain expenses resulting from distribution and reliability related expenditures, including interest, and are amortized through 2036.

Contract valuations - Includes the changes in fair value of PN above-market NUG costs and the amortization of a PE purchase accounting adjustment which was recorded in connection with the AE merger representing the fair value of NUG purchased power contracts (amortized over the life of the contracts with various end dates from 2027 through 2036).

Storm-related costs - Relates to the recovery of storm costs, which vary by jurisdiction. Approximately $231 million and $232 million are currently being recovered through rates as of June 30, 2019 and December 31, 2018, respectively.

The following table provides information about the composition of net regulatory assets that do not earn a current return as of June 30, 2019 and December 31, 2018, a majority of which are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Additionally, certain regulatory assets, totaling approximately $109 million as of June 30, 2019, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order.

Regulatory Assets by Source Not Earning a Current Return	June 30, 2019		December 31, 2018		Change
	(In millions)
Regulatory transition costs	$	11	$	10	$	1
Deferred transmission costs	40		87		(47		)
Storm-related costs	423		363		60
Other	42		43		(1		)
Regulatory Assets Not Earning a Current Return	$	516	$	503	$	13

CAPITAL RESOURCES AND LIQUIDITY

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.

58

On January 22, 2018, FirstEnergy announced a $2.5 billion equity issuance, which included $1.62 billion in mandatorily convertible preferred equity with an initial conversion price of $27.42 per share and $850 million of common equity issued at $28.22 per share. The shares of preferred stock participate in the dividend paid on common stock on an as-converted basis and are non-voting except in certain limited circumstances. The shares of preferred stock contain an optional conversion right, requiring mandatory conversion in July 2019, subject to certain exceptions noted below. Proceeds from the investment were used to reduce holding company debt by $1.45 billion and fund FirstEnergy’s pension plan as discussed below, with the remainder used for general corporate purposes. At the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019. As of June 30, 2019, 1,406,178 shares of preferred stock have been converted into 51,282,928 shares of common stock at the option of the preferred stockholders, resulting in 209,822 preferred shares outstanding and yet to be converted. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. All remaining outstanding shares of preferred stock will be automatically converted on January 22, 2020.

The equity investment strengthened FirstEnergy’s balance sheet and supports the company’s transition to a fully regulated utility company. By deleveraging the company, the investment also enables FirstEnergy to enhance its investment grade credit metrics and FirstEnergy does not currently anticipate the need to issue additional equity through at least 2021 outside of its regular stock investment and employee benefit plans.

In addition to this equity investment, FE and its distribution and transmission subsidiaries expect their existing sources of liquidity to remain sufficient to meet their respective anticipated obligations. In addition to internal sources to fund liquidity and capital requirements for 2019 and beyond, FE and its distribution and transmission subsidiaries expect 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 by certain distribution and transmission subsidiaries to, among other things, fund capital expenditures and refinance short-term and maturing long-term debt, subject to market conditions and other factors.

On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021.

FirstEnergy’s transmission growth program, Energizing the Future, provides a stable and proven investment platform, while producing important customer benefits. Through the program, $4.4 billion in capital investments were made from 2014 through 2017, and the company plans to invest up to an additional $4.8 billion in the 2018-2021 time frame, which includes a target of $1.2 billion annually through 2021. As noted above, over 80% of these capital investments are recoverable through formula rate mechanisms, reducing regulatory lag in recovering a return on investment, while offering a reasonable rate of return. These investments are expected to continue to improve the performance and condition of the transmission system while increasing automation and communication, adding capacity to the system and improving customer reliability. Beyond 2021, FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion, which are expected to strengthen grid and cyber-security and make the transmission system more reliable, robust, secure and resistant to extreme weather events, with improved operational flexibility.

In the Regulated Distribution segment, FirstEnergy remains committed to providing customer service-oriented growth opportunities by investing between $6.2 billion and $6.7 billion over 2018 to 2021. Approximately 40% of capital expenditures are recoverable through various rate mechanisms, riders and trackers. Beginning in 2019, expected investments at the Ohio Companies include the pending Ohio Grid Modernization plan which includes installation of approximately 700,000 advanced meters, distribution automation, and integrated ‘volt/var’ controls. Additionally, the JCP&L Reliability Plus infrastructure improvement plan will reduce outages and strengthen the system while preparing for the grid of the future in New Jersey. FirstEnergy continues to explore other opportunities for growth in its Regulated Distribution business, including investments in electric system improvement and modernization projects to increase reliability and improve service to customers, as well as exploring opportunities in customer engagement that focus on electrification of customers’ homes and businesses by providing a full range of products and services.

In alignment with FirstEnergy’s strategy to invest in its Regulated Transmission and Regulated Distribution segments as a fully regulated company, FirstEnergy is also focused on improving the balance sheet over time consistent with its business profile and maintaining investment grade ratings at its regulated businesses and FE. Specifically, at the regulated businesses, regulatory authority has been obtained for various regulated distribution and transmission subsidiaries to issue and/or refinance debt.

Any financing plans by FE or any of its consolidated subsidiaries, including the issuance of equity and debt, and the refinancing of short-term and maturing long-term debt are subject to market conditions and other factors. No assurance can be given that any such issuances, financing or refinancing, as the case may be, will be completed as anticipated or at all. Any delay in the completion of financing plans could require FE or any of its consolidated subsidiaries to utilize short-term borrowing capacity, which could impact available liquidity. In addition, FE and its consolidated subsidiaries expect to continually evaluate any planned financings, which may result in changes from time to time.

On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under

59

the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility.

On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy and would result in the cash payment upon emergence, note issuance and other terms as discussed in the Executive Summary.

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the FES Bankruptcy settlement agreement. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

As of June 30, 2019, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to short-term borrowings of $1,250 million, currently payable long-term debt of $381 million, and other current liabilities of $840 million primarily attributable to interest, customer deposits and anticipated payments under the FES Bankruptcy settlement. Currently payable long-term debt as of June 30, 2019, consisted of the following:

Currently Payable Long-Term Debt	(In millions)
Unsecured notes	$	250
Secured notes	50
Sinking fund requirements	64
Other notes	17
	$	381

FirstEnergy believes its cash from operations and available liquidity will be sufficient to meet its working capital needs.

Short-Term Borrowings / Revolving Credit Facilities

FE and the Utilities and FET and certain of its subsidiaries participate in two separate five-year syndicated revolving credit facilities providing for aggregate commitments of $3.5 billion (Facilities), which are available until December 6, 2022. Under the FE Facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the FET Facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FE’s transmission subsidiaries.

Borrowings under their Facilities may be used for working capital and other general corporate purposes, including intercompany loans and advances by a borrower to any of its subsidiaries. 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) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

FirstEnergy had $1,250 million of short-term borrowings as of both June 30, 2019 and December 31, 2018. FirstEnergy’s available liquidity from external sources as of July 22, 2019, was as follows:

Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	December 2022	$	2,500	$	2,491
FET(2)	Revolving	December 2022	1,000		1,000
		Subtotal	$	3,500	$	3,491
	Cash and cash equivalents		—		278
		Total	$	3,500	$	3,769

⁽¹⁾  FE and the Utilities. Available liquidity includes impact of $9 million of LOCs issued under various terms.

⁽²⁾  Includes FET and the Transmission Companies.

60

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 June 30, 2019:

Borrower	FirstEnergy Revolving Credit Facility Sub-Limit			FET Revolving Credit Facility Sub-Limit			Regulatory and Other Short-Term Debt Limitations
	(In millions)
FE		$	2,500		$	—		$	—	(1)
FET		—			1,000			—		(1)
OE		500			—			500		(2)
CEI		500			—			500		(2)
TE		300			—			300		(2)
JCP&L		500			—			500		(2)
ME		500			—			500		(2)
PN		300			—			300		(2)
WP		200			—			200		(2)
MP		500			—			500		(2)
PE		150			—			150		(2)
ATSI		—			500			500		(2)
Penn		100			—			100		(2)
TrAIL		—			400			400		(2)
MAIT		—			400			400		(2)

⁽¹⁾  No limitations.

⁽²⁾  Includes amounts which may be borrowed under the regulated companies’ money pool.

$250 million of the FE Facility and $100 million of the FET Facility, subject to each borrower’s sub-limit, is available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit.

The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the Facilities is related to the credit ratings of the company borrowing the funds, 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 June 30, 2019, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE’s upgrade to an investment grade credit rating.

Term Loans

FE participates in two separate syndicated term loan credit facilities, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively. The term loans contain covenants and other terms and conditions substantially similar to those of the FE revolving credit facility described above, including a consolidated debt-to-total-capitalization ratio.

The initial borrowing of $1.75 billion under the new term loans, 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. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively.

61

FirstEnergy Money Pools

FirstEnergy’s utility operating subsidiary companies also have the ability to borrow from each other and FE to meet their short-term working capital requirements. Similar but separate arrangements exist among FirstEnergy’s unregulated companies with AE Supply, FE, FET, FEV and certain other unregulated subsidiaries. FESC administers these money pools and tracks surplus funds of FE and the respective regulated and unregulated subsidiaries, as the case may be, as well as proceeds available from bank borrowings. Companies receiving a loan under the money pool agreements must repay the principal amount of the loan, together with accrued interest, within 364 days of borrowing the funds. The rate of interest is the same for each company receiving a loan from their respective pool and is based on the average cost of funds available through the pool. The average interest rate for borrowings in the first six months of 2019 was 2.54% per annum for the regulated companies’ money pool and 3.04% per annum for the unregulated companies’ money pool.

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 July 23, 2019:

	Senior Secured			Senior Unsecured
Issuer	S&P	Moody’s	Fitch	S&P	Moody’s	Fitch
FE	—	—	—	BBB-	Baa3	BBB-
ATSI	—	—	—	BBB	A3	BBB+
CEI	A-	A3	A-	BBB	Baa2	BBB+
FET	—	—	—	BBB-	Baa2	BBB-
JCP&L	—	—	—	BBB	Baa1	BBB+
ME	—	—	—	BBB	A3	BBB+
MAIT	—	—	—	BBB	A3	BBB+
MP	A-	A3	A-	BBB	Baa2	—
OE	A-	A1	A-	BBB	A3	BBB+
PN	—	—	—	BBB	Baa1	BBB+
Penn	—	A1	A-	—	—	—
PE	—	—	A-	—	—	—
TE	A-	A2	A-	—	—	—
TrAIL	—	—	—	BBB	A3	BBB+
WP	—	—	A-	—	—	—

On July 23, 2019, Moody’s upgraded the issuer ratings of OE and Penn to A3 from Baa1, TE to Baa1 from Baa3, and CEI to Baa2 from Baa3. The secured ratings for OE and Penn were changed to A1 from A2, TE to A2 from Baa1, and CEI to A3 from Baa1. The rating outlook for OE remains positive, Penn was revised to positive, and TE and CEI were revised to stable.

Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of June 30, 2019, FE and its subsidiaries could issue additional debt of approximately $8.6 billion, or incur a $4.6 billion reduction to equity, and remain within the limitations of the financial covenants required by the FE Facility.

Changes in Cash Position

As of June 30, 2019, FirstEnergy had $422 million of cash and cash equivalents and approximately $52 million of restricted cash compared to $367 million of cash and cash equivalents and approximately $62 million of restricted cash as of December 31, 2018, 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 distribution and transmission operating subsidiaries. The most significant use of cash from operating activities is buying electricity to serve non-shopping customers and paying fuel suppliers, employees, tax authorities, lenders and others for a wide range of materials and services.

62

FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the six months ended June 30, 2019 and 2018:

	For the Six Months Ended June 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	$	(64	)	$	1,179
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs	—			80
Unrealized gain on derivative transactions	—			(10		)

Net cash provided from operating activities was $625 million during the first six months of 2019, compared to $288 million used for operating activities during the same period of 2018. Key changes were as follows:

• a $750 million decrease in cash contributions to the qualified pension plan;

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

• lower storm costs; partially offset by

• the absence of FES’ cash from operations from the first quarter of 2018;

• a decline in working capital primarily due to the timing of payments to vendors.

Cash Flows From Financing Activities

In the first six months of 2019, cash provided from financing activities was $756 million, compared to $1,534 million in the same period of 2018. The following table summarizes new equity and debt financing, redemptions, repayments, make-whole premiums paid on debt redemptions, short-term borrowings and dividends:

	For the Six Months Ended June 30,
Securities Issued or Redeemed / Repaid	2019			2018
	(In millions)
New Issues
Unsecured notes	$	1,850		$	450
FMBs	100			—
	$	1,950		$	450
Preferred stock issuance	$	—		$	1,616
Common stock issuance	$	—		$	850
Redemptions / Repayments
Unsecured notes	$	(725	)	$	(555	)
Term Loan	—			(1,450		)
Pollution Control Revenue Bonds	—			(216		)
Senior secured notes	(32		)	(30		)
	$	(757	)	$	(2,251	)
Make-whole premiums paid on debt redemptions	$	—		$	(89	)
Short-term borrowings, net	$	—		$	1,364
Preferred stock dividend payments	$	(6	)	$	(42	)
Common stock dividend payments	$	(403	)	$	(343	)

On January 10, 2019, ME issued $500 million of 4.30% senior notes due 2029. Proceeds from the issuance of senior notes were primarily used to refinance existing indebtedness, including ME’s $300 million of 7.70% senior notes due 2019, and borrowings

63

outstanding under the FE regulated utility money pool and the FE Facility, to fund capital expenditures, and for other general corporate purposes.

On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were primarily used to refinance existing indebtedness, including amounts under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L’s $300 million of 7.35% senior notes due 2019 and the funding of storm recovery and restoration costs and expenses, to fund capital expenditures and working capital requirements and for other general corporate purposes.

On March 28, 2019, FET issued $500 million of 4.55% senior notes due 2049. Proceeds from the issuance of the senior notes were used primarily to support FET’s capital structure, to repay short-term borrowings outstanding under the FE unregulated money pool, to finance capital improvements, and for other general corporate purposes, including funding working capital needs and day-to-day operations.

On April 15, 2019, ATSI issued $100 million of 4.38% senior notes due 2031. Proceeds from the issuance of the senior notes were used primarily to repay short-term borrowings, to fund capital expenditures and working capital needs, and for other general corporate purposes.

On May 9, 2019, WP agreed to sell $250 million of new 4.22% FMBs due 2059. On May 21, 2019, WP issued $100 million of 4.22% FMBs due 2059. The remaining sale is expected to settle on August 15, 2019. Proceeds from the issuance of the FMBs were or are, as the case may be, used to refinance existing indebtedness, to fund capital expenditures, and for other general corporate purposes.

On June 3, 2019, PN issued $300 million of 3.60% senior notes due 2029. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts outstanding under the FE regulated companies’ money pool incurred in connection with the repayment at maturity of PN’s $125 million of 6.63% senior notes due 2019, to fund capital expenditures, and for other general corporate purposes.

On June 5, 2019, AGC issued $50 million of 4.47% senior unsecured notes due 2029. Proceeds from the issuance of the senior notes were used to improve liquidity, re-establish the debt component within its capital structure following the recent redemption of all of its existing long-term debt, and satisfy working capital requirements and other general corporate purposes. 

Cash Flows From Investing Activities

Cash used for investing activities in the first six months of 2019 principally represented cash used for property additions. The following table summarizes investing activities for the first six months of 2019 and 2018:

	For the Six Months Ended June 30,						Increase
Cash Used for Investing Activities(1)	2019			2018			(Decrease)
	(In millions)
Property Additions:
Regulated Distribution	$	672		$	655		$	17
Regulated Transmission	531			574			(43		)
Corporate / Other	25			78			(53		)
Proceeds from asset sales	(12		)	(390		)	378
Investments	20			33			(13		)
Notes receivable from affiliated companies	—			500			(500		)
Asset removal costs	103			118			(15		)
Other	(3		)	(3		)	—
	$	1,336		$	1,565		$	(229	)

⁽¹⁾ See Note 3, “Discontinued Operations,” for major classes of discontinued operations for cash used for investing activities.

Cash used for investing activities for the first six months of 2019 decreased $229 million, compared to the same period of 2018, primarily due to the absence of FES’ borrowings from the committed line of credit available under the secured credit facility with FE during the first quarter of 2018, lower property additions and asset removal costs, partially offset by lower proceeds from asset sales.

64

The decrease in property additions was due to the following:

• a decrease of $43 million at Regulated Transmission due to timing of capital investments associated with its Energizing the Future investment program;

• a decrease of $53 million at Corporate/Other due to lower competitive generation related investments; partially offset by

• an increase of $17 million at Regulated Distribution due to investments in electric system improvements and modernization projects to increase reliability.

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 June 30, 2019, was approximately $1.7 billion, as summarized below:

Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FE’s Guarantees on Behalf of FES and FENOC
Energy and Energy-Related Contracts(1)	$	5
Surety Bonds - FG(2)	200
Deferred compensation arrangements	145
	350
FE’s Guarantees on Behalf of its Consolidated Subsidiaries
AE Supply asset sales(3)	555
Deferred compensation arrangements	424
Fuel related contracts and other	20
	999
FE’s Guarantees on Behalf of Business Ventures
Global Holding Facility	180
Other Assurances
Surety Bonds	131
LOCs(4)	9
	140
Total Guarantees and Other Assurances	$	1,669

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

⁽²⁾  FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

⁽³⁾  As a condition to closing AE Supply’s sale of four natural gas generating plants in December 2017, FE provided the purchaser two limited three-year guarantees totaling $555 million of certain obligations of AE Supply and AGC. In connection with the FES Bankruptcy settlement agreement, FirstEnergy has also committed to provide additional guarantees to FG for certain retained environmental liabilities of AE Supply related to the Pleasants Power Station and the McElroy’s Run CCR disposal facility.

⁽⁴⁾  Includes $9 million issued for various terms pursuant to LOC capacity available under FirstEnergy’s revolving credit facilities.

Collateral and Contingent-Related Features

Certain bilateral agreements 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 ratings 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 entered into by FE and its subsidiaries have margining provisions that require posting of collateral. The Utilities have posted collateral totaling $2 million.

65

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. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2019:

Potential Collateral Obligations		AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating		$	1	$	—	$	—	$	1
Upon Further Downgrade		—		43		—		43
Surety Bonds (Collateralized Amount)(1)		1		59		246		306
Total Exposure from Contractual Obligations		$	2	$	102	$	246	$	350

⁽¹⁾  Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

Other Commitments and Contingencies

FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global Holding’s outstanding principal balance is $180 million as of June 30, 2019. 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 respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral.

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 has limited exposure 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.

The valuation of derivative contracts is based on observable market information. As of June 30, 2019, FirstEnergy has a net liability of $33 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.

Equity Price Risk

As of June 30, 2019, the FirstEnergy pension plan assets were allocated approximately as follows: 37% in equity securities, 36% in fixed income securities, 10% in absolute return strategies, 8% in real estate, 2% in private equity, 5% in derivatives and 2% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021. See Note 5, “Pension and Other Postemployment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans. Through June 30, 2019, FirstEnergy’s pension plan assets have earned approximately 13.7% as compared to an annual expected return on plan assets of 7.5%.

As of June 30, 2019, FirstEnergy’s OPEB plans were invested in fixed income and equity securities. Through June 30, 2019, FirstEnergy’s OPEB plans have earned approximately 10.9% as compared to an annual expected return on plan assets of 7.5%.

NDT funds have been established to satisfy JCP&L, ME and PN’s nuclear decommissioning obligations associated with TMI-2. As of June 30, 2019, approximately 54% of the funds were invested in fixed income securities, 45% of the funds were invested in

66

equity securities and 1% 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 $475 million, $393 million and $11 million for fixed income securities, equity securities and short-term investments, respectively, as of June 30, 2019, excluding $16 million of net receivables, payables and accrued income. A hypothetical 10% decrease in prices quoted by stock exchanges would result in a $39 million reduction in fair value as of June 30, 2019. A decline in the value of JCP&L, ME and PN’s NDTs or a significant escalation in estimated decommissioning costs could result in additional funding requirements. During the six months ended June 30, 2019, JCP&L, ME and PN made no contributions to the NDTs.

Interest Rate Risk

FirstEnergy recognizes net actuarial gains or losses for its pension and OPEB plans in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for a remeasurement. 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, 2019.

CREDIT RISK

Credit risk is the risk that FirstEnergy would incur a loss as a result of nonperformance by counterparties of their contractual obligations. FirstEnergy maintains credit policies and procedures with respect to counterparty credit (including requirement that counterparties maintain specified credit ratings) and require other assurances in the form of credit support or collateral in certain circumstance in order to limit counterparty credit risk. However, FirstEnergy, as applicable, has concentrations of suppliers and customers among electric utilities, financial institutions and energy marketing and trading companies. These concentrations may impact FirstEnergy’s overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. In the event an energy supplier of the Ohio Companies, Pennsylvania Companies, JCP&L or PE defaults on its obligation, the affected company would be required to seek replacement power in the market. In general, subject to regulatory review or other processes, appropriate incremental costs incurred by these entities would be recoverable from customers through applicable rate mechanisms, thereby mitigating the financial risk for these entities. FirstEnergy’s credit policies to manage credit risk include the use of an established credit approval process, daily credit mitigation provisions, such as margin, prepayment or collateral requirements. FirstEnergy and its subsidiaries may request additional credit assurance, in certain circumstances, in the event that the counterparties’ credit ratings fall below investment grade, their tangible net worth falls below specified percentages or their exposures exceed an established credit limit.

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 New Jersey by the NJBPU, in Ohio by the PUCO, 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. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also 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 EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE’s 2016 starting goal under this requirement was 0.97%. PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers 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 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed

67

energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.

On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.

NEW JERSEY

JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L 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. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.

In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey.

Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications.

On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.

OHIO

The Ohio Companies currently operate under ESP IV through May 31, 2024. ESP IV includes Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years beginning in 2017, with the possibility of a two-year extension and is grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and

68

2019. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. On February 1, 2019, the Ohio Companies filed with the PUCO an application requesting a two-year extension of Rider DMR at the same amount and conditions.

ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year 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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval, which was filed in February 2016, and remains pending as part of the grid modernization settlement described below; (3) a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers’ base distribution rates, which filing the PUCO denied on June 13, 2018.

Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. The Ohio Companies then filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure, which the PUCO denied. In October 2017, the Sierra Club and the OMAEG filed notices of appeal with the SCOH appealing various PUCO entries on their applications for rehearing. The Ohio Companies intervened in the appeal, and additional parties subsequently filed notices of appeal with the SCOH challenging various PUCO entries on their applications for rehearing. On September 26, 2018, the SCOH denied a July 30, 2018 joint motion filed by the OCC, the NOAC, and the OMAEG to stay the portions of the PUCO’s orders and entries under appeal that authorized Rider DMR. On June 19, 2019, the SCOH reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On July 1, 2019, the Ohio Companies filed a motion with the SCOH requesting reconsideration of the SCOH decision. Also, on July 1, 2019, the Ohio Companies filed revised tariffs with the PUCO providing that while the motion for reconsideration is pending, Rider DMR is being collected subject to refund. On July 2, 2019, the PUCO approved the Ohio Companies’ revised tariffs. On July 11, 2019, various parties filed a memorandum with the SCOH in opposition to the motion for reconsideration.

Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan, as proposed in April 2016, includes 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. In December 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plans with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modifications, which the PUCO denied on January 10, 2018. On March 12, 2018, the Ohio Companies appealed to the SCOH challenging the PUCO’s imposition of a 4% cost cap. Various other parties also appealed challenging various PUCO entries on their applications for rehearing. Oral argument on the appeals was held on February 20, 2019.

On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. Should the Ohio Companies elect to apply to the PUCO for approval of the decoupling mechanism, it would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. FirstEnergy is reviewing the potential impacts to customers and the Ohio Companies, and may seek approval for this mechanism later this year.

On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’

69

electric distribution system, and for all tax savings associated with the Tax Act, discussed below, to flow back to customers. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications.

On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies, effective January 1, 2018, were required to establish a regulatory liability for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. On October 24, 2018, the PUCO entered an Order in its investigation into the impacts of the Tax Act on Ohio’s utilities directing that by January 1, 2019, all Ohio rate-regulated utility companies, unless ordered otherwise, file applications not for an increase in rates to reflect the impact of the Tax Act on each specific utility’s current rates. On October 30, 2018, the Ohio Companies filed an application to open a new proceeding for the implementation of matters relating to the impact of the Tax Act. As discussed further above, on November 9, 2018, the Ohio Companies filed a settlement agreement that provides for all tax savings associated with the Tax Act to flow back to customers and for the implementation of the first phase of grid modernization plans. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On December 19, 2018, the PUCO upheld its January 10, 2018 ruling that utilities should be required to establish a deferred tax liability, effective January 1, 2018, in response to the Tax Act. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The PUCO conducted a hearing on February 5 and 6, 2019. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications.

The Ohio Companies’ Rider NMB is designed to recover non-market-based transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019.

On April 19, 2019, OCC filed an application for rehearing alleging Rider DMR revenues should not have been excluded from the determination of the existence of Significantly Excessive Earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. On May 15, 2019, the PUCO denied OCC’s application for rehearing, and on July 15, 2019, OCC filed a Notice of Appeal with the SCOH. The Ohio Companies intend to contest this appeal but are unable to predict the outcome of this matter.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 must also be separately tracked for treatment in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which 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 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. The PPUC directed a working group to further discuss the implementation of customer assistance program shopping limitations and appropriate scripting for the Pennsylvania Companies’ customer referral programs, and in November 2018, issued a subsequent order to approve additional customer assistance program shopping parameters and further limit the scope of the working group discussion. On December 21, 2018, the PPUC issued a tentative order proposing a model to incorporate the directed shopping restrictions. Comments on the proposal were filed January 22, 2019. On February 28, 2019, the PPUC issued a final order approving the Pennsylvania Companies’ proposal on customer assistance programs shopping limitations and directing script modifications to the Pennsylvania Companies’ customer referral programs. 

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.

70

Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed.

The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018, and remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Pennsylvania Companies are reviewing the Commonwealth Court’s opinion and order.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates under rates approved by the WVPSC effective February 2015. 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.

FERC REGULATORY MATTERS

Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply, AGC, and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to regulation by the relevant state commissions.

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of the facilities that FirstEnergy operates 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 material 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, or obligations to upgrade

71

or build transmission facilities that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 million until 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. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.

FERC Actions on Tax Act

On March 15, 2018, FERC issued a NOI seeking information regarding whether and how FERC should address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.

Transmission ROE Methodology

In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to rely on three financial models-discounted cash flow, capital-asset pricing, and expected earnings to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the NOI comments, and any subsequent rulemaking and other proceedings.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

FirstEnergy complies with SO₂ and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.

CSAPR requires reductions of NOx and SO₂ emissions in two phases (2015 and 2017), ultimately capping SO₂ emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission

72

allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂ emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry’s bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy’s operations, cash flows and financial condition.

In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO₂, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of June 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.

In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility’s NOx emissions significantly contribute to Delaware’s inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland’s inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland’s petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 9 states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018 but has not taken any further action. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

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 GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO₂ emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO₂ emissions by approximately 62 percent. In September 2016, the U.S. 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’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. 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.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” 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 CPP regulations in August 2015 to reduce CO₂ emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO₂ emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. 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. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

73

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 facilities. 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. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.

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 phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. 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 operations may result.

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 CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for 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. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment.

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 of June 30, 2019, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $119 million have been accrued through June 30, 2019. Included in the total are accrued liabilities of approximately $83 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE 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, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of June 30, 2019, JCP&L, ME and PN had in total approximately $863 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN 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.

On May 10, 2019, FirstEnergy signed a non-binding term sheet with EnergySolutions, LLC. concerning the transfer of TMI-2. This transfer of TMI-2 to EnergySolutions, LLC. will also include the transfer of the external trusts for the decommissioning and environmental remediation of TMI-2 and related liabilities of approximately $900 million as of June 30, 2019. The term sheet also contemplates EnergySolutions, LLC. decommissioning of TMI-2. EnergySolutions, LLC. nuclear decommissioning experience includes the nearly completed Zion Nuclear Power Station in Illinois and the La Crosse Boiling Water Reactor in Wisconsin. There can be no assurance that a definitive agreement will be finalized by the parties and subsequently approved by the NRC and, even if approved, whether the conditions to the closing of the transfer will be satisfied.

74

FES Bankruptcy

On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, “Discontinued Operations,” for additional information.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “Regulatory Matters.”

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 FE 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 FE’s or its subsidiaries’ financial condition, results of operations and cash flows.

NEW ACCOUNTING PRONOUNCEMENTS

Recently Adopted Pronouncements

ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires 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, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

75

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

See “FirstEnergy Corp. 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, with the participation of the Chief Executive Officer and Chief Financial Officer, have reviewed and evaluated the effectiveness of its disclosure controls and procedures, as defined under the Securities Exchange Act of 1934, as amended, in 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 FirstEnergy have concluded that its disclosure controls and procedures were effective as of the end of the period covered by this report.

(b) Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2019, there were no changes in internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934) that have materially affected, or are reasonably likely to materially affect, FirstEnergy’s internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1.        LEGAL PROCEEDINGS

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

ITEM 1A.    RISK FACTORS

During the quarter ended June 30, 2019, there were no material changes to the risk factors included in our Annual Report on Form 10-K for the year ended December 31, 2018.

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.

76

ITEM 6.        EXHIBITS

Exhibit Number		Description
(A)	3-1	Amended and Restated Articles of Incorporation of FirstEnergy Corp.
(A)	3-2	Amended and Restated Code of Regulations of FirstEnergy Corp.
(A)	31.1	Certification of chief executive officer, as adopted pursuant to Rule 13a-14(a).
(A)	31.2	Certification of chief financial officer, as adopted pursuant to Rule 13a-14(a).
(A)	32	Certification of chief executive officer and chief financial officer, pursuant to 18 U.S.C. Section 1350.
	101	The following materials from the Quarterly Report on Form 10-Q of FirstEnergy Corp. for the period ended June 30, 2019, formatted in iXBRL (Inline 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.

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

Pursuant to paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K, except as set forth above FirstEnergy has not 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 hereby agrees to furnish to the SEC on request any such documents.

77

SIGNATURES

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

July 23, 2019

FIRSTENERGY CORP.

Registrant

/s/ Jason J. Lisowski

Jason J. Lisowski

Vice President, Controller

and Chief Accounting Officer 

78

EX-3.1

Exhibit 3-1

AMENDED AND RESTATED
ARTICLES OF INCORPORATION
OF
FirstEnergy Corp.

Effective July 16, 2019

ARTICLE I

The name of the corporation is FirstEnergy Corp. (the “Corporation”).

ARTICLE II

The place in the State of Ohio where the Corporation’s principal office is located is the City of Akron, Summit County.

ARTICLE III

The purpose of the Corporation is to engage in any lawful act or activity for which corporations may be formed under Sections 1701.01 to 1701.98, inclusive, of the Ohio Revised Code.

ARTICLE IV

A.Authorized Capital Stock. The Corporation is authorized to issue 705 million shares of capital stock, consisting of five (5) million shares of preferred stock, with par value of $100 per share (“Preferred Stock”), and 700 million shares of common stock, with par value of $0.10 per share (“Common Stock”).

B.Preferred Stock. The Board of Directors shall have authority to issue Preferred Stock from time to time in one or more classes or series. The express terms of shares of a different series of any particular class shall be identical except for such variations as may be permitted by law.

C.Common Stock. Subject to any Preferred Stock Designation (as defined herein), the holders of shares of Common Stock shall be entitled to one vote on each matter submitted to a vote at a meeting of shareholders for each share of Common Stock held of record by such holder as of the record date for such meeting.

D.Convertible Preferred Stock.

1.Designation and Number of Shares. A series of Preferred Stock shall be designated as “Series A Convertible Preferred Stock,” with a par value of $100 per share (the “Convertible Preferred Stock”), and the number of shares so authorized and designated shall be 1,616,000.

1

2.    Ranking. Each share of the Convertible Preferred Stock shall be identical in all respects to every other share of the Convertible Preferred Stock, and shall rank (i) with respect to rights upon liquidation, dissolution or winding-up of the affairs of the Corporation, (A) senior to all classes of the Common Stock and (B) senior to each other class of the Corporation’s capital stock and any other class or series of Preferred Stock established after the Issuance Date (all such shares, collectively, the “Junior Securities”), except for any capital stock or class or series of Preferred Stock designated as Senior Securities or Parity Securities pursuant to Section ‎10‎(b) below (in which case, such Senior Securities or Parity Securities shall rank as so designated) and (ii) with respect to dividend and distribution rights, (A) pari passu to all classes of the Common Stock and (B) senior to the Junior Securities, except for any capital stock or class or series of Preferred Stock designated as Senior Securities or Parity Securities pursuant to Section ‎10‎(b) below (in which case, such Senior Securities or Parity Securities shall rank as so designated). Notwithstanding the seniority of the Convertible Preferred Stock as described in this Section ‎2, the entitlement of a Convertible Preferred Stock holder to participate in any dividend or distribution from the Corporation, including but not limited to, with respect to a Bankruptcy or Liquidation Conversion, shall be to participate with the Common Stock on an as-converted basis as further set forth herein, and in no event shall the right of the Convertible Preferred Stock to so participate be limited or restricted, other than as expressly set forth herein.

3.Dividends and Distributions.

(a)Participation with Common Stock. If and to the extent the Corporation intends to pay any dividend or make a distribution on shares of Common Stock, whether in the form of cash, securities, debt, assets, options, warrants or other rights, but excluding any dividend or distribution payable in shares of Common Stock (which shall result in an adjustment to the Conversion Price as described in Section ‎5‎(e)‎(ii) below), then any such dividend or distribution shall be payable to the holders of shares of Common Stock and Convertible Preferred Stock on a pari passu, pro rata basis (treating each holder of shares of Convertible Preferred Stock as being the holder of the number of shares of Common Stock into which such holder’s shares of Convertible Preferred Stock would be converted if such shares were converted pursuant to the provisions of Section ‎5‎(a) hereof as of the record date for payment of such dividend or distribution). The record date for payment of any dividend or distribution to holders of Convertible Preferred Stock will be the same date as the record date for payment of the dividend or distribution to holders of Common Stock, whether or not such date is a Business Day. The payment date of any dividend or distribution to holders of Convertible Preferred Stock will be the same date on which payment of such dividend or distribution is made to holders of Common Stock (each such date, a “Dividend Payment Date”).

(b)Conversion Prior to or Following a Record Date. If the Conversion Date for any shares of Convertible Preferred Stock is prior to the close of business on the record date for a dividend as provided in paragraph (a) above, the holder of such shares shall not be entitled to any dividend in respect of such record date as a holder of shares of Convertible Preferred Stock (but such holder will be entitled, to the extent it is a holder of shares of Common Stock, to any applicable dividend payable with respect to shares of Common Stock held by it (including any such shares received or to be received as a result of any conversion with respect to a Conversion Date occurring prior to such record date)). If the Conversion Date for any shares of Convertible Preferred Stock

2

is after the close of business on the record date for a dividend as provided in paragraph (a) above but prior to the corresponding Dividend Payment Date, as applicable, the holder of such shares of Convertible Preferred Stock as of the applicable record date shall be entitled to receive such dividend, notwithstanding the conversion of such shares prior to the applicable Dividend Payment Date, as applicable.

4.Transfer. If any shares of Convertible Preferred Stock shall constitute “restricted securities,” as that term is defined in Rule 144 (or any successor rule) promulgated pursuant to the Securities Act, such shares shall be Transferred only pursuant to a registration statement filed with the SEC in accordance with the Securities Act and applicable state securities laws, or an exemption from the requirements of such registration.

5.Conversion Rights.

(a)Conversion Privilege. Following the Six-Month Anniversary Date, a holder shall have the right (the “Conversion Right”), at its option and at any time, and from time to time, to convert each share of Convertible Preferred Stock that it holds into Common Stock. Upon exercise of the Conversion Right as provided in this Section ‎5 (an “Optional Conversion”), the Corporation shall deliver to the holder the number of shares of Common Stock equal to the quotient obtained by dividing (x) the Liquidation Preference by (y) the Conversion Price in effect on the Conversion Date. Immediately following such conversion, the right of the holder, as a holder of the converted Convertible Preferred Stock, shall, except as set forth in Section ‎3‎(b) above, cease, and such holder, or the Person or Persons designated by it as provided in Section ‎5‎(b), shall be treated for all purposes as having become the owner(s) of such Common Stock with respect to the shares of Convertible Preferred Stock that have been converted.

(b)Manner of Conversion. To convert shares of Convertible Preferred Stock pursuant to this Section ‎5, a holder must notify the Corporation at the Corporation’s headquarters in Akron, Ohio or at such other office as the Corporation designates that it elects to convert Convertible Preferred Stock and the number of shares it wishes to convert (a “Conversion Notice”), which Conversion Notice shall be irrevocable and shall also state in writing the name or names in which the holder wishes any certificate or certificates for shares of Common Stock to be issued or otherwise to be recorded on the Common Stock Register. No later than two Business Days after delivering a Conversion Notice, a holder converting Convertible Preferred Stock shall, (A) if the Convertible Preferred Stock is represented by a certificate or certificates, surrender the certificate or certificates evidencing the shares of Convertible Preferred Stock to be converted, duly endorsed in a form satisfactory to the Corporation, at the office of the Corporation or Transfer Agent for the Convertible Preferred Stock and (B) pay any transfer or similar tax required by Section ‎5‎(d) below to be paid by the holder, if any. The Business Day immediately prior to the date on which the holder delivers the Conversion Notice is the “Conversion Date.”

As soon as practical, and in any event within five Business Days following the applicable Conversion Date, (x) if the Common Stock is then represented by certificates, the Corporation shall deliver a certificate for the number of full shares of Common Stock issuable upon the conversion, and otherwise the Corporation shall record such shares on the Common Stock Register, and (y) if the Convertible Preferred Stock is then represented by certificates and the Corporation so elects,

3

the Corporation shall deliver a new certificate representing the unconverted portion, if any, of the shares of Convertible Preferred Stock represented by the certificate or certificates surrendered for conversion, and otherwise the Corporation shall record such shares on the Preferred Stock Register. The Person in whose name the Common Stock certificate is registered, or the Person in whose name the shares of Common Stock are recorded on the Common Stock Register, shall be treated as the stockholder of record on and after the Conversion Date. If a holder of Convertible Preferred Stock converts more than one share at a time, the number of full shares of Common Stock issuable upon conversion shall be based on the total Liquidation Preferences of all shares of Convertible Preferred Stock converted by such holder at such time.

(c)Fractional Shares. The Corporation shall not issue any fractional shares of Common Stock upon conversion of Convertible Preferred Stock. Instead the Corporation shall pay a cash adjustment to the holder of Convertible Preferred Stock being converted based upon the Market Price on the Conversion Date.

(d)Reservation of Shares. The Corporation shall reserve (and shall keep available and free from preemptive rights) and shall continue to reserve out of its authorized but unissued Common Stock or its Common Stock held in treasury a sufficient number of shares of Common Stock to permit the conversion of the Convertible Preferred Stock in full. All shares of Common Stock that may be issued upon conversion of Convertible Preferred Stock shall be fully paid and non-assessable. All shares of Common Stock that are issued upon the conversion of Convertible Preferred Stock shall, upon issuance, be validly issued, not subject to any preemptive rights, and, be free from all taxes, liens, security interests, charges, and other encumbrances with respect to the issuance thereof (collectively, “Encumbrances”), other than taxes in respect of any transfer occurring contemporaneously with such issue and Encumbrances created by the holder.

(e)Specific Adjustments. The Conversion Price shall be subject to adjustment as provided in this Section ‎5‎(e).

(i)Subdivisions and Combinations. In case the outstanding shares of Common Stock shall be subdivided into a greater number of shares of Common Stock or combined into a lesser number of shares of Common Stock, then the Conversion Price in effect at the opening of business on the day following the day upon which such subdivision or combination becomes effective shall be adjusted to equal the product of the Conversion Price in effect on such date and a fraction the numerator of which shall be the number of shares of Common Stock outstanding immediately prior to such subdivision or combination, and the denominator of which shall be the number of shares of Common Stock outstanding immediately after such subdivision or combination. Such adjustment shall become effective retroactively to the close of business on the day upon which such subdivision or combination becomes effective.

(ii)Dividends or Distributions Payable in Common Stock. In case the Corporation shall pay or make a dividend or other distribution on Common Stock payable in shares of Common Stock, the Corporation shall give prompt notice to the holders of the Convertible Preferred Stock of such dividend or distribution, and the Conversion Price in effect at the opening of business on the day following the date fixed for the determination

4

of stockholders entitled to receive such dividend or other distribution shall be reduced by multiplying such Conversion Price by a fraction the numerator of which shall be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination and the denominator of which shall be the sum of such number of shares outstanding at the close of business on the date fixed for such determination and the total number of shares constituting such dividend or other distribution, such reduction to become effective retroactively to a date immediately following the close of business on the record date for the determination of the holders entitled to such dividends and distributions. For the purposes of this Section ‎5‎(e)‎(ii), the number of shares of Common Stock at any time outstanding shall not include shares held in the treasury of the Corporation. The Corporation will not pay any dividend or make any distribution on shares of Common Stock held in the treasury of the Corporation.

(iii)Issuances of Common Stock Below Conversion Price. If, prior to the Eighteen-Month Anniversary Date, the Corporation shall issue or sell Common Stock or Common Stock Equivalents at a price per share less than the Conversion Price in effect on the Issuance Date, the Conversion Price in effect at the opening of business on the day following the date fixed for the determination of such price per share shall be reduced by multiplying such Conversion Price by a fraction (x) the numerator of which shall be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination plus the number of shares of Common Stock which the aggregate of the offering price of the total number of shares of Common Stock so offered for subscription, purchase or acquisition would purchase at the Conversion Price (or, in the case of Common Stock Equivalents, the number of shares of Common Stock which the aggregate consideration received by the Corporation upon the issuance of such Common Stock Equivalents and receivable by the Corporation upon the conversion, exchange or exercise of such Common Stock Equivalents would purchase at the Conversion Price) and (y) the denominator of which shall be the number of shares of Common Stock outstanding at the close of business on the date fixed for such determination plus the number of shares of Common Stock so offered for subscription, purchase or acquisition (or, in the case of Common Stock Equivalents, the maximum number of shares of Common Stock into which such Common Stock Equivalents initially may convert, exchange or be exercised).

Any such change in the Conversion Price shall become effective immediately on the issuance or sale of such Common Stock or Common Stock Equivalents. However, upon the expiration of any Common Stock Equivalent to purchase Common Stock, the issuance of which resulted in an adjustment in the Conversion Price pursuant to this Section ‎5‎(e)‎(iii), if any such Common Stock Equivalent shall expire and shall not have been exercised, the Conversion Price shall be recomputed immediately upon such expiration and effective immediately upon such expiration shall be adjusted to the price it would have been (but reflecting any other adjustments to the Conversion Price made pursuant to the provisions of this Section ‎5 after the issuance of such Common Stock Equivalents) had the adjustment of the Conversion Price made upon the issuance of such Common Stock Equivalents been made on the basis of offering for subscription or purchase only that number of shares of Common Stock actually purchased upon the exercise of such Common Stock Equivalents.

5

No further adjustment shall be made upon exercise of any Common Stock Equivalent if any adjustment shall be made upon the issuance of such security. For the purposes of this Section ‎5‎(e)‎(iii), the number of shares of Common Stock at any time outstanding shall not include shares held in the treasury of the Corporation. The Corporation will not issue any Common Stock Equivalents in respect of shares of Common Stock held in the treasury of the Corporation. In case at any time any shares of Common Stock or Common Stock Equivalents or any rights or options to purchase any shares of Common Stock or Common Stock Equivalents shall be issued or sold for cash, the consideration received therefor shall be deemed to be the amount received by the Corporation therefor, without deduction therefrom of any expenses incurred or any underwriting commissions or concessions or discounts paid or allowed by the Corporation in connection therewith. In case any shares of Common Stock or Common Stock Equivalents or any rights or options to purchase any Common Stock or Common Stock Equivalents shall be issued or sold for a consideration other than cash, the amount of the consideration other than cash received by the Corporation shall be deemed to be the Fair Market Value of such consideration, without deduction therefrom of any expenses incurred or any underwriting commissions or concessions or discounts paid or allowed by the Corporation in connection therewith. This Section ‎5‎(e)‎(iii) shall not apply to issuances of Common Stock or Common Stock Equivalents (i) to employees, directors and consultants of the Corporation, solely in their capacity as such, pursuant to any bona fide stock or option plan authorized by the Board of Directors or a majority of the members of a committee of non-employee directors established for such purpose, provided that in any event, the aggregate amount of shares of (x) Common Stock (which, for the avoidance of doubt, shall not include Common Stock issued as contemplated in the following clause (y)) and (y) Common Stock issuable upon conversion, vesting, exercise and/or settlement (or any similar event) of Common Stock Equivalents, in each case issued pursuant to all such plans, shall not exceed 2.0% of the shares of fully diluted Common Stock outstanding at the time of any such issuance or (ii) pursuant to any bona fide dividend reinvestment plan or share purchase plan or similar plans of the Corporation.

(f)Par Value. No adjustment in the Conversion Price shall reduce the Conversion Price below the then par value of the Common Stock.

(g)Notices.

(i)If: (A) the Corporation takes any action which requires an adjustment in the Conversion Price pursuant to this Section ‎5; or (B) the Corporation undergoes a Fundamental Change, the Corporation shall notify holders of the Convertible Preferred Stock of the proposed record or effective date, as the case may be, at least ten days before such date; provided, however, that the failure to provide such notice or any defect in it shall not affect the validity of any transaction referred to in clause (A) or (B) of this Section ‎5‎(g).

(ii)Whenever the Conversion Price shall be adjusted, the Corporation shall file with the Transfer Agent for the Convertible Preferred Stock, if other than the Corporation, a certificate from the Corporation, duly signed by an authorized officer of the Corporation,

6

briefly stating the facts requiring the adjustment and the manner of computing it, and provide notice to the holders of Convertible Preferred Stock as provided herein.

(iii)Notwithstanding the other provisions of this Section ‎5, no adjustment shall be made to the Conversion Price unless such adjustment would require a change of at least 1% in the Conversion Price then in effect. The Corporation shall carry forward any adjustments that are less than 1% of the Conversion Price and make such carried forward adjustments, regardless of whether the aggregate adjustment is less than 1%, upon an Optional Conversion, a Mandatory Conversion or a Conversion at the Corporation’s Option.

(h)Deferral; Failure to Issue or Rescission. In any case in which this Section ‎5‎ shall require that an adjustment as a result of any event that becomes effective from and after a record date, the Corporation may elect to defer until after the occurrence of such event the issuance to the holder of any shares of Convertible Preferred Stock converted after such record date and before the occurrence of such event of the additional shares of Common Stock issuable upon such conversion over and above the shares issuable on the basis of the Conversion Price in effect immediately prior to adjustment; provided, however, that if such event shall not have occurred and authorization of such event shall be rescinded by the Corporation (including a decision by the Corporation not to issue Common Stock or pay dividends, make distributions, or take other actions contemplated by Section ‎5‎(e), the Conversion Price shall be recomputed immediately upon such rescission to the price that would have been in effect had such event not been authorized with respect to all holders of Convertible Preferred Stock, provided that such rescission or decision is permitted by and effective under applicable laws.

(i)Third-Party Conversion Right. Notwithstanding any temporal limitations on the rights of a holder of Convertible Preferred Stock to exercise its Conversion Right set out in Section ‎5‎‎(a) above, if any holder of Convertible Preferred Stock pledges or otherwise grants a security interest in any of its shares of the Convertible Preferred Stock in connection with such holder’s financing activities (such shares, the “Pledged Convertible Preferred Shares”) to any creditor, lender or other Person performing similar functions in the ordinary course of such creditor’s, lender’s or other Person’s business to which such pledge or other grant of a security interest is made (any of the foregoing, a “Creditor”) and such Creditor has foreclosed on or acquired the beneficial ownership of the Pledged Convertible Preferred Shares by other similar remedy, then such Pledged Convertible Preferred Shares shall become immediately and at all times thereafter convertible into Common Stock, at the election of such Creditor, at the then-applicable Conversion Price.

6.Mandatory Conversion.

(a)Mandatory Conversion on the Eighteen-Month Anniversary Date. Subject to the limitations set forth in Section ‎9, each share of Convertible Preferred Stock, unless previously converted pursuant to Section ‎5, this Section ‎6 or a Conversion at the Corporation’s Option, shall automatically convert (an “Eighteen-Month Conversion”) into a number of shares of Common Stock equal to the quotient obtained by dividing (x) the Liquidation Preference by (y) the Conversion Price as of the Business Day immediately prior to the Eighteen-Month Anniversary Date.

7

(b)Mandatory Conversion on the Two-Year Anniversary Date. Each share of Convertible Preferred Stock, unless previously converted pursuant to Section ‎5, this Section ‎6 or a Conversion at the Corporation’s Option, shall automatically convert (a “Two-Year Conversion”) into a number of shares of Common Stock equal to the quotient obtained by dividing (x) the Liquidation Preference by (y) the Conversion Price as of the Business Day immediately prior to the Two-Year Anniversary Date.

(c)Mandatory Conversion upon Bankruptcy or Liquidation. Each share of Convertible Preferred Stock, unless previously converted pursuant to Section ‎5, this Section ‎6 or a Conversion at the Corporation’s Option, shall automatically convert (a “Bankruptcy or Liquidation Conversion” and, together with an Eighteen-Month Conversion and a Two-Year Conversion, a “Mandatory Conversion”) into a number of shares of Common Stock equal to the quotient obtained by dividing (x) the Liquidation Preference by (y) the Conversion Price as of the Business Day immediately prior to the date of any of the following (each a “Bankruptcy or Liquidation Triggering Event”): (i) the commencement of a voluntary or involuntary case (unless such involuntary case is dismissed prior to the Business Day that is 60 days after its commencement) with respect to the Corporation or any subsidiary holding all or substantially all of the Corporation’s assets (on a consolidated basis) pursuant to or within the meaning of Title 11 of the United States Code, (ii) the appointment of a custodian for all or substantially all of the assets of the Corporation and its subsidiaries, taken as a whole, (iii) a general assignment by the Corporation for the benefit of its creditors and (iv) any other liquidation, dissolution or winding-up of the entirety of the affairs of the Corporation. In no event will the commencement of a voluntary or involuntary case with respect to FirstEnergy Solutions Corp., and/or any of its subsidiaries, and/or FirstEnergy Nuclear Operating Company pursuant to or within the meaning of Title 11 of the United States Code constitute a Bankruptcy or Liquidation Triggering Event. Neither the sale (for cash, shares of stock, securities or other consideration) of all or substantially all of the assets or business of the Corporation (other than in connection with the liquidation, winding-up or dissolution of the Corporation), nor the merger or consolidation of the Corporation into or with any other Person, shall constitute a Bankruptcy or Liquidation Triggering Event.

Any Bankruptcy or Liquidation Conversion shall be deemed to have occurred as of the Business Day after the date of any Bankruptcy or Liquidation Triggering Event, irrespective of the date of the issuance of Common Stock in connection with such Bankruptcy or Liquidation Conversion other than in the case of the commencement of an involuntary case as described in the preceding paragraph, in which case, it will be 60 days after the date of the Bankruptcy or Liquidation Triggering Event.

(d)Issuance of Shares Following Mandatory Conversion. The shares of Common Stock issuable upon a Mandatory Conversion shall be issued on the third Business Day following the Eighteen-Month Anniversary Date, the Two-Year Anniversary Date or the Bankruptcy or Liquidation Triggering Event, as applicable, to the holder of the respective shares of Convertible Preferred Stock on the Eighteen-Month Anniversary Date, the Two-Year Anniversary Date or the Bankruptcy or Liquidation Triggering Event, as applicable, and the Corporation shall issue certificates representing the shares of Common Stock issuable upon such Mandatory Conversion, if the Common Stock is then represented by certificates, or, if the Common Stock is not then

8

represented by certificates, the Corporation shall record the issuance of such Common Stock on the Common Stock Register, in the name of the respective holders of the Convertible Preferred Stock on the date of such Mandatory Conversion.

7.Conversion at the Corporation’s Option.

(a)Corporation’s Option to Cause Conversion. If at any time following the Issuance Date there shall be outstanding fewer than 323,200 shares of Convertible Preferred Stock, the Corporation shall have the right, but not the obligation, as of a subsequent date selected by the Corporation, to cause the conversion of all, but not less than all, of such outstanding shares of Convertible Preferred Stock at the Conversion Price (“Conversion at the Corporation’s Option”). In the event of any Conversion pursuant to this Section ‎7‎(a), the Corporation shall provide written notice to the holders of the Convertible Preferred Stock of the Conversion at least ten days prior to such Conversion at the Corporation’s Option.

(b)Issuance of Shares following Exercise of Corporation’s Option to Cause Conversion. The shares of Common Stock issuable upon a Conversion at the Corporation’s Option shall be issued on the third Business Day following the date of such Conversion at the Corporation’s Option to the holder of the respective shares of Convertible Preferred Stock on the date of such Conversion at the Corporation’s Option, and the Corporation shall issue certificates representing the shares of Common Stock issuable upon such Conversion at the Corporation’s Option, if the Common Stock is then represented by certificates, or, if the Common Stock is not then represented by certificates, the Corporation shall record the issuance of such Common Stock on the Common Stock Register, in the name of the respective holders of the Convertible Preferred Stock on the date of such Conversion at the Corporation’s Option.

8.Fundamental Change. The Corporation shall provide written notice to holders of the Convertible Preferred Stock no less than five Business Days prior to the Corporation undertaking a Fundamental Change, which notice shall provide each such holder the right, upon return instruction to the Corporation (which instruction shall be delivered no later than the third Business Day after a holder is initially notified of a Fundamental Change by the Corporation), to elect to:

(i)exercise its optional Conversion Rights pursuant to Section ‎5‎ hereof prior to the effective time of such Fundamental Change and participate therein on an as-converted basis; or

(ii)provided that the Fundamental Change occurs prior to the Eighteen-Month Anniversary Date, either (A) require the Corporation or any other successor entity to such Fundamental Change to assume and acknowledge the rights and preferences of the Convertible Preferred Stock, in the case of the Corporation, as embodied in this Preferred Stock Designation, and in the case of another successor entity, as embodied in a security with such terms, conditions, rights and privileges as determined by the board of directors (or similar governing body) of such successor entity, acting in good faith, to be as near as possible equivalent to those of the Convertible Preferred Stock and as shall be delivered to each of such holders so electing, or (B) cause the Corporation or its successor to set aside, in a segregated account to be held in trust for the benefit of the holders of the Convertible

9

Preferred Stock so electing, an amount (in cash, securities, or other value, and in each case in the same form as provided to holders of Common Stock in connection with such Fundamental Change) of the consideration that such holders would have received had they elected to exercise their conversion right under Section ‎8‎(i) above. The holders of Convertible Preferred Stock so electing pursuant to clause (B) above shall be entitled to receive their pro-rata portion of such consideration at any time following the Fundamental Change, provided that, on the Two-Year Anniversary Date, the Corporation (or its successor) shall distribute all consideration then remaining pro rata to the holders entitled thereto.

9.Limitations on Common Stock Issuable Upon Conversion.

(a)Conversion Limitation. Notwithstanding anything herein to the contrary, no conversion of a share of Convertible Preferred Stock pursuant to Section ‎5, Section ‎6‎(a) or Section ‎7 hereof shall be permitted if such conversion would result in a converting holder, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Securities Exchange Act of 1934, beneficially owning (as defined under Rule 13d‑3 under the Securities Exchange Act of 1934, or any successor provision) more than 4.90% of the issued and outstanding Common Stock. Any attempted conversion in violation of this Section ‎9 shall be void ab initio and of no force and effect.

(b)Common Stock Conversion Limitation. In no event shall the Corporation issue more than 58,964,222 shares of Common Stock in the aggregate (the “Share Cap”) upon conversion of Convertible Preferred Stock. The Share Cap shall be subject to equitable adjustment in a manner not adverse to the holders of Convertible Preferred Stock if and whenever there shall occur a stock split, combination, reclassification or other similar event involving the Common Stock. From and after the time at which the aggregate number of shares of Common Stock issued upon conversion of the Convertible Preferred Stock equals the Share Cap, each holder electing to convert or subject to Mandatory Conversion of Convertible Preferred Stock shall be entitled to receive from the Corporation a cash payment (a “Make-Whole Payment”) equal to the product of (x) the Current Market Price of the Common Stock on the applicable Conversion Date times (y) the number of shares of Common Stock that such holder would have been entitled to receive had such Convertible Preferred Stock been converted. To the extent that multiple holders of Convertible Preferred Stock elect or are subject to conversion on the same Conversion Date in respect of which a Make-Whole Payment may be required hereunder, any allocation between Make-Whole Payments and Common Stock issuable upon conversion shall be made ratably among such holders. The Corporation shall (A) pay any Make-Whole Payment owing to a holder of Convertible Preferred Stock on the same day it delivers or would otherwise be required to deliver Common Stock to such holder in connection with the related conversion and (B) in the event that the Corporation has issued a number of shares of Common Stock upon conversion of the Convertible Preferred Stock equal to the Share Cap (the date such Share Cap is reached, the “Share Cap Date”), promptly thereafter give all holders of Convertible Preferred Stock of record as of the Share Cap Date written notice that the Corporation has issued, upon conversion of Convertible Preferred Stock, an amount of Common Stock that is equal to the Share Cap.

10

10.Voting Rights.

(a)General. The holders of Convertible Preferred Stock shall have no voting rights, except as set forth below or as otherwise required by applicable law.

(b)Class Voting. So long as any shares of Convertible Preferred Stock are outstanding, the Corporation shall not, either directly or indirectly, by amendment or merger or otherwise, do any of the following without (in addition to any other vote required by law or the Amended Articles of Incorporation) the affirmative vote or consent of the Requisite Holders voting as a separate class, given in person or by proxy, either in writing by consent or by resolution adopted at an annual or special meeting and any act or transaction entered into without such vote or consent shall be void ab initio and of no force and effect:

(i)authorize or create any class or series of Senior Securities or Parity Securities or any obligation or security convertible or exchangeable into or evidencing the right to purchase, shares of any class or series of Parity Securities or Senior Securities;

(ii)reclassify, alter or amend any authorized Parity Securities, Senior Securities or Junior Securities, if such reclassification, alteration or amendment would render such other security on a parity with or senior to (or, in the case of Parity Securities or Senior Securities, pari passu with or senior in additional respects to) the Convertible Preferred Stock;

(iii)(A) issue any shares of Convertible Preferred Stock other than the Convertible Preferred Stock issued on the Issuance Date (including any such additional shares of Convertible Preferred Stock that the Corporation is obligated to reallocate in connection with the transactions occurring on the Issuance Date) or (B) amend or alter the Amended Articles of Incorporation or this Amendment to increase the authorized amount of Convertible Preferred Stock; or

(iv)issue any securities convertible into or exchangeable for Common Stock other than (A) to employees, directors and consultants of the Corporation, solely in their capacity as such, pursuant to any bona fide stock or option plan authorized by the Board of Directors or a majority of the members of a committee of non-employee directors established for such purpose or (B) pursuant to any bona fide dividend reinvestment plan or share purchase plan or similar plans of the Corporation.

11.Amendment. So long as any shares of Convertible Preferred Stock are outstanding, the Corporation shall not, either directly or indirectly, by amendment or merger, or otherwise, amend the terms of the Convertible Preferred Stock in any manner that would adversely alter or change the powers, preferences or special rights of the Convertible Preferred Stock without (in addition to any other vote required by law or the Amended Articles of Incorporation) the affirmative vote or consent of the Requisite Holders, given in person or by proxy, either in writing by consent or by resolution adopted at an annual or special meeting of stockholders; provided that any amendment that adversely alters or changes the rights of a holder of Convertible Preferred Stock (i) to participate in dividends and other distributions, (ii) to convert its Convertible Preferred Stock pursuant to the

11

terms hereof, (iii) to Transfer its Convertible Preferred Stock or the Common Stock receivable therefor, or (iv) under this proviso, shall require the affirmative vote or consent of holders holding in aggregate at least 90% of the then outstanding Convertible Preferred Stock. Any amendment to the terms of the Convertible Preferred Stock, including, but not limited to, any amendment to this Amendment or the Amended Articles of Incorporation, entered into without such vote or consent shall be void ab initio and of no force and effect. Notwithstanding the foregoing, this Section ‎11 shall not require the affirmative consent of the Requisite Holders in connection with the issuance of securities pursuant to clause ‎(ii)(A) of Section ‎8.

12.Exclusion of Other Rights. Except as may otherwise be required by law, the shares of Convertible Preferred Stock shall not have any voting powers, preferences and relative, participating, optional or other special rights, other than those specifically set forth in this Amendment (as such Amendment may be amended from time to time) and in the Amended Articles of Incorporation (as amended). The shares of Convertible Preferred Stock shall have no preemptive or subscription rights.

13.Headings of Subdivisions. The headings of the various subdivisions hereof are for convenience of reference only and shall not affect the interpretation of any of the provisions hereof.

14.Severability of Provisions. If any voting powers, preferences and relative, participating, optional and other special rights of the Convertible Preferred Stock and qualifications, limitations and restrictions thereof set forth in this Amendment (as such resolution may be amended from time to time) is invalid, unlawful or incapable of being enforced by reason of any rule of law or public policy, all other voting powers, preferences and relative, participating, optional and other special rights of Convertible Preferred Stock and qualifications, limitations and restrictions thereof set forth in this Amendment (as so amended) which can be given effect without the invalid, unlawful or unenforceable voting powers, preferences and relative, participating, optional or other special rights of Convertible Preferred Stock and qualifications, limitations and restrictions thereof shall, nevertheless, remain in full force and effect and no voting powers, preferences and relative, participating, optional or other special rights of Convertible Preferred Stock and qualifications, limitations and restrictions thereof herein set forth shall be deemed dependent upon any other such voting powers, preferences and relative, participating, optional or other special rights of Convertible Preferred Stock and qualifications, limitations and restrictions thereof unless so expressed herein.

15.Re-issuance of Convertible Preferred Stock. Shares of Convertible Preferred Stock that have been issued and reacquired by the Corporation in any manner, including shares purchased or exchanged or converted, shall (upon compliance with any applicable provisions of the laws of Ohio) have the status of authorized but unissued shares of Preferred Stock of the Corporation undesignated as to series and may be designated or re-designated and issued or reissued, as the case may be, as part of any series of Preferred Stock of the Corporation, provided that any issuance of such shares as Convertible Preferred Stock must be in compliance with the terms hereof (including but not limited to Section ‎10‎(b)‎(iii) hereof).

16.Mutilated or Missing Convertible Preferred Stock Certificates. If physical certificates are issued for the Convertible Preferred Stock and if any of such Convertible Preferred Stock certificates shall be mutilated, lost, stolen or destroyed, the Corporation shall issue, at the

12

holder’s expense, in exchange and in substitution for and upon cancellation of the mutilated Convertible Preferred Stock certificate, or in lieu of and substitution for the Convertible Preferred Stock certificate lost, stolen or destroyed, a new Convertible Preferred Stock certificate of like tenor and representing an equivalent amount of shares of Convertible Preferred Stock, but only upon receipt of evidence of such loss, theft or destruction of such Convertible Preferred Stock certificate and indemnity and/or a bond, if requested, satisfactory to the Corporation and the Transfer Agent (if other than the Corporation).

17.Transfer Agent, Conversion Agent, Registrar and Paying Agent. The Transfer Agent, conversion agent, registrar and paying agent for the Convertible Preferred Stock shall initially be American Stock Transfer & Trust Company, LLC, the Corporation’s duly appointed transfer agent for the Convertible Preferred Stock. The Corporation may appoint a successor to any one or more of such roles (and may remove any such successor in accordance with any agreement with such successor and appoint a new successor). Upon any such removal or appointment, the Corporation shall provide notice to the holders of the Convertible Preferred Stock thereof. To the fullest extent permitted by applicable law, the Corporation and its duly appointed Transfer Agent may deem and treat the holder of any shares of Convertible Preferred Stock as the true and lawful owner thereof for all purposes.

18.Taxes. Except as otherwise agreed by the Corporation, all payments and distributions (or deemed distributions) on the shares of Convertible Preferred Stock (and any shares of Common Stock issued upon conversion thereof) shall be subject to withholding and backup withholding of tax to the extent required by law, and such amounts withheld, if any, shall be treated as received by the holders of Convertible Preferred Stock. The Corporation shall pay any and all stock transfer and documentary stamp taxes that may be payable in respect of any issuance or delivery of shares of Convertible Preferred Stock or shares of Common Stock or other securities issued on account of Convertible Preferred Stock pursuant hereto or certificates representing such shares or securities. The Corporation shall not, however, be required to pay any such tax that may be payable in respect of any transfer involved in the issuance or delivery of shares of Common Stock or other securities in a name other than that in which the shares of Convertible Preferred Stock with respect to which such shares or other securities are issued or delivered were registered, and the Corporation shall not be required to make any such issuance or delivery unless and until the Person otherwise entitled to such issuance or delivery has paid to the Corporation the amount of any such tax or has established, to the satisfaction of the Corporation, that such tax has been paid or is not payable.

19.Notices. Except as otherwise set forth herein, all notices to be provided by the Corporation to holders of Convertible Preferred Stock hereunder shall be delivered by a notice sent to holders of Convertible Preferred Stock by first class mail, postage prepaid, or by electronic mail or facsimile, or by such other manner as may be permitted in this Amendment, or the Amended Articles of Incorporation or the Corporation’s Amended Code of Regulations. Except as otherwise set forth herein, all notices to be provided by the holders of Convertible Preferred Stock to the Corporation hereunder shall be delivered by a notice sent to the Secretary of the Corporation by first class mail, postage prepaid, or by electronic mail or facsimile, or by such other manner as may be permitted in this Amendment, or the Amended Articles of Incorporation or the Corporation’s Amended Code of Regulations.

13

20.Adjustment to Liquidation Preference. The Liquidation Preference shall be subject to equitable adjustment in a manner not adverse to the holders of Convertible Preferred Stock if and whenever there shall occur a stock split, combination, reclassification or other similar event involving the Convertible Preferred Stock (including any reclassification of or other similar event involving the Common Stock, to the extent such event does not result in an adjustment to the Conversion Price in accordance with Section ‎5). Such adjustments shall be determined in good faith by the Board of Directors (or an authorized committee thereof) of the Corporation and submitted by the Board of Directors (or such authorized committee thereof) to the Transfer Agent.

21.Rounding and Definitive Calculations. All calculations (including interim calculations) hereunder shall be made to the nearest 1/1,000^th of a cent or to the nearest 1/1,000^th of a share, as the case may be. The Corporation shall make all calculations hereunder in good faith and, absent manifest error, its calculations shall be final and binding on holders of Convertible Preferred Stock.

22.No Impairment. The Corporation shall not, by amendment of this Amendment, the Amended Articles of Incorporation or any other organizational document of the Corporation or through any reorganization, recapitalization, transfer of assets, consolidation, merger, dissolution, issue or sale of securities or any other voluntary action, avoid or seek to avoid the observance or performance of any of the terms to be observed or performed under this Amendment by the Corporation, but shall at all times in good faith assist in the carrying out of all the provisions of this Amendment and in the taking of all such action as may be necessary or appropriate in order to protect the rights, preferences and privileges of the holders of Convertible Preferred Stock against impairment.

23.Certain Definitions. As used in this Amendment, the following terms shall have the following meanings (with terms defined in the singular having comparable meanings when used in the plural and vice versa), unless the context otherwise requires:

“Business Day” means a day other than a Saturday, Sunday or other day on which commercial banks in New York, New York are authorized or required by law to close.

“Common Stock” means the common stock, par value $0.10 per share, of the Corporation.

“Common Stock Equivalent” means any security or obligation which is by its terms, directly or indirectly, convertible into or exchangeable or exercisable for shares of Common Stock (other than the Convertible Preferred Stock and such instruments issued pursuant to a dividend reinvestment plan or share purchase plan or similar plans), including, without limitation, any option, warrant or other subscription or purchase right with respect to Common Stock or any Common Stock Equivalent.

“Common Stock Register” means a register maintained by the Corporation, the Transfer Agent or other agent of the Corporation for the purpose of recording the holders of record of shares of Common Stock.

14

“Conversion Price” means $27.42, subject to adjustment from time to time pursuant to the terms hereof.

“Current Market Price” means, on any day, the average of the Daily VWAP for the 20 consecutive Trading Days ending on the Trading Day immediately prior to the day in question.

“Daily VWAP” means the consolidated volume-weighted average price per share of Common Stock as displayed under the heading “Bloomberg VWAP” on the Bloomberg page for the “<equity> AQR” page corresponding to the “ticker” for such Common Stock (or its equivalent successor if such page is not available) in respect of the period from the scheduled open of trading until the scheduled close of trading of the primary trading session on such Trading Day (or if such volume-weighted average price is unavailable, the Market Price of one share of such Common Stock on such Trading Day). The “volume weighted average price” shall be determined without regard to after-hours trading or any other trading outside of the regular trading session trading hours.

“Eighteen-Month Anniversary Date” means the date that is eighteen months after the Issuance Date.

“Fair Market Value” means fair market value as determined by a nationally recognized investment banking firm, financial advisor or other appraiser selected in good faith by the Board of Directors; provided that the Fair Market Value of any cash dividend or distribution shall be the amount of such cash dividend or distribution.

“Fundamental Change” means a transaction in which the Corporation consolidates with, or merges with or into, or enters into any other business combination with, another Person or sells, assigns, conveys, transfers, leases or otherwise disposes of all or substantially all of its and its subsidiaries’ assets to any Person, or any Person consolidates or combines with, or merges with or into, the Corporation, in which such consolidation, combination, or merger the outstanding voting capital stock of the Corporation is converted into or exchanged for cash, securities or other property.

“Issuance Date” means January 22, 2018.

“Liquidation Preference” means $1,000.00 per share of Convertible Preferred Stock.

“Market Price” means, with respect to the Common Stock or any other security, on any given day, the last sale price, regular way, or, in case no such sale takes place on such day, the average of the closing bid and asked prices, regular way, of the shares of the Common Stock or of such security, as applicable, on the New York Stock Exchange on such day. If the Common Stock or such security, as applicable, is not listed on the New York Stock Exchange as of any date of determination, the Market Price of the Common Stock or such security, as applicable, on such date of determination means the closing sale price on such date as reported in the composite transactions for the principal U.S. national or regional securities exchange on which the Common Stock or such security, as applicable, is so listed or quoted, or, if no closing sale price is reported, the last reported sale price on such date on the principal U.S. national or regional securities exchange on which the Common Stock or such security, as applicable, is so listed or quoted, or if the Common Stock or such security, as applicable, is not so listed or quoted on a U.S. national or regional securities

15

exchange, the last quoted bid price on such date for the Common Stock or such security, as applicable, in the over-the-counter market as reported by OTC Markets Group Inc. or similar organization, or, if that bid price is not available, the Market Price of the Common Stock or such security, as applicable, on that date shall mean the Fair Market Value per share as of such date of the Common Stock or such security.

“Parity Securities” means equity securities of the Corporation ranking on a parity with Convertible Preferred Stock with respect to dividends and distributions or on the liquidation, dissolution or winding-up of the affairs of the Corporation, excluding the Common Stock.

“Person” means any individual, firm, corporation, partnership, limited liability company, incorporated or unincorporated association, joint venture, joint stock company, trust, governmental authority or other entity of any kind.

“Preferred Stock Register” means a register maintained by the Corporation, the Transfer Agent or other agent of the Corporation for the purpose of recording the holders of record of shares of Convertible Preferred Stock.

“Requisite Holders” means, at any time, the holders of shares of Convertible Preferred Stock representing at least a majority of the outstanding shares of Convertible Preferred Stock at such time; provided, however, that with respect to Section ‎11 it means the holders of shares of Convertible Preferred Stock representing at least 66 2/3% of the outstanding shares of Convertible Preferred Stock.

“Six-Month Anniversary Date” means the date that is six months from the Issuance Date.

“SEC” means the United States Securities and Exchange Commission.

“Securities Act” means the Securities Act of 1933.

“Senior Securities” means equity securities of the Corporation ranking senior to the Convertible Preferred Stock with respect to dividends or distributions and the liquidation, dissolution or winding-up of the affairs of the Corporation.

“Trading Day” means any day on which trading in listed securities occurs on the principal U.S. national securities exchange on which the Common Stock is then listed or, if the Common Stock is not so listed, any day on which trading in listed securities occurs on the New York Stock Exchange.

“Transfer” means, as a noun, any voluntary or involuntary transfer, sale, pledge, hypothecation, gift, or other disposition and, as a verb, voluntarily or involuntarily to transfer, sell, pledge, hypothecate, give, or otherwise dispose of. Notwithstanding the foregoing, each of the following shall be deemed not to be a “Transfer”: (i) any transfer, sale, pledge, hypothecation, gift or other disposition to an affiliate, (ii) any pledge of or other grant of a security interest in Pledged Convertible Preferred Shares to a Creditor or (iii) the foreclosure by a Creditor on or the acquisition of the beneficial ownership by other similar remedy of such Pledged Convertible Preferred Shares.

16

“Transfer Agent” shall be American Stock Transfer & Trust Company, LLC, the Corporation’s duly appointed transfer agent for the Convertible Preferred Stock, unless and until a successor is selected by the Corporation as provided herein.

“Two-Year Anniversary Date” means the date that is two years from the Issuance Date.

ARTICLE V

The Board of Directors shall be authorized hereby to exercise all powers now or hereafter permitted by law providing rights to the Board of Directors to adopt amendments to these Articles of Incorporation to fix or change the express terms of any unissued or treasury shares of any class, including, without limiting the generality of the foregoing: division of such shares into series and the designation and authorized number of shares of each series; voting rights of such shares (to the extent now or hereafter permitted by law); dividend or distribution rates; dates of payment of dividends or distributions and the dates from which they are cumulative; liquidation price; redemption rights and price; sinking fund requirements; conversion rights; and restrictions on the issuance of shares of the same series or any other class or series; all as may be established by resolution of the Board of Directors from time to time (collectively, a “Preferred Stock Designation”).

ARTICLE VI

Except as may be provided in any Preferred Stock Designation, the holders of shares of capital stock of the Corporation shall not be entitled to cumulative voting rights in the election of directors.

ARTICLE VII

Except as may be provided in any Preferred Stock Designation, no holder of any shares of capital stock of the Corporation shall have any preemptive right to acquire any shares of unissued capital stock of any class or series, now or hereafter authorized, or any treasury shares or securities convertible into such shares or carrying a right to subscribe to or acquire such shares of capital stock.

ARTICLE VIII

The Corporation may from time to time, pursuant to authorization by the Board of Directors and without action by the shareholders, purchase or otherwise acquire capital stock of the Corporation of any class or classes in such manner, upon such terms and in such amounts as the Board of Directors shall determine; subject, however, to such limitation or restriction, if any, as is contained in any Preferred Stock Designation at the time of such purchase or acquisition.

ARTICLE IX

Subject to any Preferred Stock Designation, to the extent applicable law permits these Amended Articles of Incorporation expressly to provide or permit a lesser vote than a two-thirds vote otherwise provided by law for any action or authorization for which a vote of shareholders is

17

required, including, without limitation, adoption of an amendment to these Amended Articles of Incorporation, adoption of a plan of merger, authorization of a sale or other disposition of all or substantially all of the assets of the Corporation not made in the usual and regular course of its business or adoption of a resolution of dissolution of the Corporation, such action or authorization shall be by a majority of the voting power of the Corporation and a majority of the voting power of any class entitled to vote as a class on such proposal; provided, however, this Article IX (and any resolution adopted pursuant hereto) shall not alter in any case any greater vote otherwise expressly provided by any provision of these Articles of Incorporation or the Code of Regulations. For purposes of these Articles of Incorporation, “voting power of the Corporation” means the aggregate voting power of (1) all the outstanding shares of Common Stock of the Corporation and (2) all the outstanding shares of any class or series of capital stock of the Corporation that has (i) rights to distributions senior to those of the Common Stock including, without limitation, any relative, participating, optional, or other special rights and privileges of, and any qualifications, limitations or restrictions on, such shares and (ii) voting rights entitling such shares to vote generally in the election of directors.

ARTICLE X

[Reserved]

ARTICLE XI

Any and every statute of the State of Ohio hereafter enacted, whereby the rights, powers or privileges of corporations or of the shareholders of corporations organized under the laws of the State of Ohio are increased or diminished or in any way affected, or whereby effect is given to the action taken by any number, less than all, of the shareholders of any such corporation, shall apply to the Corporation and shall be binding not only upon the Corporation but upon every shareholder of the Corporation to the same extent as if such statute had been in force at the date of filing these Articles of Incorporation in the office of the Secretary of State of Ohio.

ARTICLE XII

Except as may be provided in any Preferred Stock Designation, at each meeting of shareholders at which directors are to be elected, a candidate for director shall be elected only if the votes “for” the candidate exceed the votes “against” the candidate. Abstentions and broker non-votes shall not be counted as votes “for” or “against” a candidate. Notwithstanding the foregoing, if the Board of Directors determines that the number of candidates exceeds the number of directors to be elected, then in that election the candidates receiving the greatest number of votes shall be elected.

18

EX-3.2

Exhibit 3-2

FirstEnergy Corp.

AMENDED AND RESTATED
CODE OF REGULATIONS

Effective July 16, 2019

SHAREHOLDER MEETINGS

1.Time and Place of Meetings. All meetings of the shareholders for the election of directors or for any other purpose will be held at such time and place, within or without the State of Ohio, as may be designated by the Board of Directors or, in the absence of a designation by the Board of Directors, the Chairman of the Board of Directors, if any (the “Chairman”), the President, or the Secretary, and stated in the notice of meeting. The Board of Directors may postpone and reschedule any previously scheduled annual or special meeting of the shareholders.

2.Annual Meeting. An annual meeting of the shareholders will be held at such date and time as may be designated from time to time by the Board of Directors, at which meeting the shareholders will elect directors to succeed those directors whose terms expire at such meeting and will transact such other business as may be brought properly before the meeting in accordance with Regulation 9.

3.Special Meetings. (a) Special meetings of shareholders may be called by the Chairman or the President or by a majority of the Board of Directors acting with or without a meeting or by any person or persons who hold not less than 25% of all the shares outstanding and entitled to be voted on any proposal to be submitted at said meeting. Special meetings of the holders of shares that are entitled to call a special meeting by virtue of any Preferred Stock Designation may call such meetings in the manner and for the purposes provided in the applicable terms of such Preferred Stock Designation. For purposes of this Code of Regulations, “Preferred Stock

1

Designation” has the meaning ascribed to such term in the Articles of Incorporation of the Corporation, as may be amended from time to time.

(b)Upon written request by any person or persons entitled to call a meeting of shareholders delivered in person or by certified mail to the Chairman, the President or the Secretary, such officer shall forthwith cause notice of the meeting to be given to the shareholders entitled to notice of such meeting in accordance with Regulation 4. If such notice shall not be given within 60 days after the delivery or mailing of such request, the person or persons requesting the meeting may fix the time of the meeting and give, or cause to be given, notice in the manner provided in Regulation 4.

4.Notice of Meetings. Except to the full extent that notice is legally permitted (now or hereafter) to be given by any other form of media, including any form of electronic or other communications, written notice of every meeting of the shareholders called in accordance with these Regulations, stating the time, place and purposes for which the meeting is called, will be given by or at the direction of the Chairman, the President, a Vice President, the Secretary or an Assistant Secretary (or in case of their refusal, by the person or persons entitled to call the meeting under Regulation 3). Such notice will be given not less than 7 nor more than 60 calendar days before the date of the meeting to each shareholder of record entitled to notice of such meeting. If such notice is mailed, it shall be addressed to the shareholders at their respective addresses as they appear on the records of the Corporation, and notice shall be deemed to have been given on the day so mailed. Notice of adjournment of a meeting need not be given if the time and place to which it is adjourned are fixed and announced at such meeting.

5.Inspectors. Inspectors of election may be appointed to act at any meeting of shareholders in accordance with Ohio law.

6.Quorum. To constitute a quorum at any meeting of shareholders, there shall be present in person or by proxy shareholders of record entitled to exercise not less than a majority of the voting power of the Corporation in respect of any one of the purposes for which the meeting is called, unless a greater or lesser number is expressly provided for with respect to a particular class or series of capital stock by the terms of any applicable Preferred Stock Designation. Except as

2

may be otherwise provided in any Preferred Stock Designation, the holders of a majority of the voting power of the Corporation represented in person or by proxy at a meeting of shareholders, whether or not a quorum be present, may adjourn the meeting from time to time. For purposes of this Code of Regulations, “voting power of the Corporation” has the meaning ascribed to such term in the Articles of Incorporation of the Corporation, as may be amended from time to time.

7.Voting. Except as otherwise expressly provided by law, the Articles of Incorporation or this Code of Regulations, at any meeting of shareholders at which a quorum is present, a majority of the votes cast, whether in person or by proxy, on any matter properly brought before such meeting in accordance with Regulation 9 will be the act of the shareholders. An abstention shall not represent a vote cast. Every proxy must be duly executed and filed with the Secretary. A shareholder may revoke any proxy that is not irrevocable by attending the meeting and voting in person or by filing with the Secretary written notice of revocation or a later appointment. The vote upon any question brought before a meeting of the shareholders may be by voice vote, unless otherwise required by law, the Articles of Incorporation or this Code of Regulations or unless the presiding officer otherwise determines.

8.Record Dates. In order that the Corporation may determine the shareholders entitled to notice of or to vote at any meeting of shareholders or any adjournment thereof, the Board of Directors may fix a record date, which will not be less than 7 nor more than 60 calendar days before the date of such meeting. If no record date is fixed by the Board of Directors, the record date for determining shareholders entitled to notice of or to vote at a meeting of shareholders will be the date next preceding the day on which notice is given, or, if notice is waived, at the date next preceding the day on which the meeting is held.

9.Order of Business. (a) The Chairman, or such other officer of the Corporation designated by a majority of the total number of directors that the Corporation would have if there were no vacancies on the Board of Directors (such number being referred to as the “Whole Board”), will call meetings of shareholders to order and will act as presiding officer thereof. Unless otherwise determined by the Board of Directors prior to the meeting, the presiding officer of the meeting of shareholders will also determine the order of business and have the authority in his or her sole discretion to regulate the conduct of any such meeting including, without limitation, by imposing

3

restrictions on the persons (other than shareholders of the Corporation or their duly appointed proxies) who may attend any such shareholders’ meeting, by ascertaining whether any shareholder or his proxy may be excluded from any meeting of shareholders based upon any determination by the presiding officer, in his sole discretion, that any such person has unduly disrupted or is likely to disrupt the proceedings of the meeting, and by determining the circumstances in which any person may make a statement or ask questions at any meeting of shareholders.

(b)At an annual meeting of the shareholders, only such business will be conducted or considered as is properly brought before the meeting. To be properly brought before an annual meeting, business must be (i) specified in the notice of meeting (or any supplement thereto) given by or at the direction of the Chairman, the President, a Vice President, the Secretary or an Assistant Secretary in accordance with Regulation 4, (ii) otherwise properly brought before the meeting by the presiding officer or by or at the direction of a majority of the Whole Board, or (iii) otherwise properly requested to be brought before the meeting by a shareholder of the Corporation in accordance with Regulation 9(c).

(c)For business to be properly requested by a shareholder to be brought before an annual meeting, the shareholder must (i) be a shareholder of the Corporation of record at the time of the giving of the notice for such annual meeting provided for in this Code of Regulations, (ii) be entitled to vote at such meeting, and (iii) have given timely notice thereof in writing to the Secretary. To be timely, a shareholder’s notice must be delivered to or mailed and received at the principal executive offices of the Corporation not less than 30 nor more than 60 calendar days prior to the annual meeting; provided, however, that in the event public announcement of the date of the annual meeting is not made at least 70 calendar days prior to the date of the annual meeting, notice by the shareholder to be timely must be so received not later than the close of business on the 10th calendar day following the day on which public announcement is first made of the date of the annual meeting. A shareholder’s notice to the Secretary must set forth as to each matter the shareholder proposes to bring before the annual meeting (A) a description in reasonable detail of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (B) the name and address, as they appear on the Corporation’s books, of the shareholder proposing such business and of the beneficial owner, if any, on whose behalf the proposal is made,

4

(C) the class and number of shares of the Corporation that are owned beneficially and of record by the shareholder proposing such business and by the beneficial owner, if any, on whose behalf the proposal is made, and (D) any material interest of such shareholder proposing such business and the beneficial owner, if any, on whose behalf the proposal is made in such business. Notwithstanding the foregoing provisions of this Code of Regulations, a shareholder must also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder with respect to the matters set forth in this Regulation 9(c). For purposes of this Regulation 9(c) and Regulation 14, “public announcement” means disclosure in a press release reported by the Dow Jones News Service, Associated Press, or comparable national news service or in a document publicly filed by the Corporation with the Securities and Exchange Commission pursuant to Sections 13, 14, or 15(d) of the Securities Exchange Act of 1934, as amended, or publicly filed by the Corporation with any national securities exchange or quotation service through which the Corporation’s stock is listed or traded, or furnished by the Corporation to its shareholders. Nothing in this Regulation 9(c) will be deemed to affect any rights of shareholders to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a‑8 under the Securities Exchange Act of 1934, as amended.

(d)At a special meeting of shareholders, only such business may be conducted or considered as is properly brought before the meeting. To be properly brought before a special meeting, business must be (i) specified in the notice of the meeting (or any supplement thereto) given by or at the direction of the Chairman, the President, a Vice President, the Secretary or an Assistant Secretary (or in case of their failure to give any required notice, the other persons entitled to give notice) in accordance with Regulation 4 or (ii) otherwise brought before the meeting by the presiding officer or by or at the direction of a majority of the Whole Board.

(e)The determination of whether any business sought to be brought before any annual or special meeting of the shareholders is properly brought before such meeting in accordance with this Regulation 9 will be made by the presiding officer of such meeting. If the presiding officer determines that any business is not properly brought before such meeting, he or she will so declare to the meeting and any such business will not be conducted or considered.

DIRECTORS

5

10.Function and Qualification. (a) Except where the law, the Articles of Incorporation, or this Code of Regulations requires action to be authorized or taken by the shareholders, all of the authority of the Corporation shall be exercised by or under the direction of the Board of Directors.

(b)In order to qualify for service as a director of the Corporation, within 90 days following election to the Board of Directors in accordance with Regulations 11, 12 and 14, each director will become and will remain the beneficial owner of not less than 100 shares of Common Stock of the Corporation, except where such ownership would be inconsistent with or prohibited by (i) any applicable law, rule, regulation, order or decree of any governmental authority or (ii) any policy, contract, commitment or arrangement authorized by the Corporation.

11.Number, Election and Terms of Directors. Except as may be otherwise provided in any Preferred Stock Designation, the number of the directors of the Corporation will not be less than nine nor more than 16 as may be determined from time to time only (i) by a vote of a majority of the Whole Board, or (ii) by the affirmative vote of the holders of a majority of the voting power of the Corporation, voting together as a single class. Directors shall hold office for a term expiring at the following annual meeting of shareholders and until their successors shall have been elected. Except as may be otherwise provided in any Preferred Stock Designation, directors may be elected by the shareholders only at an annual meeting of shareholders. No decrease in the number of directors constituting the Board of Directors may shorten the term of any incumbent director. Election of directors of the Corporation need not be by written ballot unless requested by the presiding officer or by the holders of a majority of the voting power of the Corporation present in person or represented by proxy at a meeting of the shareholders at which directors are to be elected.

12.Newly Created Directorships and Vacancies. Except as may be otherwise provided in any Preferred Stock Designation, any vacancy (including newly created directorships resulting from any increase in the number of directors and any vacancies on the Board of Directors resulting from death, resignation, disqualification, removal or other cause) may be filled only (i) by the affirmative vote of a majority of the remaining directors then in office, even though less than a quorum of the Board of Directors, or by a sole remaining director or (ii) by the affirmative vote of the shareholders after a vote to increase the number of directors at a meeting called for that purpose in accordance with this Code of Regulations. Any director elected in accordance with the preceding

6

sentence to fill a vacancy that does not result from a newly created directorship will hold office for the remainder of the full term of the director that he or she is replacing. Any director elected in accordance with the first sentence of Regulation 12 will hold office until such director’s successor has been elected.

13.Removal. Except as may be otherwise provided in any Preferred Stock Designation, any director or the entire Board of Directors may be removed only upon the affirmative vote of the holders of a majority of the voting power of the Corporation, voting together as a single class.

14.Nominations of Directors; Election. (a) Except as may be otherwise provided in any Preferred Stock Designation, only persons who are nominated in accordance with this Regulation 14 will be eligible for election at a meeting of shareholders to be members of the Board of Directors of the Corporation.

(b)Nominations of persons for election as directors of the Corporation may be made only for elections to be held at an annual meeting of shareholders and only (i) by or at the direction of the Board of Directors or a committee thereof, (ii) by any shareholder who is a shareholder of record at the time of giving of notice provided for in this Regulation 14, who is entitled to vote for the election of directors at such meeting, and who complies with the procedures set forth in this Regulation 14 or (iii) by one or more Eligible Shareholders (as defined below) pursuant to and in accordance with Regulation 14(d). All nominations by shareholders must be made pursuant to timely notice in proper written form to the Secretary.

(c)For nominations of persons for election as directors of the Corporation (other than a nomination for director pursuant to Regulation 14(d)) to be timely, notice delivered by a shareholder who intends to appear in person or by proxy and nominate a person for election as a director of the Corporation at an annual meeting of shareholders (such notice, the “Nomination Notice”) containing the Required Information (as defined below) must be delivered to or mailed and received at the principal executive offices of the Corporation not less than 30 nor more than 60 calendar days prior to the annual meeting of shareholders; provided, however, that in the event that public announcement of the date of the annual meeting is not made at least 70 calendar days prior to the date of the annual meeting, notice by the shareholder to be timely must be so received not later than the close of

7

business on the 10th calendar day following the day on which public announcement is first made of the date of the annual meeting by the Corporation. In no event shall any adjournment or postponement of a shareholders’ meeting, or the public announcement thereof, commence a new time period for the giving of a Nomination Notice as described above, except as required by law.

(d)The Corporation shall include in its proxy statement and proxy for any annual meeting of shareholders (collectively, the “Proxy Materials”), together with any information required to be included in a proxy statement filed pursuant to the rules and regulations of the Securities and Exchange Commission and, if the Eligible Shareholder so elects, a Statement (as defined below), the name of any person nominated for election to the Board of Directors (the “Shareholder Nominee”) by a shareholder, or a group of no more than 20 shareholders, who satisfies the requirements of this Regulation 14(d) (an “Eligible Shareholder”) and who expressly elects at the time of providing the written notice required by this Regulation 14(d) to have its nominee included in the Proxy Materials pursuant to this Regulation 14(d). For purposes of any representation, agreement or other undertaking required by this Regulation 14(d), the term “Eligible Shareholder” shall include each member of any group forming an Eligible Shareholder. Such written notice shall consist of a copy of Schedule 14N filed with the Securities and Exchange Commission in accordance with Rule 14a-18 of the Securities Exchange Act of 1934, as amended, or any successor schedule or form filed with the Securities and Exchange Commission in accordance with Rule 14a-18 of the Securities Exchange Act of 1934, as amended, or any successor provision, the Required Information and the other information required by this Regulation 14(d) (all such information collectively referred to as the “Proxy Notice”), and such Proxy Notice shall be delivered to the Corporation in accordance with the procedures and at the times set forth in this Regulation 14(d).

(i)To be timely, the Proxy Notice must be delivered to or mailed and received at the principal executive offices of the Corporation no earlier than 150 calendar days and no later than 120 calendar days prior to the first anniversary of the date that the Corporation issued its Proxy Materials for the previous year’s annual meeting of shareholders; provided, however, that in the event that the date of the annual meeting is more than 30 calendar days before or more than 60 calendar days after the first anniversary of the previous year’s annual meeting of shareholders, the Proxy Notice, to be timely, must be delivered to or mailed and received at the principal executive

8

offices of the Corporation not later than (A) 150 calendar days prior to the date of such annual meeting or (B) if the first public announcement of the date of such annual meeting is less than 150 calendar days prior to the date of such annual meeting, 10 calendar days following the day on which public announcement is first made by the Corporation of the date of such meeting.

(ii)The Corporation shall not be required to include, pursuant to this Regulation 14(d), any Shareholder Nominee in the Proxy Materials (A) for which the Secretary of the Corporation receives a Nomination Notice (whether or not subsequently withdrawn) pursuant to which the nominating shareholder has nominated a person for election to the Board of Directors pursuant to the advance notice requirements for shareholder nominees for director set forth in Regulation 14(c), (B) whose election as a member of the Board of Directors would cause the Corporation to be in violation of these Regulations, the Articles of Incorporation of the Corporation, the rules and listing standards of the principal U.S. exchange upon which the Common Stock of the Corporation is listed, any applicable state or federal law, rule or regulation, or the Corporation’s publicly disclosed policies and procedures, (C) who is or has been within the past three years, an officer or director of a competitor, as defined in Section 8 of the Clayton Antitrust Act of 1914, as amended, (D) who is a named subject of a pending criminal proceeding or has been convicted in such a criminal proceeding within the past 10 years (excluding traffic violations and other minor offenses) or (E) who is subject to any order of the type specified in Rule 506(d) of Regulation D promulgated under the Securities Act of 1933, as amended, or any successor provision.

(iii)The maximum number of Shareholder Nominees appearing in the Proxy Materials with respect to an annual meeting of shareholders shall not exceed 20% of the number of directors in office as of the last day on which the Proxy Notice may be delivered or received or, if such amount is not a whole number, the closest whole number below 20%, and in any event, not less than two Shareholder Nominees. In the event that one or more vacancies for any reason occurs on the Board of Directors after the last day on which the Proxy Notice may be delivered or received but before or as of the annual meeting of shareholders and the Board of Directors resolves to reduce the size of the Board of Directors in connection therewith, the maximum number of Shareholder Nominees included in the Proxy Materials shall be calculated based on the number of directors in office as so reduced. Shareholder Nominees that were submitted by an Eligible Shareholder for inclusion in

9

Proxy Materials pursuant to this Regulation 14(d) but either are subsequently withdrawn after the last day on which the Proxy Notice may be delivered or received or whom the Board of Directors itself determines to nominate for election shall, for the purposes of this Regulation 14(d)(iii), count as Shareholder Nominees appearing in the Proxy Materials. Each Eligible Shareholder shall rank each Shareholder Nominee it submitted for inclusion in the Proxy Materials and in the event that the number of Shareholder Nominees submitted by Eligible Shareholders pursuant to this Regulation 14(d) exceeds this maximum number, the highest ranked Shareholder Nominee from the Eligible Shareholder owning the greatest number of shares of stock of the Corporation will be selected for inclusion in the Proxy Materials first, followed by the highest ranked Shareholder Nominee of the Eligible Shareholder holding the next greatest number of shares of stock of the Corporation, and continuing on in that manner until the maximum number of Shareholder Nominees is reached.

(iv)For purposes of this Regulation 14(d), an Eligible Shareholder shall be deemed to own only those outstanding shares of Common Stock of the Corporation as to which the shareholder possesses both (A) the full voting and investment rights pertaining to the shares and (B) the full economic interest in (including the opportunity for profit and risk of loss on) such shares; provided that the number of shares calculated in accordance with clauses (A) and (B) shall not include any shares (1) sold by such shareholder or any of its affiliates in any transaction that has not been settled or closed, (2) borrowed by such shareholder or any of its affiliates for any purposes or purchased by such shareholder or any of its affiliates pursuant to an agreement to resell, or (3) subject to any option, warrant, forward contract, swap, contract of sale, other derivative or similar agreement entered into by such shareholder or any of its affiliates, whether any such instrument or agreement is to be settled with shares or with cash based on the notional amount or value of shares of outstanding Common Stock of the Corporation, in any such case which instrument or agreement has, or is intended to have, or if exercised would have, the purpose or effect of (x) reducing in any manner, to any extent or at any time in the future, such shareholder’s or its affiliates’ full right to vote or direct the voting of any such shares, or (y) hedging, offsetting or altering to any degree gain or loss arising from the full economic ownership of such shares by such shareholder or affiliate. Further, for purposes of this Regulation 14(d), an Eligible Shareholder shall be deemed to own shares held in the name of a nominee or other intermediary so long as the shareholder retains the right to recall the shares for voting purposes on no less than five business days’ notice, represents that they will

10

vote such shares at the applicable shareholder meeting and possesses the full economic interest in the shares. An Eligible Shareholder’s ownership of shares shall be deemed to continue during any period in which the shareholder has delegated any voting power by means of a proxy, power of attorney or other instrument or arrangement that is revocable at any time by the shareholder. The terms “owned,” “owning” and other variations of the word “own” shall have correlative meanings. Whether outstanding shares of the Common Stock of the Corporation are owned for purposes of this Regulation 14(d) shall be determined by the Board of Directors or a committee thereof, in its reasonable discretion. For the purposes of this Regulation 14(d)(iv), the term “affiliate” or “affiliates” shall have the meaning ascribed thereto under the rules and regulations of the Securities Exchange Act of 1934, as amended. No shares of stock of the Corporation may be attributed to more than one group constituting an Eligible Shareholder and no shareholder or beneficial owner, alone or together with any of its affiliates, may be a member of more than one group constituting an Eligible Shareholder. Furthermore, two or more funds that are (A) under common management and investment control, (B) under common management and funded primarily by the same employer or (C) a “group of investment companies,” as such term is defined in the Investment Company Act of 1940, as amended, shall be treated as one shareholder for purposes of determining Eligible Shareholder status.

(v)An Eligible Shareholder must have owned 3% or more of the Corporation’s issued and outstanding Common Stock continuously for at least three years (the “Required Shares”) as of each of the date the Proxy Notice is delivered to or received by the Corporation, the date the Proxy Notice is required to be delivered to or received by the Corporation in accordance with this Regulation 14(d) and the record date for determining shareholders entitled to vote at the annual meeting, and must continue to hold the Required Shares through the date of the annual meeting. Within the time period specified in this Regulation 14(d) for delivery of the Proxy Notice, an Eligible Shareholder must provide the following information in writing to the Secretary of the Corporation: (A) one or more written statements from the record holder of the shares (and from each intermediary through which the shares are or have been held during the requisite three-year holding period) verifying that, as of a date within three calendar days prior to the date the Proxy Notice is delivered to or received by the Corporation, the Eligible Shareholder owns, and has owned continuously for the preceding three years, the Required Shares, and the Eligible Shareholder’s agreement to provide,

11

within five business days after each of the date the Proxy Notice is required to be delivered to or received by the Corporation and the record date for the annual meeting, written statements from the record holder and intermediaries verifying the Eligible Shareholder’s continuous ownership of the Required Shares through each of the date the Proxy Notice is required to be delivered to or received by the Corporation and the record date, along with a written statement that the Eligible Shareholder will continue to hold the Required Shares through the date of the annual meeting; (B) the Required Information, together with the written consent of each Shareholder Nominee to being named in the Proxy Statement as a nominee; (C) a representation that (1) the Eligible Shareholder acquired the Required Shares in the ordinary course of business and did not acquire any of the Required Shares with the intent to change or influence control of the Corporation, and does not presently have such intent, (2) the Eligible Shareholder has not nominated and will not nominate for election to the Board of Directors at the annual meeting any person other than the Shareholder Nominee(s) being nominated pursuant to this Regulation 14(d), (3) the Eligible Shareholder has not engaged and will not engage in, and has not and will not be a “participant” in another person’s, “solicitation” within the meaning of Rule 14a-1(l) under the Securities Exchange Act of 1934, as amended, or any successor provision, in support of the election of any individual as a director at the annual meeting other than its Shareholder Nominee or a nominee of the Board of Directors, (4) that the Shareholder Nominee(s) is or are eligible for inclusion in the Proxy Materials under Regulation 14(d)(ii) and (5) the Eligible Shareholder will not distribute to any shareholder any proxy for the annual meeting other than the form distributed by the Corporation, (D) an undertaking that the Eligible Shareholder agrees to (1) assume all liability stemming from any legal or regulatory violation arising out of the Eligible Shareholder’s communications with the shareholders of the Corporation or out of the information that the Eligible Shareholder provided to the Corporation, (2) comply with all other laws and regulations applicable to any solicitation in connection with the annual meeting, and (3) provide to the Corporation prior to the election of directors such additional information as requested with respect thereto, including any other certifications, representations or undertakings as the Corporation may reasonably request, (E) in the case of a nomination by a group of shareholders that together is an Eligible Shareholder, the designation by all group members of one group member that is authorized to act on behalf of all such members with respect to the nomination, (F) an undertaking that the Eligible Shareholder agrees to immediately notify the

12

Corporation if the Eligible Shareholder ceases to own any of the Required Shares prior to the date of the applicable annual meeting and (G) in the case of a nomination by an Eligible Shareholder that includes a group of funds whose shares are aggregated for purposes of constituting an Eligible Shareholder, an undertaking that the Eligible Shareholder agrees to provide all documentation and other information reasonably requested by the Corporation to demonstrate that the funds satisfy Regulation 14(d)(iv). If the Eligible Shareholder does not comply with each of the applicable representation, agreements and undertakings set forth in this Regulation 14(d)(v), or the Eligible Shareholder provides information to the Corporation regarding a nomination that is untrue in any material respect or omitted to state a material fact necessary in order to make a statement made, in light of the circumstances under which it was made, not misleading, the Shareholder Nominee(s) nominated by such Eligible Shareholder shall be deemed to have been withdrawn and will not be included in the Proxy Materials.

(vi)The Eligible Shareholder may provide to the Secretary of the Corporation, at the time the information required by this Regulation 14(d) is first provided, a written statement (the “Statement”) for inclusion in the Proxy Materials, not to exceed 500 words, in support of the Shareholder Nominee’s candidacy. Notwithstanding anything to the contrary contained in this Regulation 14(d), the Corporation may omit from the Proxy Materials any information or Statement that it, in good faith, believes is materially false or misleading, omits to state any material fact or would violate any applicable law or regulation. If multiple members of a shareholder group submit a statement for inclusion, the statement received by the Eligible Shareholder owning the greatest number of shares will be selected.

(vii)On or prior to the date the Proxy Notice is required to be delivered or received by the Corporation as specified in this Regulation 14(d), a Shareholder Nominee must deliver to the Secretary of the Corporation the written questionnaire required of directors and officers. The Shareholder Nominee must also deliver to the Corporation such additional information as the Corporation may request to permit the Board of Directors to determine if the Shareholder Nominee is independent under the rules and listing standards of the principal U.S. exchange upon which the Corporation’s Common Stock is listed, any applicable rules of the Securities and Exchange Commission, any publicly disclosed standards used by the Board of Directors in determining and

13

disclosing the independence of its directors. If the Board of Directors determines in good faith that the Shareholder Nominee is not independent under any of these standards, the Shareholder Nominee will be deemed to have been withdrawn and will not be included in the Proxy Materials. If a Shareholder Nominee or an Eligible Shareholder fails to continue to meet the requirements of this Regulation 14(d) or if the Eligible Shareholder fails to meet the all of the requirements of the notice provisions set forth in Regulation 14(d)(v) or if a Shareholder Nominee dies, becomes disabled or is otherwise disqualified from being nominated for election or serving as a director prior to the annual meeting of shareholders: (A) the Corporation may, to the extent feasible, remove the name of the Shareholder Nominee and the Statement from its proxy statement, remove the name of the Shareholder Nominee from its form of proxy and/or otherwise communicate to its shareholders that the Shareholder Nominee will not be eligible for nomination at the annual meeting of Shareholders; and (B) the Eligible Shareholder may not name another Shareholder Nominee or, subsequent to the date on which the Proxy Notice is required to be delivered to or received by the Corporation, otherwise cure in any way any defect preventing the nomination of the Shareholder Nominee at the annual meeting of Shareholders. On or prior to the date the Proxy Notice is required to be delivered to or received by the Corporation as specified in this Regulation 14(d), a Shareholder Nominee must deliver to the Secretary of the Corporation a written representation and agreement that such person (i) is not and will not become a party to any agreement, arrangement or understanding with, and has not given any commitment or assurance to, any person or entity as to how such person, if elected as a director of the Corporation, will act or vote on any issue or question that has not been disclosed to the Corporation, (ii) is not and will not become a party to any agreement, arrangement or understanding with any person or entity other than the Corporation with respect to any direct or indirect compensation, reimbursement or indemnification in connection with service or action as a director that has not been disclosed to the Corporation, and (iii) will comply with all the Corporation corporate governance, conflict of interest, confidentiality and stock ownership and trading policies and guidelines, and any other the Corporation policies and guidelines applicable to directors. If the Shareholder Nominee fails to comply with any of the requirements included in this paragraph or this Regulation 14(d), the Shareholder Nominee will be deemed to have withdrawn and will not be included in the Proxy Materials.

14

(viii)Notwithstanding the provisions of this Regulation 14(d), unless otherwise required by law or otherwise determined by the Board of Directors, if (A) the Eligible Shareholder or (B) a qualified representative of the Eligible Shareholder does not appear at the applicable annual meeting to present its Shareholder Nominee or Shareholder Nominees, such nomination or nominations shall be disregarded, and no vote on such Shareholder Nominee or Shareholder Nominees will occur, notwithstanding that proxies in respect of such vote may have been received by the Corporation. For purposes of this Regulation 14(d)(viii), to be considered a qualified representative of an Eligible Shareholder, a person must be authorized by a writing executed by such Eligible Shareholder or an electronic transmission delivered by such Eligible Shareholder to act for such Eligible Shareholder as proxy at the applicable annual meeting and such person must produce such writing or electronic transmission, or a reliable reproduction of the writing or electronic transmission, at the applicable annual meeting.

(ix)Notwithstanding anything in this Regulation 14(d) to the contrary, in the event that the number of directors to be elected to the Board of Directors is increased by the Board of Directors, and there is no public announcement by the Corporation naming all of the nominees for director or specifying the size of the increased Board of Directors at least 130 calendar days prior to the first anniversary of the preceding year’s annual meeting, a Proxy Notice shall also be considered timely, but only with respect to nominees for any new positions created by such increase and only to the extent the increase in the size of the board increases the number of nominees permitted under Regulation 14(d)(v), if it shall be delivered to or received by the Secretary at the principal executive offices of the Corporation not later than the close of business on the tenth calendar day following the day on which such public announcement is first made by the Corporation.

(x)This Regulation 14(d) shall be the exclusive method for shareholders to include nominees for director in the Corporation’s proxy materials.

(e)    In addition to other information required to be provided pursuant to this Regulation 14, to be in proper written form, each Nomination Notice and Proxy Notice must set forth or include (the following, collectively referred to as the “Required Information”): (i) the name and address, as they appear on the Corporation’s books, of the shareholder or group of shareholders giving such notice and of the beneficial owner, if any, on whose behalf the nomination is made; (ii) a

15

representation that the shareholder or group of shareholders giving such notice is a holder of record of stock of the Corporation entitled to vote at such annual meeting and intends to appear in person or by proxy at the annual meeting to nominate the person or persons specified in such notice; (iii) the class and number of shares of stock of the Corporation owned beneficially and of record by the shareholder or group of shareholders giving such notice and by the beneficial owner, if any, on whose behalf the nomination is made; (iv) a description of all arrangements or understandings between or among any of (A) the shareholder or group of shareholders giving such notice, (B) the beneficial owner on whose behalf such notice is given, (C) each nominee, and (D) any other person or persons (naming such person or persons) pursuant to which the nomination or nominations are to be made by the shareholder or group of shareholders giving such notice; (v) such other information regarding each nominee proposed by the shareholder or group of shareholders giving such notice as would be required to be included in a proxy statement filed pursuant to the proxy rules of the Securities and Exchange Commission had the nominee been nominated, or intended to be nominated, by the Board of Directors; (vi) the signed consent of each nominee to serve as a director of the Corporation if so elected; and (vii) in the case of a Proxy Notice, if the Eligible Shareholder so elects, a Statement.

(f) The presiding officer of any annual meeting shall have the power to determine and declare to the meeting whether a nomination was made in accordance with the procedures prescribed by the Code of Regulations, and if the presiding officer should so determine that such nomination was not made in compliance with the Code of Regulations, declare to the meeting that no action shall be taken on such nomination and such defective nomination shall be disregarded. Notwithstanding the foregoing provisions of this Regulation 14, a shareholder must also comply with all applicable requirements of the Securities Exchange Act of 1934, as amended, and the rules and regulations thereunder with respect to the matters set forth in this Regulation 14.

15.Resignation. Any director may resign at any time by giving written notice of his resignation to the Chairman or the Secretary. Any resignation will be effective upon actual receipt by any such person or, if later, as of the date and time specified in such written notice.

16.Regular Meetings. Regular meetings of the Board of Directors may be held immediately after the annual meeting of the shareholders and at such other time and place either

16

within or without the State of Ohio as may from time to time be determined by a majority of the Whole Board. Notice of regular meetings of the Board of Directors need not be given.

17.Special Meetings. Special meetings of the Board of Directors may be called by the Chairman or the President on one day’s notice to each director by whom such notice is not waived, given either personally or by mail, telephone, telegram, telex, facsimile or similar medium of communication, and will be called by the Chairman or the President, in like manner and on like notice, on the written request of not less than one-third of the Whole Board. Special meetings of the Board of Directors may be held at such time and place either within or without the State of Ohio as is determined by a majority of the Whole Board or specified in the notice of any such meeting.

18.Quorum and Vote. At all meetings of the Board of Directors, one-third of the total number of directors then in office will constitute a quorum for the transaction of business. Except for the designation of committees as hereinafter provided and except for actions required by this Code of Regulations to be taken by a majority of the Whole Board, the act of a majority of the directors present at any meeting at which a quorum is present will be the act of the Board of Directors. If a quorum is not present at any meeting of the Board of Directors, the directors present thereat may adjourn the meeting from time to time to another time or place, without notice other than announcement at the meeting, until a quorum is present.

19.Participation in Meetings by Communications Equipment. Meetings of the Board of Directors or of any committee of the Board of Directors may be held through any means of communications equipment if all persons participating can hear each other, and such participation will constitute presence in person at such meeting.

20.Committees. The Board of Directors may from time to time create an executive committee or any other committee or committees of directors to act in the intervals between meetings of the Board of Directors and may delegate to such committee or committees any of its authority other than that of filling vacancies among the Board of Directors or in any committee of the Board of Directors. No committee shall consist of less than three directors. The Board of Directors may appoint one or more directors as alternate members of any such committee to take the place of absent committee members at meetings of such committee. Unless otherwise ordered by the Board

17

of Directors, a majority of the members of any committee appointed by the Board of Directors pursuant to this Regulation 20 shall constitute a quorum at any meeting thereof, and the act of a majority of the members present at a meeting at which a quorum is present shall be the act of such committee. Action may be taken by any such committee without a meeting by a writing or writings signed by all of its members. Any such committee may prescribe its own rules for calling and holding meetings and its method of procedure, subject to any rules prescribed by the Board of Directors, and will keep a written record of all action taken by it.

21.Compensation. The Board of Directors may establish the compensation and expense reimbursement policies for directors in exchange for membership on the Board of Directors and on committees of the Board of Directors, attendance at meetings of the Board of Directors or committees of the Board of Directors, and for other services by directors to the Corporation or any of its subsidiaries. No director that is also an officer or employee of the Corporation shall receive compensation as a director.

22.Bylaws. The Board of Directors may adopt Bylaws for the conduct of its meetings and those of any committees of the Board of Directors that are not inconsistent with the Articles of Incorporation or this Code of Regulations.

OFFICERS

23.Generally. The Corporation may have a Chairman, elected by the directors from among their number, and shall have a President, a Secretary and a Treasurer. The Corporation may also have one or more Vice Chairmen and Vice Presidents and such other officers and assistant officers as the Board of Directors may deem appropriate. If the Board of Directors so desires, it may elect a Chief Executive Officer to manage the affairs of the Corporation, subject to the direction and control of the Board of Directors. All of the officers shall be elected by the Board of Directors. Notwithstanding the foregoing, by specific action, the Board of Directors may authorize the Chairman or the President to appoint any person to any office other than Chairman, President, Secretary, or Treasurer. Any number of offices may be held by the same person, and no two offices must be held by the same person. Any of the offices may be left vacant from time to time as the Board of Directors may determine. In case of the absence or disability of any officer of the

18

Corporation or for any other reason deemed sufficient by a majority of the Board of Directors, the Board of Directors may delegate the absent or disabled officer’s powers or duties to any other officer or to any director.

24.Authority and Duties of Officers. The officers of the Corporation shall have such authority and shall perform such duties as are customarily incident to their respective offices, or as may be specified from time to time by the Board of Directors, the Chairman or the President regardless of whether such authority and duties are customarily incident to such office.

25.Compensation. The compensation of all officers and agents of the Corporation who are also members of the Board of Directors of the Corporation will be fixed by the Board of Directors or by a committee of the Board of Directors. The Board of Directors may fix, or delegate the power to fix, the compensation of the other officers and agents of the Corporation to the Chief Executive Officer or any other officer of the Corporation.

26.Succession. The officers of the Corporation will hold office until their successors are elected. Any officer may be removed at any time by the affirmative vote of a majority of the Whole Board. Any vacancy occurring in any office of the Corporation may be filled by the Board of Directors or by the Chairman or President as provided in Regulation 23.

STOCK

27.Transfer and Registration of Shares. The Board of Directors shall have authority to make such rules and regulations as they deem expedient concerning the issuance, transfer and registration of shares and may appoint transfer agents and registrars thereof.

28.Substituted Certificates. Any person claiming a certificate for shares to have been lost, stolen or destroyed shall make an affidavit or affirmation of that fact, shall give the Corporation and its transfer agent or agents a bond of indemnity or other assurance satisfactory to the Board of Directors or a committee thereof or to the President or a Vice President and the Secretary or the Treasurer, whereupon a new certificate may be executed and delivered of the same class and series or type and for the same number of shares as the one alleged to have been lost, stolen or destroyed.

19

29.Voting Of Shares Held by the Corporation. Unless otherwise ordered by the Board of Directors, the President in person or by proxy or proxies appointed by him will have full power and authority on behalf of the Corporation to vote, act and consent with respect to any shares issued by other corporations that the Corporation may own.

30.Owners of Shares. The Corporation will be entitled to treat the person in whose name shares are registered on the books of the Corporation as the absolute owner thereof, and will not be bound to recognize any equitable or other claim to, or interest in, such share on the part of any other person, whether or not the Corporation has knowledge or notice thereof, except as expressly provided by applicable law.

INDEMNIFICATION AND INSURANCE

31.Indemnification. The Corporation shall indemnify, to the full extent then permitted by law, any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative, by reason of the fact that he is or was a member of the Board of Directors or an officer, employee or agent of the Corporation, or is or was serving at the request of the Corporation as a director, trustee, officer, employee or agent of another corporation, partnership, joint venture, trust or other enterprise. The Corporation shall pay, to the full extent then required by law, expenses, including attorney’s fees, incurred by a member of the Board of Directors in defending any such action, suit or proceeding as they are incurred, in advance of the final disposition thereof, and may pay, in the same manner and to the full extent then permitted by law, such expenses incurred by any other person. The indemnification and payment of expenses provided hereby shall not be exclusive of, and shall be in addition to, any other rights granted to those seeking indemnification under any law, the Articles of Incorporation, any agreement, vote of shareholders or disinterested members of the Board of Directors, or otherwise, both as to action in official capacities and as to action in another capacity while he or she is a member of the Board of Directors, or an officer, employee or agent of the Corporation, and shall continue as to a person who has ceased to be a member of the Board of Directors, trustee, officer, employee or agent and shall inure to the benefit of the heirs, executors and administrators of such a person.

20

32.Insurance. The Corporation may, to the full extent then permitted by law and authorized by the Board of Directors, purchase and maintain insurance or furnish similar protection, including but not limited to trust funds, letters of credit or self‑insurance, on behalf of or for any persons described in Regulation 31 against any liability asserted against and incurred by any such person in any such capacity, or arising out of his status as such, whether or not the Corporation would have the power to indemnify such person against such liability. Insurance may be purchased from or maintained with a person in which the Corporation has a financial interest.

33.Agreements. The Corporation, upon approval by the Board of Directors, may enter into agreements with any persons whom the Corporation may indemnify under this Code of Regulations or under law and undertake thereby to indemnify such persons and to pay the expenses incurred by them in defending any action, suit or proceeding against them, whether or not the Corporation would have the power under law or this Code of Regulations to indemnify any such person.

GENERAL

34.Fiscal Year. The fiscal year of the Corporation will end on the thirty-first day of December in each calendar year or such other date as may be fixed from time to time by the Board of Directors.

35.Seal. The Board of Directors may adopt a corporate seal and use the same by causing it or a facsimile thereof to be impressed or affixed or reproduced or otherwise.

36.Amendments. Except as otherwise provided by law or by the Articles of Incorporation or this Code of Regulations, these Regulations or any of them may be amended in any respect or repealed at any time at any meeting of shareholders or otherwise by the affirmative vote of the holders of shares entitling them to exercise a majority of the voting power of the Corporation voting together as a single class, provided that any amendment or supplement proposed to be acted upon at any such meeting has been described or referred to in the notice of such meeting. Notwithstanding the foregoing provisions of this Regulation 36, no amendment to Regulations 31, 32, or 33 will be effective to eliminate or diminish the rights of persons specified in those Regulations existing at the time immediately preceding such amendment.

21

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: July 23, 2019

/s/ Charles E. Jones

Charles E. Jones

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

Certification

I, Steven E. Strah, 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: July 23, 2019

/s/ Steven E. Strah

Steven E. Strah

Senior Vice President and Chief Financial Officer

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350

In connection with the Report of FirstEnergy Corp. (“Company”) on Form 10-Q for the period ended June 30, 2019 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/ Steven E. Strah

Steven E. Strah

Senior Vice President and Chief Financial Officer

Date: July 23, 2019

XML

Cover	6 Months Ended
	Jun. 30, 2019 shares
Cover page.
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2019
Document Transition Report	false
Entity File Number	333-21011
Entity Registrant Name	FIRSTENERGY CORP
Entity Incorporation, State or Country Code	OH
Entity Address, Address Line One	76 South Main Street
Entity Address, City or Town	Akron
Entity Address, State or Province	OH
Entity Address, Postal Zip Code	44308
City Area Code	(800)
Local Phone Number	736-3402
Entity Tax Identification Number	34-1843785
Title of 12(b) Security	Common Stock, $0.10 par value
Trading Symbol	FE
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock Shares Outstanding	532,092,829
Amendment Flag	false
Entity Central Index Key	0001031296
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31

XML

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
REVENUES:
Total revenues	[1]	$ 2,516	$ 2,625	$ 5,399	$ 5,487
OPERATING EXPENSES:
Fuel		129	128	260	267
Purchased power		611	697	1,392	1,517
Other operating expenses		606	684	1,385	1,624
Provision for depreciation		309	283	606	560
Amortization (deferral) of regulatory assets, net		37	(107)	42	(255)
General taxes		239	240	500	494
Total operating expenses		1,931	1,925	4,185	4,207
OPERATING INCOME		585	700	1,214	1,280
OTHER INCOME (EXPENSE):
Miscellaneous income, net		80	48	134	115
Interest expense		(259)	(355)	(512)	(603)
Capitalized financing costs		16	16	34	31
Total other expense		(163)	(291)	(344)	(457)
INCOME BEFORE INCOME TAXES		422	409	870	823
INCOME TAXES		81	101	174	334
INCOME FROM CONTINUING OPERATIONS		341	308	696	489
Discontinued operations (Note 3)	[2]	(29)	(9)	(64)	1,179
NET INCOME		312	299	632	1,668
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4)		4	165	9	304
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS		$ 308	$ 134	$ 623	$ 1,364
EARNINGS PER SHARE OF COMMON STOCK (Note 4):
Basic - Continuing Operations (in dollars per share)		$ 0.63	$ 0.30	$ 1.29	$ 0.39
Basic - Discontinued Operations (in dollars per share)		(0.05)	(0.02)	(0.12)	2.47
Basic - Net Income Attributable to Common Stockholders (in dollars per share)		0.58	0.28	1.17	2.86
Diluted - Continuing Operations (in dollars per share)		0.63	0.30	1.29	0.39
Diluted - Discontinued Operations (in dollars per share)		(0.05)	(0.02)	(0.12)	2.46
Diluted - Net Income Attributable to Common Stockholders (in dollars per share)		$ 0.58	$ 0.28	$ 1.17	$ 2.85
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic, in shares		532	477	531	477
Diluted, in shares		533	479	533	478
Excise taxes collected		$ 81	$ 87	$ 183	$ 189
Income tax expense (benefit)		39	(16)	44	(887)
Distribution Services and Retail Generation [Member]
REVENUES:
Total revenues		1,931	2,049	4,240	4,344
Transmission [Member]
REVENUES:
Total revenues		367	336	719	655
Other [Member]
REVENUES:
Total revenues		$ 218	$ 240	$ 440	$ 488

[1] Includes excise and gross receipts tax collections of $81 million and $87 million during the three months ended June 30, 2019 and 2018, respectively, and $183 million and $189 million during the six months ended June 30, 2019 and 2018, respectively.

[2] Net of income tax expense (benefits) of $39 million and $(16) million for the three months ended June 30, 2019 and 2018, respectively, and $44 million and $(887) million for the six months ended June 30, 2019 and 2018, respectively.

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 312	$ 299	$ 632	$ 1,668
OTHER COMPREHENSIVE LOSS:
Pension and OPEB prior service costs	(7)	(19)	(14)	(37)
Amortized losses on derivative hedges	0	2	1	17
Change in unrealized gains on AFS securities	0	0	0	(106)
Other comprehensive loss	(7)	(17)	(13)	(126)
Income tax benefits on other comprehensive loss	(2)	(4)	(3)	(57)
Other comprehensive loss, net of tax	(5)	(13)	(10)	(69)
COMPREHENSIVE INCOME	$ 307	$ 286	$ 622	$ 1,599

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
CURRENT ASSETS:
Cash and cash equivalents	$ 422	$ 367
Restricted cash	52	62
Receivables-
Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018	1,109	1,221
Other, net of allowance for uncollectible accounts of $3 in 2019 and $2 in 2018	218	270
Materials and supplies, at average cost	261	252
Prepaid taxes and other	280	175
Current assets - discontinued operations	44	25
Total current assets	2,386	2,392
PROPERTY, PLANT AND EQUIPMENT:
In service	40,572	39,469
Less — Accumulated provision for depreciation	11,139	10,793
Property, plant and equipment in service net of accumulated provision for depreciation	29,433	28,676
Construction work in progress	1,245	1,235
Total net property, plant and equipment	30,678	29,911
INVESTMENTS:
Nuclear plant decommissioning trusts	863	790
Nuclear fuel disposal trust	265	256
Other	275	253
Total other property and investments	1,403	1,299
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	5,618
Regulatory assets	94	91
Other	705	752
Total deferred charges and other assets	6,417	6,461
Total assets	40,884	40,063
CURRENT LIABILITIES:
Currently payable long-term debt	381	503
Short-term borrowings	1,250	1,250
Accounts payable	810	965
Accrued taxes	416	533
Accrued compensation and benefits	231	318
Collateral	30	39
Other	840	1,026
Total current liabilities	3,983	4,634
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 532,092,829 and 511,915,450 shares outstanding as of June 30, 2019 and December 31, 2018, respectively	53	51
Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - 209,822 and 704,589 shares outstanding as of June 30, 2019 and December 31, 2018, respectively	21	71
Other paid-in capital	11,411	11,530
Accumulated other comprehensive income	31	41
Accumulated deficit	(4,247)	(4,879)
Total stockholders’ equity	7,269	6,814
Long-term debt and other long-term obligations	19,053	17,751
Total capitalization	26,322	24,565
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	2,760	2,502
Retirement benefits	2,414	2,906
Regulatory liabilities	2,584	2,498
Asset retirement obligations	833	812
Adverse power contract liability	79	89
Other	1,909	2,057
Total noncurrent liabilities	10,579	10,864
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
Total liabilities and capitalization	40,884	40,063
Affiliated Companies
Receivables-
Customers, net of allowance for uncollectible accounts of $46 in 2019 and $50 in 2018	0	20
CURRENT LIABILITIES:
Accounts payable	$ 25	$ 0

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Stockholders’ equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	700,000,000	700,000,000
Common stock, shares outstanding	532,092,829	511,915,450
Par Value, in dollars per share	$ 100	$ 100
Preferred stock, shares authorized	5,000,000	5,000,000
Customer
Receivables-
Allowance for uncollectible accounts	$ 46	$ 50
Other
Receivables-
Allowance for uncollectible accounts	3	2
Affiliated Companies
Receivables-
Allowance for uncollectible accounts	$ 937	$ 920
Series A Convertible Preferred Stock
Stockholders’ equity-
Common stock, shares outstanding	200,000	700,000
Preferred stock shares issued	1,616,000	1,616,000
Preferred stock shares outstanding	209,822	704,589

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 632	$ 1,668
Adjustments to reconcile net income to net cash from operating activities-
Loss (gain) on disposal, net of tax (Note 3)	39	(1,239)
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs	702	604
Deferred income taxes and investment tax credits, net	162	327
Retirement benefits, net of payments	(53)	(97)
Pension trust contributions	(500)	(1,250)
Changes in current assets and liabilities-
Receivables	217	20
Materials and supplies	(29)	28
Prepaid taxes and other	(109)	(143)
Accounts payable	(183)	50
Accrued taxes	(117)	(58)
Accrued compensation and benefits	(126)	(76)
Other current liabilities	(16)	(152)
Collateral, net	(8)	(15)
Other	14	45
Net cash provided from (used for) operating activities	625	(288)
New Financing-
Long-term debt	1,950	450
Short-term borrowings, net	0	1,364
Preferred stock issuance	0	1,616
Common stock issuance	0	850
Redemptions and Repayments-
Long-term debt	(757)	(2,251)
Make-whole premiums paid on debt redemptions	0	(89)
Preferred stock dividend payments	(6)	(42)
Common stock dividend payments	(403)	(343)
Other	(28)	(21)
Net cash provided from financing activities	756	1,534
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,228)	(1,307)
Proceeds from asset sales	12	390
Sales of investment securities held in trusts	302	475
Purchases of investment securities held in trusts	(322)	(508)
Notes receivable from affiliated companies	0	(500)
Asset removal costs	(103)	(118)
Other	3	3
Net cash used for investing activities	(1,336)	(1,565)
Net change in cash, cash equivalents, and restricted cash	45	(319)
Cash, cash equivalents, and restricted cash at beginning of period	429	643
Cash, cash equivalents, and restricted cash at end of period	474	324
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction, beneficial conversion feature (Note 4)	0	296
Non-cash transaction, deemed dividend preferred stock (Note 4)	$ 0	$ (261)

XML

Organization and Basis of Presentation

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

ORGANIZATION AND BASIS OF PRESENTATION

ORGANIZATION AND BASIS OF PRESENTATION

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

FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, AE Supply, MP, AGC, PE, WP, and FET and its principal subsidiaries (ATSI, MAIT and TrAIL). In addition, FE holds all of the outstanding equity of other direct subsidiaries including: Allegheny Energy Service Corporation, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPU Nuclear, Inc., and Allegheny Ventures, Inc.

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity.

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 Annual Report on Form 10-K for the year ended December 31, 2018.

FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, 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 and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 10, “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.

Certain prior year amounts have been reclassified to conform to the current year presentation, as discussed in Note 3, “Discontinued Operations.”

FES and FENOC Chapter 11 Filing

On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). As a result of the bankruptcy filings, FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements. Since such time, FE has accounted and will account for its investments in the FES Debtors at fair values of zero. FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. See Note 3, “Discontinued Operations,” for additional information.

On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, and includes the following terms, among others:

• FE will pay certain pre-petition FES Debtors employee-related obligations, which include unfunded pension obligations and other employee benefits.

• FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety

bonds, the BNSF Railway Company/CSX Transportation, Inc. rail settlement guarantee, and the FES Debtors’ unfunded pension obligations.

• A nonconsensual release of all claims against FirstEnergy by the FES Debtors’ creditors, which was subsequently waived pursuant to the Waiver Agreement, discussed below.

• A $225 million cash payment from FirstEnergy.

• A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants.

• Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred. FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

• FirstEnergy agrees to waive all pre-petition claims related to shared services and credit for nine months of the FES Debtors’ shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020.

• FirstEnergy has agreed to fund through its pension plan a pension enhancement, which is subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits (approximately $14 million recognized in 2019).

• FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018 (approximately $52 million was paid in 2018, which amount will be finalized after filing the 2018 Federal tax return).

The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the FES Bankruptcy settlement agreement. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements.

In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy.

As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.

On April 11, 2019, the Bankruptcy Court entered an order denying the FES Debtors’ disclosure statement approval motion. The Bankruptcy Court concluded that the nonconsensual third-party releases proposed under the plan of reorganization and which were a condition under the FES Bankruptcy settlement agreement for FirstEnergy’s benefit, were legally impermissible and rendered the plan unconfirmable. On April 18, 2019, FirstEnergy consented to the waiver of the condition. Additionally, the FES Debtors agreed to provide FirstEnergy with the same third-party release provided in favor of certain other parties in any plan of reorganization and pay FirstEnergy approximately $60 million in cash (paid during the second quarter of 2019) to resolve certain outstanding pension and service charges totaling $87 million, which resulted in FirstEnergy recognizing a $27 million pre-tax charge to income in the first quarter of 2019 ($17 million of which was recognized in continuing operations). Further, the FES Debtors agreed to initiate negotiations with the EPA, OEPA, PA DEP and the NRC to obtain those parties’ cooperation with the FES Debtors’ revised plan of reorganization. FirstEnergy may choose to participate in those negotiations at its option. On May 20, 2019, the Bankruptcy Court approved the waiver and a revised disclosure statement.

Capitalized Financing Costs

For each of the three months ended June 30, 2019 and 2018, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $9 million and $12 million, respectively, of allowance for equity funds used during construction and $7 million and $4 million, respectively, of capitalized interest. For each of the six months ended June 30, 2019 and 2018, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $22 million and $23 million, respectively, of allowance for equity funds used during construction and $12 million and $8 million, respectively, of capitalized interest.

Restricted Cash

Restricted cash primarily relates to the consolidated VIE’s discussed in Note 10, “Variable Interest Entities.” The cash collected from JCP&L, MP, PE and the Ohio Companies’ customers is used to service debt of their respective funding companies.

New Accounting Pronouncements

Recently Adopted Pronouncements

ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires 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, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

XML

Revenue

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.

FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.

The following tables represent a disaggregation of revenue from contracts with customers for the three months ended June 30, 2019 and 2018, by type of service from each reportable segment:

	For the Three Months Ended June 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services	$	1,160	$	—	$	(21	)	$	1,139
Retail generation	806		—		(14		)	792
Wholesale sales	110		—		3			113
Transmission(2)	—		367		—			367
Other	37		—		—			37
Total revenues from contracts with customers	$	2,113	$	367	$	(32	)	$	2,448
ARP	55		—		—			55
Other non-customer revenue	24		5		(16		)	13
Total revenues	$	2,192	$	372	$	(48	)	$	2,516

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $2 million in reductions at Regulated Transmission to revenue related to amounts subject to refund resulting from the Tax Act.

	For the Three Months Ended June 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	1,228	$	—	$	(47	)	$	1,181
Retail generation	882		—		(14		)	868
Wholesale sales	121		—		5			126
Transmission(2)	—		336		—			336
Other	35		—		3			38
Total revenues from contracts with customers	$	2,266	$	336	$	(53	)	$	2,549
ARP	60		—		—			60
Other non-customer revenue	26		5		(15		)	16
Total revenues	$	2,352	$	341	$	(68	)	$	2,625

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $8 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($10 million at Regulated Distribution, partially offset by $2 million subject to recovery at Regulated Transmission).

Other non-customer revenue includes revenue from late payment charges of $9 million for both the three months ended June 30, 2019 and 2018, as well as revenue from derivatives of $3 million and $4 million, for the three months ended June 30, 2019 and 2018, respectively.

The following tables represent a disaggregation of revenue from contracts with customers for the six months ended June 30, 2019 and 2018, by type of service from each reportable segment:

	For the Six Months Ended June 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	2,446	$	—	$	(42	)	$	2,404
Retail generation	1,864		—		(28		)	1,836
Wholesale sales	216		—		7			223
Transmission(2)	—		719		—			719
Other	71		—		1			72
Total revenues from contracts with customers	$	4,597	$	719	$	(62	)	$	5,254
ARP	117		—		—			117
Other non-customer revenue	51		9		(32		)	28
Total revenues	$	4,765	$	728	$	(94	)	$	5,399

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $34 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($27 million at Regulated Distribution and $7 million at Regulated Transmission).

	For the Six Months Ended June 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	2,509	$	—	$	(59	)	$	2,450
Retail generation	1,922		—		(28		)	1,894
Wholesale sales	244		—		10			254
Transmission(2)	—		655		—			655
Other	70		—		4			74
Total revenues from contracts with customers	$	4,745	$	655	$	(73	)	$	5,327
ARP	124		—		—			124
Other non-customer revenue	59		9		(32		)	36
Total revenues	$	4,928	$	664	$	(105	)	$	5,487

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $84 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($82 million at Regulated Distribution and $2 million at Regulated Transmission).

Other non-customer revenue includes revenue from late payment charges of $20 million and $19 million, as well as revenue from derivatives of $5 million and $14 million, for the six months ended June 30, 2019 and 2018, respectively.

Regulated Distribution

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution services to residential, commercial and industrial customers in its service territory. The Utilities are obligated under the regulated construct to deliver power to customers reliably, as it is needed, which creates an implied monthly contract with the end-use customer. See Note 12, “Regulatory Matters,” for additional information on rate recovery mechanisms. Distribution and electric revenues are recognized over time as electricity is distributed and delivered to the customer and the customers consume the electricity immediately as delivery occurs.

Retail generation sales relate to POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland, as well as generation sales in West Virginia that are regulated by the WVPSC. Certain of the Utilities have default service obligations to provide power to non-shopping customers who have elected to continue to receive service under regulated retail

tariffs. The volume of these sales varies depending on the level of shopping that occurs. Supply plans vary by state and by service territory. Default service for the Ohio Companies, Pennsylvania Companies, JCP&L and PE’s Maryland jurisdiction are provided through a competitive procurement process approved by each state’s respective commission. Retail generation revenues are recognized over time as electricity is delivered and consumed immediately by the customer.

The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the three and six months ended June 30, 2019 and 2018, by class:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Revenues by Customer Class	2019		2018		2019		2018
	(In millions)
Residential	$	1,123	$	1,255	$	2,607	$	2,718
Commercial	572		570		1,159		1,150
Industrial	251		262		500		516
Other	20		23		44		47
Total Revenues	$	1,966	$	2,110	$	4,310	$	4,431

Wholesale sales primarily consist of generation and capacity sales into the PJM market from FirstEnergy’s regulated electric generation capacity and NUGs. Certain of the Utilities may also purchase power in the PJM markets to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported gross as either revenues or purchased power on the Consolidated Statements of Income based on whether the entity was a net seller or buyer each hour. Capacity revenues are recognized ratably over the PJM planning year at prices cleared in the annual PJM Reliability Pricing Model Base Residual Auction and incremental auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income. Certain capacity income (bonuses) and charges (penalties) related to the availability of units that have cleared in the auctions are unknown and not recorded in revenue until, and unless, they occur.

The Utilities’ distribution customers are metered on a cycle basis. An estimate of unbilled revenues is calculated to recognize electric service provided from the last meter reading through the end of the month. This estimate includes many factors, among which are historical customer usage, load profiles, estimated weather impacts, customer shopping activity and prices in effect for each class of customer. In each accounting period, the Utilities accrue the estimated unbilled amount as revenue and reverse the related prior period estimate. Customer payments vary by state but are generally due within 30 days.

ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy currently has ARPs in Ohio, primarily under Rider DMR, and in New Jersey.

Regulated Transmission

The Regulated Transmission segment provides transmission infrastructure owned and operated by ATSI, TrAIL, MAIT and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at ATSI, TrAIL and MAIT, as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time.

Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million, which is recognized ratably as revenue over time.

The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the three and six months ended June 30, 2019 and 2018, by transmission owner:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Transmission Owner	2019		2018		2019		2018
	(In millions)
ATSI	$	184	$	167	$	358	$	325
TrAIL	59		63		117		123
MAIT	50		34		99		64
Other	74		72		145		143
Total Revenues	$	367	$	336	$	719	$	655

XML

Discontinued Operations

6 Months Ended

Jun. 30, 2019

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. Prior period results have been reclassified to conform with such presentation as discontinued operations.

FES and FENOC Chapter 11 Bankruptcy Filing

As discussed in Note 1, “Organization and Basis of Presentation,” on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors, as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements, and FirstEnergy has accounted and will account for its investments in the FES Debtors at fair values of zero. In connection with the disposal and the FES Bankruptcy settlement agreement approved by the Bankruptcy Court in September 2018, as further discussed in Note 1, “Organization and Basis of Presentation,” FE recorded an after-tax gain on disposal of $435 million in 2018.

By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company.

FES Borrowings from FE

On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility.

On March 16, 2018, the FES Debtors withdrew from the unregulated companies’ money pool, which included FE, and the FES Debtors. Under the terms of the FES Bankruptcy settlement agreement, FE reinstated $88 million for 2018 estimated payments for NOLs applied against the FES Debtor’s position in the unregulated companies’ money pool prior to their withdrawal on March 16, 2018, which increased the amount the FES Debtors owed FE under the money pool to $92 million. In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of the FES Debtors on March 31, 2018, and given the terms of the FES Bankruptcy settlement agreement, FE fully reserved the $92 million associated with the outstanding unsecured borrowings under the unregulated companies’ money pool and the $102 million associated with the AE Supply unsecured promissory note, under the terms of the FES Bankruptcy settlement agreement, FirstEnergy will release any and all claims against the FES Debtors with respect to the $92 million owed under the unregulated money pool and $102 million unsecured promissory note. For the six months ended June 30, 2019 and 2018, approximately $18 million and $8 million of interest was accrued and subsequently reserved, respectively.

Services Agreements

Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until no later than June 30, 2020, subject to reductions in services if requested by the FES Debtors. Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost. In addition to providing for certain notice requirements and other terms and conditions, the agreement provided for a credit to the FES Debtors in an amount up to $112.5 million for charges incurred for services provided under prior shared services agreements and the amended shared services agreement from April 1, 2018 through December 31, 2018. The entire credit for shared services provided to the FES Debtors ($112.5 million) has been recognized by FE and was included within the loss from discontinued operations as of December 31, 2018. The FES Debtors have paid approximately $67 million and $101 million for shared services for the three and six months ended June 30, 2019, respectively.

Benefit Obligations

FirstEnergy will retain certain obligations for the FES Debtors’ employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a net liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. EDCP and pension/OPEB service costs earned by the FES Debtors’ employees during bankruptcy are billed under the shared services agreement. As FE continues to provide pension benefits to FES/FENOC employees, certain components of pension cost, including the mark to market, are seen as providing ongoing services and are reported in the continuing operations of FE, subsequent to the bankruptcy filing. FE has billed the FES Debtors approximately $9 million and $19 million for their share of pension and OPEB service costs for the three and six months ended June 30, 2019, respectively.

Purchase Power

FES at times provides power through affiliated company power sales to meet a portion of the Utilities’ POLR and default service requirements and provides power to certain affiliates’ facilities. As of June 30, 2019, the Utilities owed FES approximately $7 million related to these purchases. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. The Utilities purchased and recognized in continuing operations approximately $43 million and $71 million of power purchases from FES for the three months ended June 30, 2019 and 2018, respectively, and $126 million and $174 million for the six months ended June 30, 2019 and 2018, respectively.

Income Taxes

For U.S. federal income taxes, until emergence from bankruptcy, the FES Debtors will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return NOL as a future worthless stock deduction. FirstEnergy currently estimates a future worthless stock deduction of approximately $4.8 billion ($1.0 billion, net of tax) and is net of unrecognized tax benefits of $418 million ($88 million, net of tax). The estimated worthless stock deduction is contingent upon the emergence of the FES Debtors from the FES Bankruptcy and such amounts may be materially impacted by future events.

Additionally, discontinued operations include tax expense of approximately $14 million and $20 million for the three months ended June 30, 2019 and 2018, respectively, and $28 million and $36 million for the six months ended June 30, 2019 and 2018, respectively, due to certain aspects of the Tax Act that apply as a result of the FES Debtors remaining a part of FirstEnergy’s consolidated tax return.

See Note 1, “Organization and Basis of Presentation,” for further discussion of the settlement among FirstEnergy, the FES Key Creditor Groups, the FES Debtors and the UCC.

Competitive Generation Asset Sales

FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power Equity Partners III, LP, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply’s interest in the Buchanan Generating facility and approximately 59% of AGC’s interest in Bath County (1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants. On March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility. On May 3, 2018, AE Supply and AGC completed the sale of approximately 59% of AGC’s interest in Bath County. Also, on May 3, 2018, following the closing of the sale by AGC of a portion of its ownership interest in Bath County, AGC completed the redemption of AE Supply’s shares in AGC and AGC became a wholly owned subsidiary of MP.

On March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Power, LLC (formerly Walleye Energy, LLC), for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The Bankruptcy Court approved the sale on July 13, 2018, and the transaction was completed on July 31, 2018.

As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate

Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy’s Run CCR Impoundment Facility, which is not being transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated.

Individually, the AE Supply and BSPC asset sales and Pleasants Power Station transfer did not qualify for reporting as discontinued operations. However, in the aggregate, the transactions were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES’ and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations.

Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the three and six months ended June 30, 2019 and 2018, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Revenues	$	31		$	90		$	85		$	826
Fuel	(20		)	(54		)	(55		)	(218		)
Purchased power	—			(1		)	—			(59		)
Other operating expenses	(16		)	(21		)	(26		)	(390		)
Provision for depreciation	—			(16		)	—			(79		)
General taxes	(5		)	(5		)	(9		)	(28		)
Other income (expense) (1)	10			(18		)	8			(80		)
Income (loss) from discontinued operations, before tax	—			(25		)	3			(28		)
Income tax expense (benefit)	14			(16		)	28			32
Loss from discontinued operations, net of tax	(14		)	(9		)	(25		)	(60		)
Gain (loss) on disposal of FES and FENOC, net of tax	(15		)	—			(39		)	1,239
Income (loss) from discontinued operations	$	(29	)	$	(9	)	$	(64	)	$	1,179

⁽¹⁾ Other income (expense) for the three and six months ended June 30, 2019, reflects the amounts owed to or from FG for its economic interests in Pleasants effective January 1, 2019, as further discussed above.

The gain (loss) on disposal of FES and FENOC recognized in the three and six months ended June 30, 2019 and 2018, consisted of the following:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
(In millions)	2019			2018		2019			2018
Removal of investment in FES and FENOC	$	—		$	—	$	—		$	2,193
Assumption of benefit obligations retained at FE	—			—		—			(820		)
Guarantees and credit support provided by FE	—			—		—			(139		)
Reserve on receivables and allocated pension/OPEB mark-to-market	—			—		—			(914		)
Settlement consideration and services credit	10			—		(23		)	—
Gain (loss) on disposal of FES and FENOC, before tax	10			—		(23		)	320
Income tax benefit (expense), including estimated worthless stock deduction	(25		)	—		(16		)	919
Gain (loss) on disposal of FES and FENOC, net of tax	$	(15	)	$	—	$	(39	)	$	1,239

As of June 30, 2019, and December 31, 2018, material and supplies of $44 million and $25 million, respectively, are included in FirstEnergy’s Consolidated Balance Sheets as Current assets - discontinued operations.

FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the six months ended June 30, 2019 and 2018:

	For the Six Months Ended June 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	$	(64	)	$	1,179
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs	—			80
Unrealized gain on derivative transactions	—			(10		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	—			(23		)
Sales of investment securities held in trusts	—			109
Purchases of investment securities held in trusts	—			(122		)

XML

Earnings Per Share Of Common Stock

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

EARNINGS PER SHARE OF COMMON STOCK

EARNINGS PER SHARE OF COMMON STOCK

The convertible preferred stock issued in January 2018 (see Note 9, “Capitalization”) is considered participating securities since these shares participate in dividends on common stock on an “as-converted” basis. As a result, EPS of common stock is computed using the two-class method required for participating securities.

The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations:

• preferred stock dividends,

• deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and

• an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends.

Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations.

The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend and was fully amortized in 2018.

Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive.

Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.

The following table reconciles basic and diluted EPS of common stock:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Reconciliation of Basic and Diluted EPS of Common Stock	2019			2018			2019			2018
(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	341		$	308		$	696		$	489
Less: Preferred dividends	—			—			(3		)	(43		)
Less: Amortization of beneficial conversion feature	—			(148		)	—			(261		)
Less: Undistributed earnings allocated to preferred stockholders(1)	(5		)	(18		)	(7		)	—
Income from continuing operations available to common stockholders	336			142			686			185
Discontinued operations, net of tax	(29		)	(9		)	(64		)	1,179
Less: Undistributed earnings allocated to preferred stockholders (1)	1			1			1			—
Income (loss) from discontinued operations available to common stockholders	(28		)	(8		)	(63		)	1,179
Income available to common stockholders, basic and diluted	$	308		$	134		$	623		$	1,364
Share Count information:
Weighted average number of basic shares outstanding	532			477			531			477
Assumed exercise of dilutive stock options and awards	1			2			2			1
Weighted average number of diluted shares outstanding	533			479			533			478
Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic	$	0.63		$	0.30		$	1.29		$	0.39
Discontinued operations, basic	(0.05		)	(0.02		)	(0.12		)	2.47
Income available to common stockholders, basic	$	0.58		$	0.28		$	1.17		$	2.86
Income from continuing operations, diluted	$	0.63		$	0.30		$	1.29		$	0.39
Discontinued operations, diluted	(0.05		)	(0.02		)	(0.12		)	2.46
Income available to common stockholders, diluted	$	0.58		$	0.28		$	1.17		$	2.85

⁽¹⁾  Undistributed earnings were not allocated to participating securities for the six months ended June 30, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss.

For the three and six months ended June 30, 2018, 1 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be anti-dilutive to basic EPS from continuing operations. For the three and six months ended June 30, 2019, no shares from stock options and awards were excluded from the calculation of diluted shares outstanding. Also, 8 million shares associated with the assumed conversion of preferred stock were excluded for the three and six months ended June 30, 2019, and 59 million shares for the three and six months ended June 30, 2018, as their inclusion would be anti-dilutive to basic EPS from continuing operations.

XML

Pension and Other Postemployment Benefits

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

PENSION AND OTHER POSTEMPLOYMENT BENEFITS

The components of the consolidated net periodic costs (credits) for pension and OPEB were as follows:

Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended June 30,	2019			2018			2019			2018
	(In millions)
Service costs (1)	$	48		$	56		$	1		$	1
Interest costs (2)	93			93			5			6
Expected return on plan assets (2)	(135		)	(144		)	(7		)	(7		)
Amortization of prior service costs (credits) (2)	2			2			(9		)	(20		)
Special termination costs (2) (3)	(1		)	—			—			—
Net periodic costs (credits), including amounts capitalized	$	7		$	7		$	(10	)	$	(20	)
Net periodic costs (credits), recognized in earnings	$	(14	)	$	(18	)	$	(10	)	$	(21	)
Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Six Months Ended June 30,	2019			2018			2019			2018
	(In millions)
Service costs (1)	$	96		$	112		$	2		$	2
Interest costs (2)	186			186			10			12
Expected return on plan assets (2)	(270		)	(288		)	(14		)	(15		)
Amortization of prior service costs (credits) (2)	4			4			(18		)	(40		)
Special termination costs (2) (3)	14			—			—			—
Net periodic costs (credits), including amounts capitalized	$	30		$	14		$	(20	)	$	(41	)
Net periodic costs (credits), recognized in earnings	$	(8	)	$	(32	)	$	(20	)	$	(42	)

⁽¹⁾ Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income.

⁽²⁾ Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.

⁽³⁾ FirstEnergy has agreed to fund through its pension plan a pension enhancement, which is subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits (approximately $14 million recognized in the first six months of 2019).

Amounts in the tables above include the FES Debtors’ share of the net periodic pension and OPEB costs (credits) of $11 million and $(1) million, respectively, for the three months ended June 30, 2019, and $22 million and $(2) million, respectively, for the six months ended June 30, 2019. The FES Debtors’ share of the net periodic pension and OPEB costs (credits) were $13 million and $(10) million, respectively, for the three months ended June 30, 2018, and $26 million and $(20) million, respectively, for the six months ended June 30, 2018. The 2019 special termination costs associated with FES’ voluntary enhanced retirement package are a component of Discontinued operations in FirstEnergy’s Consolidated Statements of Income. Following the FES Debtors’ voluntary bankruptcy filing, FE has billed the FES Debtors approximately $9 million and $19 million for their share of pension and OPEB service costs for the three and six months ended June 30, 2019, respectively.

On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution, FirstEnergy expects no required contributions through 2021.

XML

Accumulated Other Comprehensive Income

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables show the changes in AOCI for the three and six months ended June 30, 2019 and 2018, for FirstEnergy:

	Gains & Losses on Cash Flow Hedges (1)			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, April 1, 2019	$	(10	)	$	—		$	46		$	36
Amounts reclassified from AOCI	—			—			(7		)	(7		)
Other comprehensive loss	—			—			(7		)	(7		)
Income tax benefits on other comprehensive loss	—			—			(2		)	(2		)
Other comprehensive loss, net of tax	—			—			(5		)	(5		)
AOCI Balance, June 30, 2019	$	(10	)	$	—		$	41		$	31
AOCI Balance, April 1, 2018	$	(15	)	$	—		$	101		$	86
Amounts reclassified from AOCI	2			—			(19		)	(17		)
Other comprehensive income (loss)	2			—			(19		)	(17		)
Income taxes (benefits) on other comprehensive income (loss)	1			—			(5		)	(4		)
Other comprehensive income (loss), net of tax	1			—			(14		)	(13		)
AOCI Balance, June 30, 2018	$	(14	)	$	—		$	87		$	73
	Gains & Losses on Cash Flow Hedges (1)			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, January 1, 2019	$	(11	)	$	—		$	52		$	41
Amounts reclassified from AOCI	1			—			(14		)	(13		)
Other comprehensive income (loss)	1			—			(14		)	(13		)
Income tax benefits on other comprehensive income (loss)	—			—			(3		)	(3		)
Other comprehensive income (loss), net of tax	1			—			(11		)	(10		)
AOCI Balance, June 30, 2019	$	(10	)	$	—		$	41		$	31
AOCI Balance, January 1, 2018	$	(22	)	$	67		$	97		$	142
Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI	4			(1		)	(37		)	(34		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	17			(106		)	(37		)	(126		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(27		)	(57		)
Other comprehensive income (loss), net of tax	8			(67		)	(10		)	(69		)
AOCI Balance, June 30, 2018	$	(14	)	$	—		$	87		$	73

⁽¹⁾ Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance.

The following amounts were reclassified from AOCI for FirstEnergy in the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI(1)	2019			2018			2019			2018 (2)
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	—		$	—		$	—		$	1		Other operating expenses
Long-term debt	—			2			1			3			Interest expense
	—			—			—			(1		)	Income taxes
	$	—		$	2		$	1		$	3		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	—		$	—		$	(1	)	Discontinued operations
Defined benefit pension and OPEB plans
Prior-service costs	$	(7	)	$	(19	)	$	(14	)	$	(37	)	(3)
	2			4			3			9			Income taxes
	$	(5	)	$	(15	)	$	(11	)	$	(28	)	Net of tax
(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
(2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”.
(3)  Prior-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, “Pension and Other Postemployment Benefits.”

XML

Income Taxes

6 Months Ended

Jun. 30, 2019

Income Tax Disclosure [Abstract]

INCOME TAXES

INCOME TAXES

FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2019 and 2018. 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 for the three months ended June 30, 2019 and 2018, was 19.2% and 24.7%, respectively. The decrease in effective tax rate was primarily due to an income tax benefit from the re-measurement of reserves for uncertain tax positions and an increase in the amortization of net excess deferred income taxes. See Note 12, “Regulatory Matters,” for additional details.

FirstEnergy’s effective tax rate for the six months ended June 30, 2019 and 2018, was 20.0% and 40.6%, respectively. In addition to the factors mentioned above, the decrease in the effective tax rate was primarily due to the absence of a one-time charge of approximately $126 million to income tax expense in continuing operations associated with the re-measurement of West Virginia state deferred income taxes, resulting from the legal and financial separation of FES and FENOC from FirstEnergy, which occurred in the first quarter of 2018. See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations.

During the six months ended June 30, 2019, FirstEnergy increased its reserve for uncertain tax positions taken in the current year by approximately $7 million, none of which had an impact on the effective tax rate as the full amount was recorded to discontinued operations. In the three months ended June 30, 2019, FirstEnergy remeasured its reserve for uncertain tax positions, which resulted in a decrease to the reserve of approximately $10 million. As of June 30, 2019, it is reasonably possible that FirstEnergy could record a net decrease to its reserve for uncertain tax positions by approximately $54 million within the next twelve months due to the statute of limitations expiring or resolution with taxing authorities, of which approximately $51 million would impact FirstEnergy’s effective tax rate.

In June 2019, the Internal Revenue Service completed its examination of FirstEnergy’s 2017 federal income tax return and issued a full acceptance letter with no changes or adjustments to FirstEnergy’s taxable income.

XML

Leases

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Leases

LEASES

FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.

FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material.

Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants.

For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of June 30, 2019, the maximum potential loss for these lease agreements at the end of the lease term is approximately $16 million.

Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:

	For the Three Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	8	$	1	$	3	$	12
Finance lease costs:
Amortization of right-of-use assets	4		—		—		4
Interest on lease liabilities	1		1		—		2
Total finance lease cost	5		1		—		6
Total lease cost	$	13	$	2	$	3	$	18

⁽¹⁾ Includes $2 million of short-term lease costs.

	For the Six Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	15	$	3	$	6	$	24
Finance lease costs:
Amortization of right-of-use assets	8		—		1		9
Interest on lease liabilities	2		2		—		4
Total finance lease cost	10		2		1		13
Total lease cost	$	25	$	5	$	7	$	37

⁽¹⁾ Includes $6 million of short-term lease costs.

Supplemental cash flow information related to leases was as follows:

(In millions)	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	7	$	15
Operating cash flows from finance leases	2		3
Finance cash flows from finance leases	5		9
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	20	$	26
Finance leases	1		2

Lease terms and discount rates were as follows:

	As of June 30, 2019
Weighted-average remaining lease terms (years)
Operating leases	8.57
Finance leases	4.75
Weighted-average discount rate (1)
Operating leases	4.91	%
Finance leases	3.45	%

⁽¹⁾ When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.

Supplemental balance sheet information related to leases was as follows:

(In millions)	Financial Statement Line Item	As of June 30, 2019
Assets
Operating lease assets, net of accumulated amortization of $11 million	Deferred charges and other assets	$	188
Finance lease assets, net of accumulated amortization of $89 million	Property, plant and equipment	74
Total leased assets		$	262
Liabilities
Current:
Operating	Other current liabilities	$	31
Finance	Currently payable long-term debt	16
Noncurrent:
Operating	Other noncurrent liabilities	196
Finance	Long-term debt and other long-term obligations	51
Total leased liabilities		$	294

Maturities of lease liabilities as of June 30, 2019, were as follows:

(In millions)	Operating Leases			Finance Leases			Total
2019	$	18		$	11		$	29
2020	38			19			57
2021	36			17			53
2022	35			15			50
2023	32			8			40
2024	27			4			31
Thereafter	99			12			111
Total lease payments (1)	285			86			371
Less imputed interest	(58		)	(19		)	(77		)
Total net present value	$	227		$	67		$	294

⁽¹⁾ Operating lease payments for certain leases are offset by sublease receipts of $13 million over 14 years.

As of June 30, 2019, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $16 million. These leases are expected to commence within the next 18 months with lease terms of 3 to 10 years.

The future minimum capital lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Capital Leases
	(In millions)
2019	$	24
2020	19
2021	16
2022	13
2023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23		)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	$	55

The future minimum operating lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Operating Leases
	(In millions)
2019	$	34
2020	36
2021	34
2022	30
2023	28
Years thereafter	127
Total minimum lease payments	$	289

Leases

LEASES

FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.

FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material.

Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants.

For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of June 30, 2019, the maximum potential loss for these lease agreements at the end of the lease term is approximately $16 million.

Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows:

	For the Three Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	8	$	1	$	3	$	12
Finance lease costs:
Amortization of right-of-use assets	4		—		—		4
Interest on lease liabilities	1		1		—		2
Total finance lease cost	5		1		—		6
Total lease cost	$	13	$	2	$	3	$	18

⁽¹⁾ Includes $2 million of short-term lease costs.

	For the Six Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	15	$	3	$	6	$	24
Finance lease costs:
Amortization of right-of-use assets	8		—		1		9
Interest on lease liabilities	2		2		—		4
Total finance lease cost	10		2		1		13
Total lease cost	$	25	$	5	$	7	$	37

⁽¹⁾ Includes $6 million of short-term lease costs.

Supplemental cash flow information related to leases was as follows:

(In millions)	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	7	$	15
Operating cash flows from finance leases	2		3
Finance cash flows from finance leases	5		9
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	20	$	26
Finance leases	1		2

Lease terms and discount rates were as follows:

	As of June 30, 2019
Weighted-average remaining lease terms (years)
Operating leases	8.57
Finance leases	4.75
Weighted-average discount rate (1)
Operating leases	4.91	%
Finance leases	3.45	%

⁽¹⁾ When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.

Supplemental balance sheet information related to leases was as follows:

(In millions)	Financial Statement Line Item	As of June 30, 2019
Assets
Operating lease assets, net of accumulated amortization of $11 million	Deferred charges and other assets	$	188
Finance lease assets, net of accumulated amortization of $89 million	Property, plant and equipment	74
Total leased assets		$	262
Liabilities
Current:
Operating	Other current liabilities	$	31
Finance	Currently payable long-term debt	16
Noncurrent:
Operating	Other noncurrent liabilities	196
Finance	Long-term debt and other long-term obligations	51
Total leased liabilities		$	294

Maturities of lease liabilities as of June 30, 2019, were as follows:

(In millions)	Operating Leases			Finance Leases			Total
2019	$	18		$	11		$	29
2020	38			19			57
2021	36			17			53
2022	35			15			50
2023	32			8			40
2024	27			4			31
Thereafter	99			12			111
Total lease payments (1)	285			86			371
Less imputed interest	(58		)	(19		)	(77		)
Total net present value	$	227		$	67		$	294

⁽¹⁾ Operating lease payments for certain leases are offset by sublease receipts of $13 million over 14 years.

As of June 30, 2019, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $16 million. These leases are expected to commence within the next 18 months with lease terms of 3 to 10 years.

The future minimum capital lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Capital Leases
	(In millions)
2019	$	24
2020	19
2021	16
2022	13
2023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23		)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	$	55

The future minimum operating lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Operating Leases
	(In millions)
2019	$	34
2020	36
2021	34
2022	30
2023	28
Years thereafter	127
Total minimum lease payments	$	289

XML

Capitalization

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

CAPITALIZATION

CAPITALIZATION

Stockholders’ Equity

The changes in stockholders’ equity for the three and six months ended June 30, 2019 and 2018 for FirstEnergy are included in the following tables:

	Series A Convertible Preferred Stock					Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares		Amount			Shares	Amount
Balance, January 1, 2019	0.7		$	71		512	$	51	$	11,530		$	41		$	(4,879	)	$	6,814
Net income															320			320
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									7									7
Stock Investment Plan and certain share-based benefit plans						1			1									1
Cash dividends declared on common stock									(202		)							(202		)
Cash dividends declared on preferred stock									(3		)							(3		)
Conversion of Series A Convertible Preferred Stock	(0.5	)	(50		)	18	2		48									—
Balance, March 31, 2019	0.2		$	21		531	$	53	$	11,381		$	36		$	(4,559	)	$	6,932
Net income															$	312		$	312
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									9									9
Stock Investment Plan and certain share-based benefit plans						1			21									21
Balance, June 30, 2019	0.2		$	21		532	$	53	$	11,411		$	31		$	(4,247	)	$	7,269

	Series A Convertible Preferred Stock			Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares	Amount		Shares	Amount
Balance, January 1, 2018	—	$	—	445	$	44	$	10,001		$	142		$	(6,262	)	$	3,925
Net income													1,369			1,369
Other comprehensive loss, net of tax										(56		)				(56		)
Stock-based compensation							19									19
Stock Investment Plan and certain share-based benefit plans				2	1		5									6
Cash dividends declared on common stock							(343		)							(343		)
Cash dividends declared on preferred stock							(42		)							(42		)
Stock issuance (1)	1.6	162		30	3		2,297									2,462
Impact of adopting new accounting pronouncements (2)													35			35
Balance, March 31, 2018	1.6	$	162	477	$	48	$	11,937		$	86		$	(4,858	)	$	7,375
Net income													$	299		$	299
Other comprehensive loss, net of tax										(13		)				(13		)
Stock-based compensation							19									19
Stock Investment Plan and certain share-based benefit plans				1			19									19
Balance, June 30, 2018	1.6	$	162	478	$	48	$	11,975		$	73		$	(4,559	)	$	7,699

⁽¹⁾ The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature (BCF), which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend of $261 million for the six months ended June 30, 2018) through the period from the issue date to the first allowable conversion

date (July 22, 2018). There is no net impact to OPIC for the three and six months ended June 30, 2018. Please see below for additional information on the issuance.

⁽²⁾ FirstEnergy adopted ASU 2016-01, “Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities” standard on January 1, 2018, and subsequently recorded a cumulative effect adjustment to retained earnings of $57 million representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. In addition, FirstEnergy adopted ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” and upon adoption, recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018. These amounts are offset in other comprehensive loss and do not have an impact on total stockholders’ equity.

Dividends declared for each share of common stock and as-converted share of preferred stock was $0.38 and $0.72 during the first quarter of 2019 and 2018, respectively. There were no dividends declared during the second quarter of 2019 or 2018.

Preferred Stock

On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in FE. FE entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). FE also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of Common Stock and $847 million of OPIC).

The preferred stock participates in dividends on the common stock on an as-converted basis based on the number of shares of common stock a holder of preferred stock would receive if its shares of preferred stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends are paid at the same time that the dividends on common stock are paid.

Subject to certain exceptions noted below, all shares of preferred stock outstanding on July 22, 2019, were automatically converted. Further, the preferred stock will automatically convert to common stock upon certain events of bankruptcy or liquidation of FE. FE may elect to convert the preferred stock if, at any time, fewer than 323,200 shares of preferred stock are outstanding. However, no shares of preferred stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding common stock. Furthermore, in no event shall FE issue more than 58,964,222 shares of common stock (the Share Cap) in the aggregate upon conversion of the convertible preferred stock. From and after the time at which the aggregate number of shares of common stock issued upon conversion of the preferred stock equals the Share Cap, each holder electing to convert convertible preferred stock will be entitled to receive a cash payment equal to the market value of the common stock such holder does not receive upon conversion.

The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature will be reflected in net income attributable to common stockholders as a deemed dividend. The amount amortized for the six months ended June 30, 2018, was $261 million. The BCF was fully amortized as of December 31, 2018.

The preferred stockholders have limited class voting rights related to the creation of additional securities that are senior or equal with the preferred stock, as well as certain reclassifications and amendments that would affect the rights of the preferred stockholders. The preferred stockholders also have the right to approve issuances of securities convertible or exchangeable for common stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans.

Each share of preferred stock is convertible at the holder’s option into a number of shares of common stock equal to the $1,000 liquidation preference, divided by the conversion price then in effect. As of June 30, 2019, the conversion price in effect was $27.42 per share. The conversion price is subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the common stock, as well as dividends on the common stock paid in common stock and for certain equity issuances below the conversion price then in effect.

During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. Also at the option of the preferred stockholders, 494,767 shares of preferred stock were converted into 18,044,018 shares of common stock in January 2019, resulting in 209,822 shares of preferred stock outstanding and yet to be converted as of June 30, 2019. On July 22, 2019, 28,302 shares of preferred stock automatically converted into 1,032,165 shares of common stock, and 181,520 shares of preferred stock remained unconverted as the holder reached the 4.9% cap as outlined in the terms of the preferred stock. All remaining outstanding shares of preferred stock will be automatically converted on January 22, 2020.

XML

Variable Interest Entities

6 Months Ended

Jun. 30, 2019

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.

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):

• Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly owned limited liability company 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 June 30, 2019, and December 31, 2018, $280 million and $292 million of the phase-in recovery bonds were outstanding, respectively.

• JCP&L Securitization - 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 Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of June 30, 2019, and December 31, 2018, $33 million and $41 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 limited liability company SPEs 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 limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of June 30, 2019, and December 31, 2018, $345 million and $358 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 ventures economic performance. FEV’s ownership interest is subject to the equity method of accounting. As of June 30, 2019, the carrying value of the equity method investment was $14 million.

As discussed in Note 13, “Commitments, Guarantees and Contingencies,” FE is the guarantor under Global Holding’s $300 million term loan facility, which matures in March 2020, and has an outstanding principal balance of $180 million as of June 30, 2019. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to perform its obligations under the provisions of its guarantee, resulting in consolidation of Global Holding by FE.

• PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland, which PJM cancelled in 2012, 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. As of June 30, 2019, the carrying value of the equity method investment was $17 million.

• Purchase Power Agreements - FirstEnergy evaluated its PPAs 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 11 long-term PPAs 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 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 contract that may contain a variable interest during the three months ended June 30, 2019 and 2018, were $30 million and $26 million, respectively, and $61 million and $58 million during the six months ended June 30, 2019 and 2018, respectively.

•

FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, “Discontinued Operations,” FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court. The carrying values of the equity investments in FES and FENOC were zero at June 30, 2019.

XML

Fair Value Measurements

6 Months Ended

Jun. 30, 2019

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 are used to measure fair value.

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. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.

NUG contracts represent PPAs 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 two 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 Intercontinental Exchange, Inc. 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. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.

FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of June 30, 2019, from those used as of December 31, 2018. 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.

The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy:

	June 30, 2019										December 31, 2018
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	439	$	—		$	439		$	—	$	405	$	—		$	405
Derivative assets FTRs(1)	—		—		6			6			—		—		10			10
Equity securities(2)	395		—		—			395			339		—		—			339
Foreign government debt securities	—		16		—			16			—		13		—			13
U.S. government debt securities	—		19		—			19			—		20		—			20
U.S. state debt securities	—		263		—			263			—		250		—			250
Other(3)	422		36		—			458			367		34		—			401
Total assets	$	817	$	773	$	6		$	1,596		$	706	$	722	$	10		$	1,438
Liabilities
Derivative liabilities FTRs(1)	$	—	$	—	$	(4	)	$	(4	)	$	—	$	—	$	(1	)	$	(1	)
Derivative liabilities NUG contracts(1)	—		—		(35		)	(35		)	—		—		(44		)	(44		)
Total liabilities	$	—	$	—	$	(39	)	$	(39	)	$	—	$	—	$	(45	)	$	(45	)
Net assets (liabilities)(4)	$	817	$	773	$	(33	)	$	1,557		$	706	$	722	$	(35	)	$	1,393

⁽¹⁾  Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index.

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

⁽⁴⁾  Excludes $(15) million and $4 million as of June 30, 2019 and December 31, 2018, 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 June 30, 2019, and December 31, 2018:

	NUG Contracts(1)								FTRs(1)
	Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2018 Balance	$	—	$	(79	)	$	(79	)	$	3		$	—		$	3
Unrealized gain	—		2			2			8			1			9
Purchases	—		—			—			5			(5		)	—
Settlements	—		33			33			(6		)	3			(3		)
December 31, 2018 Balance	$	—	$	(44	)	$	(44	)	$	10		$	(1	)	$	9
Unrealized loss	—		(11		)	(11		)	—			—			—
Purchases	—		—			—			6			(4		)	2
Settlements	—		20			20			(10		)	1			(9		)
June 30, 2019 Balance	$	—	$	(35	)	$	(35	)	$	6		$	(4	)	$	2

(1)Contracts are subject to regulatory accounting treatment and changes in market values 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 June 30, 2019:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	2		Model	RTO auction clearing prices	$.50 to $2.70	$1.00	Dollars/MWH
NUG Contracts	$	(35	)	Model	Generation	400 to 776,000	160,000	MWH
					Regional electricity prices	$33.50 to $34.10	$33.80	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 equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.

Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities 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.

Nuclear Decommissioning and Nuclear Fuel Disposal Trusts

JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value.

The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of June 30, 2019, and December 31, 2018:

	June 30, 2019(1)									December 31, 2018(1)
	Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value		Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)
Debt securities	$	730	$	22	$	(15	)	$	737	$	714	$	2	$	(28	)	$	688
Equity securities	$	346	$	48	$	(1	)	$	393	$	339	$	15	$	(16	)	$	338

⁽¹⁾ Excludes $(2) million and $20 million as of June 30, 2019 and December 31, 2018, respectively, of short-term cash investments, taxes, receivables, payables and accrued income.

Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three and six months ended June 30, 2019 and 2018, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Sale Proceeds	$	149		$	175		$	302		$	366
Realized Gains	5			9			12			28
Realized Losses	(5		)	(11		)	(11		)	(27		)
Interest and Dividend Income	11			10			20			20

Other Investments

Other investments include employee benefit trusts, which are primarily invested in corporate-owned life insurance policies, and equity method investments. Other investments were $275 million and $253 million as of June 30, 2019, and December 31, 2018, respectively, and 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, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Carrying Value (1)	$	19,508	$	18,315
Fair Value	$	21,890	$	19,266

⁽¹⁾ The carrying value as of June 30, 2019, includes $1,950 million of debt issuances and $757 million of redemptions that occurred in the first six months of 2019.

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 June 30, 2019, and December 31, 2018.

XML

Regulatory Matters

6 Months Ended

Jun. 30, 2019

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 New Jersey by the NJBPU, in Ohio by the PUCO, 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. Further, if any of the FirstEnergy affiliates were to engage in the construction of significant new transmission facilities, depending on the state, they may be required to obtain state regulatory authorization to site, construct and operate the new transmission facility.

MARYLAND

PE operates under MDPSC approved base rates that were effective as of March 23, 2019. PE also 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 EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE’s 2016 starting goal under this requirement was 0.97%. PE’s approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years’ programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers 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 19, 2018, PE filed a joint petition along with other utility companies, work group stakeholders and the MDPSC electric vehicle work group leader to implement a statewide electric vehicle portfolio in connection with a 2016 MDPSC proceeding to consider an array of issues relating to electric distribution system design, including matters relating to electric vehicles, distributed energy resources, advanced metering infrastructure, energy storage, system planning, rate design, and impacts on low-income customers. PE proposed an electric vehicle charging infrastructure program at a projected total cost of $12 million, to be recovered over a five-year amortization. On January 14, 2019, the MDPSC approved the petition subject to certain reductions in the scope of the program. The MDPSC approved PE’s compliance filing, which implements the pilot program, with minor modifications, on July 3, 2019.

On August 24, 2018, PE filed a base rate case with the MDPSC, which it supplemented on October 22, 2018, to update the partially forecasted test year with a full twelve months of actual data. The rate case requested an annual increase in base distribution rates of $19.7 million, plus creation of an EDIS to fund four enhanced service reliability programs. In responding to discovery, PE revised

its request for an annual increase in base rates to $17.6 million. The proposed rate increase reflected $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On March 22, 2019, the MDPSC issued a final order that approved a rate increase of $6.2 million, approved three of the four EDIS programs for four years, directed PE to file a new depreciation study within 18 months, and ordered the filing of a new base rate case in four years to correspond to the ending of the approved EDIS programs.

NEW JERSEY

JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. JCP&L 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. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates.

On April 18, 2019, pursuant to the May 2018 New Jersey enacted legislation establishing a ZEC program to provide ratepayer funded subsidies of New Jersey nuclear energy supply, the NJBPU approved the implementation of a non-bypassable, irrevocable ZEC charge for all New Jersey electric utility customers, including JCP&L’s customers. Once collected from customers by JCP&L, these funds will be remitted to eligible nuclear energy generators.

In December 2017, the NJBPU issued proposed rules to modify its current CTA policy in base rate cases to: (i) calculate savings using a five-year look back from the beginning of the test year; (ii) allocate savings with 75% retained by the company and 25% allocated to ratepayers; and (iii) exclude transmission assets of electric distribution companies in the savings calculation, which were published in the NJ Register in the first quarter of 2018. JCP&L filed comments supporting the proposed rulemaking. On January 17, 2019, the NJBPU approved the proposed CTA rules with no changes. On May 17, 2019, the Rate Counsel filed an appeal with the Appellate Division of the Superior Court of New Jersey.

Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On January 23, 2019, the NJBPU granted JCP&L’s request to temporarily suspend the procedural schedule in the matter pending settlement discussions. On April 23, 2019, JCP&L filed a Stipulation of Settlement with the NJBPU on behalf of the JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition, which provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020. JCP&L shall seek recovery of the capital investment through an accelerated cost recovery mechanism, provided for in the rules, that includes a revenue adjustment calculation and a process for two rate adjustments. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modifications.

On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. On April 23, 2019, JCP&L filed a Stipulation of Settlement on behalf of the Rate Counsel, NJBPU Staff, and the New Jersey Large Energy Users Coalition with the NJBPU. The terms of the Stipulation of Settlement provide that between January 1, 2018 and March 31, 2018, JCP&L’s refund obligation is estimated to be approximately $7 million, which will be refunded to customers. The Stipulation of Settlement also provides for a base rate reduction of $28.6 million, which was reflected in rates on April 1, 2018, and a Rider Tax Act Adjustment for certain items over a five-year period. On May 8, 2019, the NJBPU issued an order approving the Stipulation of Settlement without modification.

OHIO

The Ohio Companies currently operate under ESP IV through May 31, 2024. ESP IV includes Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years beginning in 2017, with the possibility of a two-year extension and is grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three-year term but the exclusion will be reconsidered upon application for a potential two-year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. On February 1, 2019, the Ohio Companies filed with the PUCO an application requesting a two-year extension of Rider DMR at the same amount and conditions.

ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year 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. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval, which was filed in February 2016, and remains pending as part of the grid modernization settlement described below; (3) a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers’ base distribution rates, which filing the PUCO denied on June 13, 2018.

Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. The Ohio Companies then filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure, which the PUCO denied. In October 2017, the Sierra Club and the OMAEG filed notices of appeal with the SCOH appealing various PUCO entries on their applications for rehearing. The Ohio Companies intervened in the appeal, and additional parties subsequently filed notices of appeal with the SCOH challenging various PUCO entries on their applications for rehearing. On September 26, 2018, the SCOH denied a July 30, 2018 joint motion filed by the OCC, the NOAC, and the OMAEG to stay the portions of the PUCO’s orders and entries under appeal that authorized Rider DMR. On June 19, 2019, the SCOH reversed the PUCO’s determination that Rider DMR is lawful, and remanded the matter to the PUCO with instructions to remove Rider DMR from ESP IV. On July 1, 2019, the Ohio Companies filed a motion with the SCOH requesting reconsideration of the SCOH decision. Also, on July 1, 2019, the Ohio Companies filed revised tariffs with the PUCO providing that while the motion for reconsideration is pending, Rider DMR is being collected subject to refund. On July 2, 2019, the PUCO approved the Ohio Companies’ revised tariffs. On July 11, 2019, various parties filed a memorandum with the SCOH in opposition to the motion for reconsideration.

Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan, as proposed in April 2016, includes 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. In December 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plans with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modifications, which the PUCO denied on January 10, 2018. On March 12, 2018, the Ohio Companies appealed to the SCOH challenging the PUCO’s imposition of a 4% cost cap. Various other parties also appealed challenging various PUCO entries on their applications for rehearing. Oral argument on the appeals was held on February 20, 2019.

On July 23, 2019, Ohio enacted legislation establishing support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, the legislation included a provision implementing a decoupling mechanism for Ohio electric utilities. The legislation also is ending current energy efficiency program mandates on December 31, 2020, provided statewide energy efficiency mandates are achieved as determined by the PUCO. Should the Ohio Companies elect to apply to the PUCO for approval of the decoupling mechanism, it would set residential and commercial base distribution related revenues at the levels collected in 2018. As such, those base distribution revenues would no longer be based on electric consumption, which allows continued support of energy efficiency initiatives while also providing revenue certainty to the Ohio Companies. FirstEnergy is reviewing the potential impacts to customers and the Ohio Companies, and may seek approval for this mechanism later this year.

On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act, discussed below, to flow back to customers. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications.

On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies, effective January 1, 2018, were required to establish a regulatory

liability for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. On October 24, 2018, the PUCO entered an Order in its investigation into the impacts of the Tax Act on Ohio’s utilities directing that by January 1, 2019, all Ohio rate-regulated utility companies, unless ordered otherwise, file applications not for an increase in rates to reflect the impact of the Tax Act on each specific utility’s current rates. On October 30, 2018, the Ohio Companies filed an application to open a new proceeding for the implementation of matters relating to the impact of the Tax Act. As discussed further above, on November 9, 2018, the Ohio Companies filed a settlement agreement that provides for all tax savings associated with the Tax Act to flow back to customers and for the implementation of the first phase of grid modernization plans. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On December 19, 2018, the PUCO upheld its January 10, 2018 ruling that utilities should be required to establish a deferred tax liability, effective January 1, 2018, in response to the Tax Act. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The PUCO conducted a hearing on February 5 and 6, 2019. On July 17, 2019, the PUCO approved the settlement agreement with no material modifications.

The Ohio Companies’ Rider NMB is designed to recover non-market-based transmission-related costs imposed on or charged to the Ohio Companies by FERC or PJM. On December 14, 2018, the Ohio Companies filed an application for a review of their 2019 Rider NMB, including recovery of future Legacy RTEP costs and previously absorbed Legacy RTEP costs, net of refunds received from PJM. On February 27, 2018, the PUCO issued an order directing the Ohio Companies to file revised final tariffs recovering Legacy RTEP costs incurred since May 31, 2018, but excluding recovery of approximately $95 million in Legacy RTEP costs incurred prior to May 31, 2018, net of refunds received from PJM. The PUCO solicited comments on whether the Ohio Companies should be permitted to recover the Legacy RTEP charges incurred prior to May 31, 2018. The Ohio Companies, OCC and OMAEG filed comments on March 29, 2019. The Ohio Companies filed reply comments on April 15, 2019.

On April 19, 2019, OCC filed an application for rehearing alleging Rider DMR revenues should not have been excluded from the determination of the existence of Significantly Excessive Earnings under ESP IV for calendar year 2017 and claiming a $42 million refund is due to OE customers. On May 15, 2019, the PUCO denied OCC’s application for rehearing, and on July 15, 2019, OCC filed a Notice of Appeal with the SCOH. The Ohio Companies intend to contest this appeal but are unable to predict the outcome of this matter.

PENNSYLVANIA

The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. These rates were adjusted for the net impact of the Tax Act, effective March 15, 2018. The net impact of the Tax Act for the period January 1, 2018 through March 14, 2018 must also be separately tracked for treatment in a future rate proceeding. The Pennsylvania Companies operate under DSPs for the June 1, 2019 through May 31, 2023 delivery period, which 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 2019-2023 DSPs, supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW. The PPUC directed a working group to further discuss the implementation of customer assistance program shopping limitations and appropriate scripting for the Pennsylvania Companies’ customer referral programs, and in November 2018, issued a subsequent order to approve additional customer assistance program shopping parameters and further limit the scope of the working group discussion. On December 21, 2018, the PPUC issued a tentative order proposing a model to incorporate the directed shopping restrictions. Comments on the proposal were filed January 22, 2019. On February 28, 2019, the PPUC issued a final order approving the Pennsylvania Companies’ proposal on customer assistance programs shopping limitations and directing script modifications to the Pennsylvania Companies’ customer referral programs. 

Pursuant to Pennsylvania Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies’ Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC’s Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders.

Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate

those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of approximately $45 million by ME, $25 million by PN, $26 million by Penn and $51 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. On May 23, 2019, the PPUC issued an order approving the Pennsylvania Companies’ Modified LTIIPs as filed.

The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ’s previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC’s decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA’s appeal to the Commonwealth Court. On July 11, 2019, the Commonwealth Court issued an opinion and order reversing the PPUC’s decision of April 19, 2018, and remanding the matter to the PPUC to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. The Pennsylvania Companies are reviewing the Commonwealth Court’s opinion and order.

WEST VIRGINIA

MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates under rates approved by the WVPSC effective February 2015. 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.

FERC REGULATORY MATTERS

Under the FPA, FERC regulates rates for interstate wholesale sales, transmission of electric power, accounting and other matters, including construction and operation of hydroelectric projects. With respect to their wholesale services and rates, the Utilities, AE Supply, AGC, and the Transmission Companies are subject to regulation by FERC. FERC regulations require JCP&L, MP, PE, WP and the Transmission Companies to provide open access transmission service at FERC-approved rates, terms and conditions. Transmission facilities of JCP&L, MP, PE, WP and the Transmission Companies are subject to functional control by PJM and transmission service using their transmission facilities is provided by PJM under the PJM Tariff.

FERC regulates the sale of power for resale in interstate commerce in part by granting authority to public utilities to sell wholesale power at market-based rates upon showing that the seller cannot exert market power in generation or transmission or erect barriers to entry into markets. The Utilities and AE Supply each have been authorized by FERC to sell wholesale power in interstate commerce at market-based rates and have a market-based rate tariff on file with FERC, although major wholesale purchases remain subject to regulation by the relevant state commissions.

Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of the facilities that FirstEnergy operates 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 material 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, or obligations to upgrade or build transmission facilities that could have a material adverse effect on its financial condition, results of operations and cash flows.

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 million until 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. In a subsequent order, FERC affirmed its prior ruling that ATSI must submit the cost/benefit analysis. ATSI is evaluating the cost/benefit approach.

FERC Actions on Tax Act

On March 15, 2018, FERC issued a NOI seeking information regarding whether and how FERC should address possible changes to ADIT and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including transmission rates. On November 15, 2018, FERC issued a NOPR suggesting mechanisms to revise transmission rates to address the Tax Act’s effect on ADIT. Specifically, FERC proposed utilities with transmission formula rates would include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate bases; (ii) raise or lower their income tax allowances by any amortized excess or deficient ADIT; and (iii) incorporate a new permanent worksheet into their rates that will annually track information related to excess or deficient ADIT. Utilities with transmission stated rates would determine the amount of excess and deferred income tax caused by the reduced federal corporate income tax rate and return or recover this amount to or from customers. To assist with implementation of the proposed rule, FERC also issued on November 15, 2018, a policy statement providing accounting and ratemaking guidance for treatment of ADIT for all FERC-jurisdictional public utilities. The policy statement also addresses the accounting and ratemaking treatment of ADIT following the sale or retirement of an asset after December 31, 2017. FESC, on behalf of its affiliated transmission owners, supported comments submitted by EEI requesting additional clarification on the ratemaking and accounting treatment for ADIT in formula and stated transmission rates. FERC’s final rule remains pending.

Transmission ROE Methodology

In June 2014, FERC issued Opinion No. 531 revising its approach for calculating the discounted cash flow element of FERC’s ROE methodology and announcing the potential for a qualitative adjustment to the ROE methodology results. Parties appealed to the D.C. Circuit, and on April 14, 2017, that court issued a decision vacating FERC’s order and remanding the matter to FERC for further review. On October 16, 2018, FERC issued its order on remand, in which it proposed a revised ROE methodology. Specifically, in complaint proceedings alleging that an existing ROE is not just and reasonable, FERC proposes to rely on three financial models-discounted cash flow, capital-asset pricing, and expected earnings to establish a composite zone of reasonableness to identify a range of just and reasonable ROEs. FERC then will utilize the transmission utility’s risk relative to other utilities within that zone of reasonableness to assign the transmission utility to one of three quartiles within the zone. FERC would take no further action (i.e., dismiss the complaint) if the existing ROE falls within the identified quartile. However, if the ROE falls outside the quartile, FERC would deem the existing ROE presumptively unjust and unreasonable and would determine the replacement ROE. FERC would add a fourth financial model risk premium to the analysis to calculate a ROE based on the average point of central tendency for each of the four financial models. On March 21, 2019, FERC established NOIs to collect industry and stakeholder comments on the revised ROE methodology that is described in the October 16, 2018 decision, and also whether to make changes to FERC’s existing policies and practices for awarding transmission rates incentives. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis. FirstEnergy currently is participating through various trade groups in the NOI comments, and any subsequent rulemaking and other proceedings.

XML

Commitments, Guarantees and Contingencies

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

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

As of June 30, 2019, outstanding guarantees and other assurances aggregated approximately $1.7 billion, consisting of guarantees on behalf of FES and FENOC ($350 million), parental guarantees on behalf of its consolidated subsidiaries’ guarantees ($1 billion), other guarantees ($180 million) and other assurances ($140 million). FirstEnergy has also committed to provide additional guarantees to the FES Debtors for certain retained environmental liabilities of AE Supply related to the Pleasants Power Station and McElroy’s Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy.

COLLATERAL AND CONTINGENT-RELATED FEATURES

Certain bilateral agreements 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 ratings 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 entered into by FE and its subsidiaries have margining provisions that require posting of collateral. The Utilities have posted collateral totaling $2 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. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2019:

Potential Collateral Obligations		AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating		$	1	$	—	$	—	$	1
Upon Further Downgrade		—		43		—		43
Surety Bonds (Collateralized Amount)(1)		1		59		246		306
Total Exposure from Contractual Obligations		$	2	$	102	$	246	$	350

⁽¹⁾  Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global Holding’s outstanding principal balance is $180 million as of June 30, 2019. 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 respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral.

ENVIRONMENTAL MATTERS

Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality, hazardous and solid waste disposal, and other environmental matters. While FirstEnergy’s environmental policies and procedures are designed to achieve compliance with applicable environmental laws and regulations, such laws and regulations are subject to periodic review and potential revision by the implementing agencies. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof may materially impact its business, results of operations, cash flows and financial condition.

Clean Air Act

FirstEnergy complies with SO₂ and NOx emission reduction requirements under the CAA and SIP(s) by burning lower-sulfur fuel, utilizing combustion controls and post-combustion controls and/or using emission allowances.

CSAPR requires reductions of NOx and SO₂ emissions in two phases (2015 and 2017), ultimately capping SO₂ emissions in affected states to 2.4 million tons annually and NOx emissions to 1.2 million tons annually. CSAPR allows trading of NOx and SO₂ emission allowances between power plants located in the same state and interstate trading of NOx and SO₂ emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO₂ emissions from power plants in 13 states, including Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry’s bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may materially impact FirstEnergy’s operations, cash flows and financial condition.

In February 2019, the EPA announced its final decision to retain without changes the NAAQS for SO₂, specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of June 30, 2019, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA.

In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility’s NOx emissions significantly contribute to Delaware’s inability to attain the ozone NAAQS. The petition sought a short-term NOx

emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland’s inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland’s petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 9 states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018 but has not taken any further action. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

Climate Change

There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation.

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 GHG emissions by 26 to 28 percent below 2005 levels by 2025. In 2015, FirstEnergy set a goal of reducing company-wide CO₂ emissions by at least 90 percent below 2005 levels by 2045. As of December 31, 2018, FirstEnergy has reduced its CO₂ emissions by approximately 62 percent. In September 2016, the U.S. 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’s non-binding obligations to limit global warming to below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. 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.

In December 2009, the EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act” 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 CPP regulations in August 2015 to reduce CO₂ emissions from existing fossil fuel-fired EGUs and finalized separate regulations imposing CO₂ emission limits for new, modified, and reconstructed fossil fuel fired EGUs. Numerous states and private parties filed appeals and motions to stay the CPP with the D.C. Circuit in October 2015. 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. On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material.

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 facilities. 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. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material.

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 phase-in as permits are renewed on a five-year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and on September 18, 2017, the EPA postponed certain compliance deadlines for two years. 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 operations may result.

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 CCRs, such as coal ash, were exempted from hazardous waste disposal requirements pending the EPA’s evaluation of the need for future regulation.

In April 2015, the EPA finalized regulations for the disposal of CCRs (non-hazardous), establishing national standards for 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. On September 13, 2017, the EPA announced that it would reconsider certain provisions of the final regulations. On July 17, 2018, the EPA Administrator signed a final rule extending the deadline for certain CCR facilities to cease disposal and commence closure activities, as well as, establishing less stringent groundwater monitoring and protection requirements. On August 21, 2018, the D.C. Circuit remanded sections of the CCR Rule to the EPA to provide additional safeguards for unlined CCR impoundments that are more protective of human health and the environment.

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 of June 30, 2019, based on estimates of the total costs of cleanup, FirstEnergy’s proportionate responsibility for such costs and the financial ability of other unaffiliated entities to pay. Total liabilities of approximately $119 million have been accrued through June 30, 2019. Included in the total are accrued liabilities of approximately $83 million for environmental remediation of former MGP and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE 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, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of June 30, 2019, JCP&L, ME and PN had in total approximately $863 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN 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.

On May 10, 2019, FirstEnergy signed a non-binding term sheet with EnergySolutions, LLC. concerning the transfer of TMI-2. This transfer of TMI-2 to EnergySolutions, LLC. will also include the transfer of the external trusts for the decommissioning and environmental remediation of TMI-2 and related liabilities of approximately $900 million as of June 30, 2019. The term sheet also contemplates EnergySolutions, LLC. decommissioning of TMI-2. EnergySolutions, LLC. nuclear decommissioning experience includes the nearly completed Zion Nuclear Power Station in Illinois and the La Crosse Boiling Water Reactor in Wisconsin. There can be no assurance that a definitive agreement will be finalized by the parties and subsequently approved by the NRC and, even if approved, whether the conditions to the closing of the transfer will be satisfied.

FES Bankruptcy

On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, “Discontinued Operations,” for additional information.

Other Legal Matters

There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy’s normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 12, “Regulatory Matters.”

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 FE 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 FE’s or its subsidiaries’ financial condition, results of operations and cash flows.

XML

Segment Information

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

SEGMENT INFORMATION

SEGMENT INFORMATION

Regulated Distribution and Regulated Transmission are FirstEnergy’s reportable segments.

On March 31, 2018, as discussed in Note 3, “Discontinued Operations,” FirstEnergy deconsolidated FES and FENOC and presented FES, FENOC, BSPC and a portion of AE Supply, representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, as discontinued operations in FirstEnergy’s consolidated financial statements resulting from actions taken as part of the strategic review to exit commodity-exposed generation. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes.

The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies, serving approximately six million customers within 65,000 square miles of Ohio, Pennsylvania, West Virginia, Maryland, New Jersey and New York, and purchases power for its POLR, SOS, SSO and default service requirements in Ohio, Pennsylvania, New Jersey and Maryland. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. The segment’s results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs.

The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy’s utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment’s revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at certain of JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment’s results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy’s transmission facilities.

The Corporate/Other segment reflects corporate support not charged to FE’s subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are shown separately in the following table of Segment Financial Information. As of June 30, 2019, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of June 30, 2019, Corporate/Other had approximately $7.1 billion of FE holding company debt.

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below:

Segment Financial Information

For the Three Months Ended	Regulated Distribution			Regulated Transmission		Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)
June 30, 2019
External revenues	$	2,145		$	368	$	3		$	—		$	2,516
Internal revenues	47			4		—			(51		)	—
Total revenues	$	2,192		$	372	$	3		$	(51	)	$	2,516
Depreciation	220			71		1			17			309
Amortization of regulatory assets, net	34			3		—			—			37
Miscellaneous income, net	46			4		38			(8		)	80
Interest expense	124			48		95			(8		)	259
Income taxes (benefits)	67			30		(16		)	—			81
Income (loss) from continuing operations	258			116		(33		)	—			341
Property additions	354			300		20			—			674
June 30, 2018
External revenues	$	2,285		$	336	$	4		$	—		$	2,625
Internal revenues	67			5		7			(79		)	—
Total revenues	$	2,352		$	341	$	11		$	(79	)	$	2,625
Depreciation	200			62		3			18			283
Deferral of regulatory assets, net	(107		)	—		—			—			(107		)
Miscellaneous income (expense), net	56			3		(1		)	(10		)	48
Interest expense	129			42		194			(10		)	355
Income taxes (benefits)	138			38		(75		)	—			101
Income (loss) from continuing operations	377			104		(173		)	—			308
Property additions	391			282		44			7			724
For the Six Months Ended
June 30, 2019
External revenues	$	4,671		$	720	$	8		$	—		$	5,399
Internal revenues	94			8		—			(102		)	—
Revenues	$	4,765		$	728	$	8		$	(102	)	$	5,399
Depreciation	429			140		3			34			606
Amortization of regulatory assets, net	37			5		—			—			42
Miscellaneous income, net	92			8		49			(15		)	134
Interest expense	246			93		188			(15		)	512
Income taxes (benefits)	156			61		(43		)	—			174
Income (loss) from continuing operations	587			220		(111		)	—			696
Property additions	672			531		25			—			1,228
June 30, 2018
External revenues	$	4,823		$	655	$	9		$	—		$	5,487
Internal revenues	105			9		13			(127		)	—
Revenues	$	4,928		$	664	$	22		$	(127	)	$	5,487
Depreciation	396			123		5			36			560
Amortization (deferral) of regulatory assets, net	(259		)	4		—			—			(255		)
Miscellaneous income, net	112			7		15			(19		)	115
Interest expense	257			81		284			(19		)	603
Income taxes	231			70		33			—			334
Income (loss) from continuing operations	699			203		(413		)	—			489
Property additions	655			574		55			23			1,307
As of June 30, 2019
Total assets	$	29,240		$	11,070	$	574		$	—		$	40,884
Total goodwill	5,004			614		—			—			5,618
As of December 31, 2018
Total assets	$	28,690		$	10,404	$	969		$	—		$	40,063
Total goodwill	5,004			614		—			—			5,618

XML

Organization and Basis of Presentation (Policies)

6 Months Ended

Jun. 30, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

These interim financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and disclosures normally included in financial statements and notes prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These interim financial statements should be read in conjunction with the financial statements and notes included in the Annual Report on Form 10-K for the year ended December 31, 2018.

FE and its subsidiaries follow GAAP and comply with the related regulations, orders, policies and practices prescribed by the SEC, FERC, and, as applicable, the NRC, 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 and permitted pursuant to GAAP. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 10, “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

Recently Adopted Pronouncements

ASU 2016-02, "Leases (Topic 842)" (Issued February 2016 and subsequently updated to address implementation questions): The new guidance requires 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, as well as new qualitative and quantitative disclosures. FirstEnergy implemented a third-party software tool that assisted with the initial adoption and will assist with ongoing compliance. FirstEnergy chose to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by $186 million, with no impact to results of operations or cash flows. See Note 8, "Leases," for additional information on FirstEnergy's leases.

Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB has not yet been adopted. Unless otherwise indicated, FirstEnergy is currently assessing the impact such guidance may have on its financial statements and disclosures, as well as the potential to early adopt where applicable. FirstEnergy has assessed other FASB issuances of new standards not described below based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting.

ASU 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

ASU 2018-15, "Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract" (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.

Revenue

FirstEnergy accounts for revenues from contracts with customers under ASC 606, “Revenue from Contracts with Customers.” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances are excluded from recognition in the income statement and instead recorded through the balance sheet. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations.

FirstEnergy’s revenues are primarily derived from electric service provided by the Utilities and Transmission Companies.

Earnings Per Share

The convertible preferred stock issued in January 2018 (see Note 9, “Capitalization”) is considered participating securities since these shares participate in dividends on common stock on an “as-converted” basis. As a result, EPS of common stock is computed using the two-class method required for participating securities.

The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations:

• preferred stock dividends,

• deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and

• an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends.

Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations.

The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million, represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature was reflected in net income attributable to common stockholders as a deemed dividend and was fully amortized in 2018.

Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive.

Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible shares of preferred stock. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred stock dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.

Leases

FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancelable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor.

FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material.

Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term, unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants.

For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term.

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.

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.

Investment Policy

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 equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes.

Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities 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.

Long-Term Debt and Other Long-Term Obligations

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.

XML

Revenue (Tables)

6 Months Ended

Jun. 30, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

The following table represents a disaggregation of revenue from contracts with regulated transmission customers by transmission owner for the three and six months ended June 30, 2019 and 2018, by transmission owner:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Transmission Owner	2019		2018		2019		2018
	(In millions)
ATSI	$	184	$	167	$	358	$	325
TrAIL	59		63		117		123
MAIT	50		34		99		64
Other	74		72		145		143
Total Revenues	$	367	$	336	$	719	$	655

The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the three and six months ended June 30, 2019 and 2018, by class:

	For the Three Months Ended June 30,				For the Six Months Ended June 30,
Revenues by Customer Class	2019		2018		2019		2018
	(In millions)
Residential	$	1,123	$	1,255	$	2,607	$	2,718
Commercial	572		570		1,159		1,150
Industrial	251		262		500		516
Other	20		23		44		47
Total Revenues	$	1,966	$	2,110	$	4,310	$	4,431

The following tables represent a disaggregation of revenue from contracts with customers for the three months ended June 30, 2019 and 2018, by type of service from each reportable segment:

	For the Three Months Ended June 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services	$	1,160	$	—	$	(21	)	$	1,139
Retail generation	806		—		(14		)	792
Wholesale sales	110		—		3			113
Transmission(2)	—		367		—			367
Other	37		—		—			37
Total revenues from contracts with customers	$	2,113	$	367	$	(32	)	$	2,448
ARP	55		—		—			55
Other non-customer revenue	24		5		(16		)	13
Total revenues	$	2,192	$	372	$	(48	)	$	2,516

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $2 million in reductions at Regulated Transmission to revenue related to amounts subject to refund resulting from the Tax Act.

	For the Three Months Ended June 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	1,228	$	—	$	(47	)	$	1,181
Retail generation	882		—		(14		)	868
Wholesale sales	121		—		5			126
Transmission(2)	—		336		—			336
Other	35		—		3			38
Total revenues from contracts with customers	$	2,266	$	336	$	(53	)	$	2,549
ARP	60		—		—			60
Other non-customer revenue	26		5		(15		)	16
Total revenues	$	2,352	$	341	$	(68	)	$	2,625

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $8 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act ($10 million at Regulated Distribution, partially offset by $2 million subject to recovery at Regulated Transmission).

Other non-customer revenue includes revenue from late payment charges of $9 million for both the three months ended June 30, 2019 and 2018, as well as revenue from derivatives of $3 million and $4 million, for the three months ended June 30, 2019 and 2018, respectively.

The following tables represent a disaggregation of revenue from contracts with customers for the six months ended June 30, 2019 and 2018, by type of service from each reportable segment:

	For the Six Months Ended June 30, 2019
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	2,446	$	—	$	(42	)	$	2,404
Retail generation	1,864		—		(28		)	1,836
Wholesale sales	216		—		7			223
Transmission(2)	—		719		—			719
Other	71		—		1			72
Total revenues from contracts with customers	$	4,597	$	719	$	(62	)	$	5,254
ARP	117		—		—			117
Other non-customer revenue	51		9		(32		)	28
Total revenues	$	4,765	$	728	$	(94	)	$	5,399

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $34 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($27 million at Regulated Distribution and $7 million at Regulated Transmission).

	For the Six Months Ended June 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)			Total
	(In millions)
Distribution services(2)	$	2,509	$	—	$	(59	)	$	2,450
Retail generation	1,922		—		(28		)	1,894
Wholesale sales	244		—		10			254
Transmission(2)	—		655		—			655
Other	70		—		4			74
Total revenues from contracts with customers	$	4,745	$	655	$	(73	)	$	5,327
ARP	124		—		—			124
Other non-customer revenue	59		9		(32		)	36
Total revenues	$	4,928	$	664	$	(105	)	$	5,487

⁽¹⁾ Includes eliminations and reconciling adjustments of inter-segment revenues.

⁽²⁾ Includes $84 million in reductions to revenue related to amounts subject to refund resulting from the Tax Act ($82 million at Regulated Distribution and $2 million at Regulated Transmission).

XML

Discontinued Operations (Tables)

6 Months Ended

Jun. 30, 2019

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations

Summarized results of discontinued operations for the three and six months ended June 30, 2019 and 2018, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(In millions)	2019			2018			2019			2018
Revenues	$	31		$	90		$	85		$	826
Fuel	(20		)	(54		)	(55		)	(218		)
Purchased power	—			(1		)	—			(59		)
Other operating expenses	(16		)	(21		)	(26		)	(390		)
Provision for depreciation	—			(16		)	—			(79		)
General taxes	(5		)	(5		)	(9		)	(28		)
Other income (expense) (1)	10			(18		)	8			(80		)
Income (loss) from discontinued operations, before tax	—			(25		)	3			(28		)
Income tax expense (benefit)	14			(16		)	28			32
Loss from discontinued operations, net of tax	(14		)	(9		)	(25		)	(60		)
Gain (loss) on disposal of FES and FENOC, net of tax	(15		)	—			(39		)	1,239
Income (loss) from discontinued operations	$	(29	)	$	(9	)	$	(64	)	$	1,179

⁽¹⁾ Other income (expense) for the three and six months ended June 30, 2019, reflects the amounts owed to or from FG for its economic interests in Pleasants effective January 1, 2019, as further discussed above.

The gain (loss) on disposal of FES and FENOC recognized in the three and six months ended June 30, 2019 and 2018, consisted of the following:

	For the Three Months Ended June 30,					For the Six Months Ended June 30,
(In millions)	2019			2018		2019			2018
Removal of investment in FES and FENOC	$	—		$	—	$	—		$	2,193
Assumption of benefit obligations retained at FE	—			—		—			(820		)
Guarantees and credit support provided by FE	—			—		—			(139		)
Reserve on receivables and allocated pension/OPEB mark-to-market	—			—		—			(914		)
Settlement consideration and services credit	10			—		(23		)	—
Gain (loss) on disposal of FES and FENOC, before tax	10			—		(23		)	320
Income tax benefit (expense), including estimated worthless stock deduction	(25		)	—		(16		)	919
Gain (loss) on disposal of FES and FENOC, net of tax	$	(15	)	$	—	$	(39	)	$	1,239

As of June 30, 2019, and December 31, 2018, material and supplies of $44 million and $25 million, respectively, are included in FirstEnergy’s Consolidated Balance Sheets as Current assets - discontinued operations.

FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the six months ended June 30, 2019 and 2018:

	For the Six Months Ended June 30,
(In millions)	2019			2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	$	(64	)	$	1,179
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs	—			80
Unrealized gain on derivative transactions	—			(10		)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	—			(23		)
Sales of investment securities held in trusts	—			109
Purchases of investment securities held in trusts	—			(122		)

XML

Earnings Per Share Of Common Stock (Tables)

6 Months Ended

Jun. 30, 2019

Earnings Per Share [Abstract]

Reconciliation of Basic and Diluted Earnings Per Share

The following table reconciles basic and diluted EPS of common stock:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Reconciliation of Basic and Diluted EPS of Common Stock	2019			2018			2019			2018
(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	341		$	308		$	696		$	489
Less: Preferred dividends	—			—			(3		)	(43		)
Less: Amortization of beneficial conversion feature	—			(148		)	—			(261		)
Less: Undistributed earnings allocated to preferred stockholders(1)	(5		)	(18		)	(7		)	—
Income from continuing operations available to common stockholders	336			142			686			185
Discontinued operations, net of tax	(29		)	(9		)	(64		)	1,179
Less: Undistributed earnings allocated to preferred stockholders (1)	1			1			1			—
Income (loss) from discontinued operations available to common stockholders	(28		)	(8		)	(63		)	1,179
Income available to common stockholders, basic and diluted	$	308		$	134		$	623		$	1,364
Share Count information:
Weighted average number of basic shares outstanding	532			477			531			477
Assumed exercise of dilutive stock options and awards	1			2			2			1
Weighted average number of diluted shares outstanding	533			479			533			478
Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic	$	0.63		$	0.30		$	1.29		$	0.39
Discontinued operations, basic	(0.05		)	(0.02		)	(0.12		)	2.47
Income available to common stockholders, basic	$	0.58		$	0.28		$	1.17		$	2.86
Income from continuing operations, diluted	$	0.63		$	0.30		$	1.29		$	0.39
Discontinued operations, diluted	(0.05		)	(0.02		)	(0.12		)	2.46
Income available to common stockholders, diluted	$	0.58		$	0.28		$	1.17		$	2.85

⁽¹⁾  Undistributed earnings were not allocated to participating securities for the six months ended June 30, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss.

XML

Pension and Other Postemployment Benefits (Tables)

6 Months Ended

Jun. 30, 2019

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Costs

The components of the consolidated net periodic costs (credits) for pension and OPEB were as follows:

Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended June 30,	2019			2018			2019			2018
	(In millions)
Service costs (1)	$	48		$	56		$	1		$	1
Interest costs (2)	93			93			5			6
Expected return on plan assets (2)	(135		)	(144		)	(7		)	(7		)
Amortization of prior service costs (credits) (2)	2			2			(9		)	(20		)
Special termination costs (2) (3)	(1		)	—			—			—
Net periodic costs (credits), including amounts capitalized	$	7		$	7		$	(10	)	$	(20	)
Net periodic costs (credits), recognized in earnings	$	(14	)	$	(18	)	$	(10	)	$	(21	)
Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Six Months Ended June 30,	2019			2018			2019			2018
	(In millions)
Service costs (1)	$	96		$	112		$	2		$	2
Interest costs (2)	186			186			10			12
Expected return on plan assets (2)	(270		)	(288		)	(14		)	(15		)
Amortization of prior service costs (credits) (2)	4			4			(18		)	(40		)
Special termination costs (2) (3)	14			—			—			—
Net periodic costs (credits), including amounts capitalized	$	30		$	14		$	(20	)	$	(41	)
Net periodic costs (credits), recognized in earnings	$	(8	)	$	(32	)	$	(20	)	$	(42	)

⁽¹⁾ Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income.

⁽²⁾ Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.

⁽³⁾ FirstEnergy has agreed to fund through its pension plan a pension enhancement, which is subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits (approximately $14 million recognized in the first six months of 2019).

XML

Accumulated Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2019

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income

The following tables show the changes in AOCI for the three and six months ended June 30, 2019 and 2018, for FirstEnergy:

	Gains & Losses on Cash Flow Hedges (1)			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, April 1, 2019	$	(10	)	$	—		$	46		$	36
Amounts reclassified from AOCI	—			—			(7		)	(7		)
Other comprehensive loss	—			—			(7		)	(7		)
Income tax benefits on other comprehensive loss	—			—			(2		)	(2		)
Other comprehensive loss, net of tax	—			—			(5		)	(5		)
AOCI Balance, June 30, 2019	$	(10	)	$	—		$	41		$	31
AOCI Balance, April 1, 2018	$	(15	)	$	—		$	101		$	86
Amounts reclassified from AOCI	2			—			(19		)	(17		)
Other comprehensive income (loss)	2			—			(19		)	(17		)
Income taxes (benefits) on other comprehensive income (loss)	1			—			(5		)	(4		)
Other comprehensive income (loss), net of tax	1			—			(14		)	(13		)
AOCI Balance, June 30, 2018	$	(14	)	$	—		$	87		$	73
	Gains & Losses on Cash Flow Hedges (1)			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance, January 1, 2019	$	(11	)	$	—		$	52		$	41
Amounts reclassified from AOCI	1			—			(14		)	(13		)
Other comprehensive income (loss)	1			—			(14		)	(13		)
Income tax benefits on other comprehensive income (loss)	—			—			(3		)	(3		)
Other comprehensive income (loss), net of tax	1			—			(11		)	(10		)
AOCI Balance, June 30, 2019	$	(10	)	$	—		$	41		$	31
AOCI Balance, January 1, 2018	$	(22	)	$	67		$	97		$	142
Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI	4			(1		)	(37		)	(34		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	17			(106		)	(37		)	(126		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(27		)	(57		)
Other comprehensive income (loss), net of tax	8			(67		)	(10		)	(69		)
AOCI Balance, June 30, 2018	$	(14	)	$	—		$	87		$	73

⁽¹⁾ Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance.

Reclassification out of Accumulated Other Comprehensive Income

The following amounts were reclassified from AOCI for FirstEnergy in the three and six months ended June 30, 2019 and 2018:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,						Affected Line Item in Consolidated Statements of Income
Reclassifications from AOCI(1)	2019			2018			2019			2018 (2)
	(In millions)
Gains & losses on cash flow hedges
Commodity contracts	$	—		$	—		$	—		$	1		Other operating expenses
Long-term debt	—			2			1			3			Interest expense
	—			—			—			(1		)	Income taxes
	$	—		$	2		$	1		$	3		Net of tax
Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	—		$	—		$	(1	)	Discontinued operations
Defined benefit pension and OPEB plans
Prior-service costs	$	(7	)	$	(19	)	$	(14	)	$	(37	)	(3)
	2			4			3			9			Income taxes
	$	(5	)	$	(15	)	$	(11	)	$	(28	)	Net of tax
(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
(2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income”.
(3)  Prior-service costs are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, “Pension and Other Postemployment Benefits.”

XML

Leases (Tables)

6 Months Ended

Jun. 30, 2019

Leases [Abstract]

Components of Lease Expense

The components of lease expense were as follows:

	For the Three Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	8	$	1	$	3	$	12
Finance lease costs:
Amortization of right-of-use assets	4		—		—		4
Interest on lease liabilities	1		1		—		2
Total finance lease cost	5		1		—		6
Total lease cost	$	13	$	2	$	3	$	18

⁽¹⁾ Includes $2 million of short-term lease costs.

	For the Six Months Ended June 30, 2019
(In millions)	Vehicles		Buildings		Other		Total
Operating lease costs (1)	$	15	$	3	$	6	$	24
Finance lease costs:
Amortization of right-of-use assets	8		—		1		9
Interest on lease liabilities	2		2		—		4
Total finance lease cost	10		2		1		13
Total lease cost	$	25	$	5	$	7	$	37

⁽¹⁾ Includes $6 million of short-term lease costs.

Supplemental cash flow information related to leases was as follows:

(In millions)	For the Three Months Ended June 30, 2019		For the Six Months Ended June 30, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	7	$	15
Operating cash flows from finance leases	2		3
Finance cash flows from finance leases	5		9
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	$	20	$	26
Finance leases	1		2

Lease terms and discount rates were as follows:

	As of June 30, 2019
Weighted-average remaining lease terms (years)
Operating leases	8.57
Finance leases	4.75
Weighted-average discount rate (1)
Operating leases	4.91	%
Finance leases	3.45	%

⁽¹⁾ When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date.

Supplemental balance sheet information related to leases was as follows:

(In millions)	Financial Statement Line Item	As of June 30, 2019
Assets
Operating lease assets, net of accumulated amortization of $11 million	Deferred charges and other assets	$	188
Finance lease assets, net of accumulated amortization of $89 million	Property, plant and equipment	74
Total leased assets		$	262
Liabilities
Current:
Operating	Other current liabilities	$	31
Finance	Currently payable long-term debt	16
Noncurrent:
Operating	Other noncurrent liabilities	196
Finance	Long-term debt and other long-term obligations	51
Total leased liabilities		$	294

Maturity of Operating Lease Liabilities

Maturities of lease liabilities as of June 30, 2019, were as follows:

(In millions)	Operating Leases			Finance Leases			Total
2019	$	18		$	11		$	29
2020	38			19			57
2021	36			17			53
2022	35			15			50
2023	32			8			40
2024	27			4			31
Thereafter	99			12			111
Total lease payments (1)	285			86			371
Less imputed interest	(58		)	(19		)	(77		)
Total net present value	$	227		$	67		$	294

⁽¹⁾ Operating lease payments for certain leases are offset by sublease receipts of $13 million over 14 years.

Maturity of Finance Lease Liabilities

Maturities of lease liabilities as of June 30, 2019, were as follows:

(In millions)	Operating Leases			Finance Leases			Total
2019	$	18		$	11		$	29
2020	38			19			57
2021	36			17			53
2022	35			15			50
2023	32			8			40
2024	27			4			31
Thereafter	99			12			111
Total lease payments (1)	285			86			371
Less imputed interest	(58		)	(19		)	(77		)
Total net present value	$	227		$	67		$	294

⁽¹⁾ Operating lease payments for certain leases are offset by sublease receipts of $13 million over 14 years.

Schedule of Future Minimum Capital Lease Payments

The future minimum capital lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Capital Leases
	(In millions)
2019	$	24
2020	19
2021	16
2022	13
2023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23		)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	$	55

Schedule of Future Minimum Operating Lease Payments

The future minimum operating lease payments as of December 31, 2018, as reported in the Annual Report on Form 10-K for the year ended December 31, 2018 under ASC 840 ”Leases” are as follows:

Operating Leases
	(In millions)
2019	$	34
2020	36
2021	34
2022	30
2023	28
Years thereafter	127
Total minimum lease payments	$	289

XML

Capitalization (Tables)

6 Months Ended

Jun. 30, 2019

Regulated Operations [Abstract]

Schedule of Stockholders Equity

The changes in stockholders’ equity for the three and six months ended June 30, 2019 and 2018 for FirstEnergy are included in the following tables:

	Series A Convertible Preferred Stock					Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares		Amount			Shares	Amount
Balance, January 1, 2019	0.7		$	71		512	$	51	$	11,530		$	41		$	(4,879	)	$	6,814
Net income															320			320
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									7									7
Stock Investment Plan and certain share-based benefit plans						1			1									1
Cash dividends declared on common stock									(202		)							(202		)
Cash dividends declared on preferred stock									(3		)							(3		)
Conversion of Series A Convertible Preferred Stock	(0.5	)	(50		)	18	2		48									—
Balance, March 31, 2019	0.2		$	21		531	$	53	$	11,381		$	36		$	(4,559	)	$	6,932
Net income															$	312		$	312
Other comprehensive loss, net of tax												(5		)				(5		)
Stock-based compensation									9									9
Stock Investment Plan and certain share-based benefit plans						1			21									21
Balance, June 30, 2019	0.2		$	21		532	$	53	$	11,411		$	31		$	(4,247	)	$	7,269

	Series A Convertible Preferred Stock			Common Stock			OPIC			AOCI			Accumulated Deficit			Total Stockholders’ Equity
(In millions)	Shares	Amount		Shares	Amount
Balance, January 1, 2018	—	$	—	445	$	44	$	10,001		$	142		$	(6,262	)	$	3,925
Net income													1,369			1,369
Other comprehensive loss, net of tax										(56		)				(56		)
Stock-based compensation							19									19
Stock Investment Plan and certain share-based benefit plans				2	1		5									6
Cash dividends declared on common stock							(343		)							(343		)
Cash dividends declared on preferred stock							(42		)							(42		)
Stock issuance (1)	1.6	162		30	3		2,297									2,462
Impact of adopting new accounting pronouncements (2)													35			35
Balance, March 31, 2018	1.6	$	162	477	$	48	$	11,937		$	86		$	(4,858	)	$	7,375
Net income													$	299		$	299
Other comprehensive loss, net of tax										(13		)				(13		)
Stock-based compensation							19									19
Stock Investment Plan and certain share-based benefit plans				1			19									19
Balance, June 30, 2018	1.6	$	162	478	$	48	$	11,975		$	73		$	(4,559	)	$	7,699

⁽¹⁾ The preferred stock included an embedded conversion option at a price that was below the fair value of the common stock on the commitment date. This beneficial conversion feature (BCF), which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend of $261 million for the six months ended June 30, 2018) through the period from the issue date to the first allowable conversion

date (July 22, 2018). There is no net impact to OPIC for the three and six months ended June 30, 2018. Please see below for additional information on the issuance.

⁽²⁾ FirstEnergy adopted ASU 2016-01, “Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities” standard on January 1, 2018, and subsequently recorded a cumulative effect adjustment to retained earnings of $57 million representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. In addition, FirstEnergy adopted ASU 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income” and upon adoption, recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018. These amounts are offset in other comprehensive loss and do not have an impact on total stockholders’ equity.

XML

Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2019

Fair Value Disclosures [Abstract]

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:

	June 30, 2019										December 31, 2018
	Level 1		Level 2		Level 3			Total			Level 1		Level 2		Level 3			Total
Assets	(In millions)
Corporate debt securities	$	—	$	439	$	—		$	439		$	—	$	405	$	—		$	405
Derivative assets FTRs(1)	—		—		6			6			—		—		10			10
Equity securities(2)	395		—		—			395			339		—		—			339
Foreign government debt securities	—		16		—			16			—		13		—			13
U.S. government debt securities	—		19		—			19			—		20		—			20
U.S. state debt securities	—		263		—			263			—		250		—			250
Other(3)	422		36		—			458			367		34		—			401
Total assets	$	817	$	773	$	6		$	1,596		$	706	$	722	$	10		$	1,438
Liabilities
Derivative liabilities FTRs(1)	$	—	$	—	$	(4	)	$	(4	)	$	—	$	—	$	(1	)	$	(1	)
Derivative liabilities NUG contracts(1)	—		—		(35		)	(35		)	—		—		(44		)	(44		)
Total liabilities	$	—	$	—	$	(39	)	$	(39	)	$	—	$	—	$	(45	)	$	(45	)
Net assets (liabilities)(4)	$	817	$	773	$	(33	)	$	1,557		$	706	$	722	$	(35	)	$	1,393

⁽¹⁾  Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.

⁽²⁾  NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index.

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

⁽⁴⁾ 

Excludes $(15) million and $4 million as of June 30, 2019 and December 31, 2018, 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 June 30, 2019, and December 31, 2018:

	NUG Contracts(1)								FTRs(1)
	Derivative Assets		Derivative Liabilities			Net			Derivative Assets			Derivative Liabilities			Net
	(In millions)
January 1, 2018 Balance	$	—	$	(79	)	$	(79	)	$	3		$	—		$	3
Unrealized gain	—		2			2			8			1			9
Purchases	—		—			—			5			(5		)	—
Settlements	—		33			33			(6		)	3			(3		)
December 31, 2018 Balance	$	—	$	(44	)	$	(44	)	$	10		$	(1	)	$	9
Unrealized loss	—		(11		)	(11		)	—			—			—
Purchases	—		—			—			6			(4		)	2
Settlements	—		20			20			(10		)	1			(9		)
June 30, 2019 Balance	$	—	$	(35	)	$	(35	)	$	6		$	(4	)	$	2

(1)Contracts are subject to regulatory accounting treatment and changes in market values 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 June 30, 2019:

	Fair Value, Net (In millions)			Valuation Technique	Significant Input	Range	Weighted Average	Units
FTRs	$	2		Model	RTO auction clearing prices	$.50 to $2.70	$1.00	Dollars/MWH
NUG Contracts	$	(35	)	Model	Generation	400 to 776,000	160,000	MWH
					Regional electricity prices	$33.50 to $34.10	$33.80	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, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of June 30, 2019, and December 31, 2018:

	June 30, 2019(1)									December 31, 2018(1)
	Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value		Cost Basis		Unrealized Gains		Unrealized Losses			Fair Value
	(In millions)
Debt securities	$	730	$	22	$	(15	)	$	737	$	714	$	2	$	(28	)	$	688
Equity securities	$	346	$	48	$	(1	)	$	393	$	339	$	15	$	(16	)	$	338

⁽¹⁾ Excludes $(2) million and $20 million as of June 30, 2019 and December 31, 2018, respectively, of short-term cash investments, taxes, receivables, payables and accrued income.

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 equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three and six months ended June 30, 2019 and 2018, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions)
Sale Proceeds	$	149		$	175		$	302		$	366
Realized Gains	5			9			12			28
Realized Losses	(5		)	(11		)	(11		)	(27		)
Interest and Dividend Income	11			10			20			20

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, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of June 30, 2019 and December 31, 2018:

	June 30, 2019		December 31, 2018
	(In millions)
Carrying Value (1)	$	19,508	$	18,315
Fair Value	$	21,890	$	19,266

⁽¹⁾ The carrying value as of June 30, 2019, includes $1,950 million of debt issuances and $757 million of redemptions that occurred in the first six months of 2019.

XML

Commitments, Guarantees and Contingencies (Tables)

6 Months Ended

Jun. 30, 2019

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations

Potential Collateral Obligations		AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating		$	1	$	—	$	—	$	1
Upon Further Downgrade		—		43		—		43
Surety Bonds (Collateralized Amount)(1)		1		59		246		306
Total Exposure from Contractual Obligations		$	2	$	102	$	246	$	350

⁽¹⁾ 

Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield’s Ferry CCR disposal site, respectively.

XML

Segment Information (Tables)

6 Months Ended

Jun. 30, 2019

Segment Reporting [Abstract]

Segment Financial Information

Financial information for each of FirstEnergy’s reportable segments is presented in the tables below:

Segment Financial Information

For the Three Months Ended	Regulated Distribution			Regulated Transmission		Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)
June 30, 2019
External revenues	$	2,145		$	368	$	3		$	—		$	2,516
Internal revenues	47			4		—			(51		)	—
Total revenues	$	2,192		$	372	$	3		$	(51	)	$	2,516
Depreciation	220			71		1			17			309
Amortization of regulatory assets, net	34			3		—			—			37
Miscellaneous income, net	46			4		38			(8		)	80
Interest expense	124			48		95			(8		)	259
Income taxes (benefits)	67			30		(16		)	—			81
Income (loss) from continuing operations	258			116		(33		)	—			341
Property additions	354			300		20			—			674
June 30, 2018
External revenues	$	2,285		$	336	$	4		$	—		$	2,625
Internal revenues	67			5		7			(79		)	—
Total revenues	$	2,352		$	341	$	11		$	(79	)	$	2,625
Depreciation	200			62		3			18			283
Deferral of regulatory assets, net	(107		)	—		—			—			(107		)
Miscellaneous income (expense), net	56			3		(1		)	(10		)	48
Interest expense	129			42		194			(10		)	355
Income taxes (benefits)	138			38		(75		)	—			101
Income (loss) from continuing operations	377			104		(173		)	—			308
Property additions	391			282		44			7			724
For the Six Months Ended
June 30, 2019
External revenues	$	4,671		$	720	$	8		$	—		$	5,399
Internal revenues	94			8		—			(102		)	—
Revenues	$	4,765		$	728	$	8		$	(102	)	$	5,399
Depreciation	429			140		3			34			606
Amortization of regulatory assets, net	37			5		—			—			42
Miscellaneous income, net	92			8		49			(15		)	134
Interest expense	246			93		188			(15		)	512
Income taxes (benefits)	156			61		(43		)	—			174
Income (loss) from continuing operations	587			220		(111		)	—			696
Property additions	672			531		25			—			1,228
June 30, 2018
External revenues	$	4,823		$	655	$	9		$	—		$	5,487
Internal revenues	105			9		13			(127		)	—
Revenues	$	4,928		$	664	$	22		$	(127	)	$	5,487
Depreciation	396			123		5			36			560
Amortization (deferral) of regulatory assets, net	(259		)	4		—			—			(255		)
Miscellaneous income, net	112			7		15			(19		)	115
Interest expense	257			81		284			(19		)	603
Income taxes	231			70		33			—			334
Income (loss) from continuing operations	699			203		(413		)	—			489
Property additions	655			574		55			23			1,307
As of June 30, 2019
Total assets	$	29,240		$	11,070	$	574		$	—		$	40,884
Total goodwill	5,004			614		—			—			5,618
As of December 31, 2018
Total assets	$	28,690		$	10,404	$	969		$	—		$	40,063
Total goodwill	5,004			614		—			—			5,618

XML

Organization and Basis of Presentation (Details) customer in Millions	3 Months Ended			6 Months Ended		9 Months Ended	12 Months Ended
	Jun. 30, 2019 USD ($) transmission_center company MW	Mar. 31, 2019 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) customer transmission_center company mi MW	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($) MW	Dec. 31, 2018 USD ($) MW	Apr. 11, 2019 USD ($)	Jan. 01, 2019 USD ($)	Sep. 26, 2018 USD ($)	Aug. 31, 2017 MW
Property, Plant and Equipment [Line Items]
Length of transmission lines | mi				24,500
Number of regional transmission centers | transmission_center	2			2
Cash payment										$ 225,000,000
Capitalized cost of equity	$ 9,000,000		$ 12,000,000	$ 22,000,000	$ 23,000,000
Capitalized interest	7,000,000		4,000,000	12,000,000	8,000,000
Total assets	$ 40,884,000,000			$ 40,884,000,000		$ 40,063,000,000	$ 40,063,000,000
Accounting Standards Update 2016-02
Property, Plant and Equipment [Line Items]
Total assets									$ 186,000,000
Total liabilities									$ 186,000,000
Regulated Distribution
Property, Plant and Equipment [Line Items]
Number of existing utility operating companies | company	10			10
Number of customers served by utility operating companies | customer				6
Plant capacity (in MW's) | MW	3,790			3,790
Purchase Agreement with Subsidiary of LS Power
Property, Plant and Equipment [Line Items]
Plant capacity (in MW's) | MW											1,615
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Property, Plant and Equipment [Line Items]
Fair value of investments	$ 0		0	$ 0	0
Terms of settlement agreement							66,000,000
Estimated tax payments that have been made							$ 52,000,000
Income (Loss) from discontinued operations, before tax	$ 0		$ (25,000,000)	$ 3,000,000	$ (28,000,000)
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | Tax Year 2017
Property, Plant and Equipment [Line Items]
Overpayment of NOL's waived										71,000,000
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | Tax Year 2018
Property, Plant and Equipment [Line Items]
Overpayment of NOL's waived										88,000,000
Loans Payable | Intercompany Income Tax Allocation Agreement | FES
Property, Plant and Equipment [Line Items]
Face amount of debt										628,000,000
Line of Credit | Secured Credit Facility | FES
Property, Plant and Equipment [Line Items]
Maximum amount borrowed under revolving credit facility										500,000,000
Line of Credit | Credit Agreement | FES
Property, Plant and Equipment [Line Items]
Maximum amount borrowed under revolving credit facility										$ 200,000,000
Pleasants Power Station | Purchase Agreement with Subsidiary of LS Power | AE Supply
Property, Plant and Equipment [Line Items]
Plant capacity (in MW's) | MW	1,300			1,300		1,300	1,300
Affiliated Companies | Services Agreements | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | FES
Property, Plant and Equipment [Line Items]
Amounts of transaction	$ 67,000,000			$ 101,000,000		$ 112,500,000
Affiliated Companies | Pension Plan Enhancement | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Property, Plant and Equipment [Line Items]
Amounts of transaction				14,000,000
Affiliated Companies | Benefit Obligations | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Property, Plant and Equipment [Line Items]
Obligations settled in cash								$ 60,000,000
Total obligations to be settled								$ 87,000,000
Income (Loss) from discontinued operations, before tax		$ 27,000,000
Affiliated Companies | Benefit Obligations | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | FES
Property, Plant and Equipment [Line Items]
Amounts of transaction	$ 9,000,000			$ 19,000,000
Continuing Operations | Affiliated Companies | Benefit Obligations | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Property, Plant and Equipment [Line Items]
Income (Loss) from discontinued operations, before tax		$ 17,000,000

XML

Revenue (Details) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019 USD ($) company MW	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) company MW	Jun. 30, 2018 USD ($)
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		$ 2,448	$ 2,549	$ 5,254	$ 5,327
ARP		55	60	117	124
Other non-customer revenue		13	16	28	36
Total revenues	[1]	2,516	2,625	5,399	5,487
Other Non-Customer Revenue
Disaggregation of Revenue [Line Items]
Late payment charges		9	9
Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		1,139	1,181	2,404	2,450
Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		792	868	1,836	1,894
Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		113	126	223	254
Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		367	336	719	655
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		37	38	72	74
Derivative Revenue | Other Non-Customer Revenue
Disaggregation of Revenue [Line Items]
Total revenues		3	4	5	14
Revenue from late payment charges | Other Non-Customer Revenue
Disaggregation of Revenue [Line Items]
Late payment charges				20	19
Regulated Distribution
Disaggregation of Revenue [Line Items]
Total revenues		$ 1,966	2,110	4,310	4,431
Reduction in revenue			10	$ 27	82
Number of existing utility operating companies | company		10		10
Megawatts of net demonstrated capacity of competitive segment | MW		3,790		3,790
Utility customer payment period				30 days
Regulated Distribution | Residential
Disaggregation of Revenue [Line Items]
Total revenues		$ 1,123	1,255	$ 2,607	2,718
Regulated Distribution | Commercial
Disaggregation of Revenue [Line Items]
Total revenues		572	570	1,159	1,150
Regulated Distribution | Industrial
Disaggregation of Revenue [Line Items]
Total revenues		251	262	500	516
Regulated Distribution | Other
Disaggregation of Revenue [Line Items]
Total revenues		20	23	44	47
Regulated Transmission
Disaggregation of Revenue [Line Items]
Total revenues		367	336	719	655
Reduction in revenue			2	7	2
Regulated Transmission | JCP&L | FERC
Disaggregation of Revenue [Line Items]
Annual revenue requirement				155
Regulated Transmission | ATSI
Disaggregation of Revenue [Line Items]
Total revenues		184	167	358	325
Regulated Transmission | TrAIL
Disaggregation of Revenue [Line Items]
Total revenues		59	63	117	123
Regulated Transmission | MAIT
Disaggregation of Revenue [Line Items]
Total revenues		50	34	99	64
Regulated Transmission | Other
Disaggregation of Revenue [Line Items]
Total revenues		74	72	145	143
Operating Segments
Disaggregation of Revenue [Line Items]
Reduction in revenue		2	8	34	84
Operating Segments | Regulated Distribution
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		2,113	2,266	4,597	4,745
ARP		55	60	117	124
Other non-customer revenue		24	26	51	59
Total revenues		2,192	2,352	4,765	4,928
Operating Segments | Regulated Distribution | Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		1,160	1,228	2,446	2,509
Operating Segments | Regulated Distribution | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		806	882	1,864	1,922
Operating Segments | Regulated Distribution | Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		110	121	216	244
Operating Segments | Regulated Distribution | Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0	0
Operating Segments | Regulated Distribution | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		37	35	71	70
Operating Segments | Regulated Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		367	336	719	655
ARP		0	0	0	0
Other non-customer revenue		5	5	9	9
Total revenues		372	341	728	664
Operating Segments | Regulated Transmission | Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0	0
Operating Segments | Regulated Transmission | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0	0
Operating Segments | Regulated Transmission | Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0	0
Operating Segments | Regulated Transmission | Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		367	336	719	655
Operating Segments | Regulated Transmission | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0	0
Corporate/Other and Reconciling Adjustments
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		(32)	(53)	(62)	(73)
ARP		0	0	0	0
Other non-customer revenue		(16)	(15)	(32)	(32)
Total revenues		(48)	(68)	(94)	(105)
Corporate/Other and Reconciling Adjustments | Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		(21)	(47)	(42)	(59)
Corporate/Other and Reconciling Adjustments | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		(14)	(14)	(28)	(28)
Corporate/Other and Reconciling Adjustments | Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		3	5	7	10
Corporate/Other and Reconciling Adjustments | Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0	0
Corporate/Other and Reconciling Adjustments | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		$ 0	$ 3	$ 1	$ 4

[1] Includes excise and gross receipts tax collections of $81 million and $87 million during the three months ended June 30, 2019 and 2018, respectively, and $183 million and $189 million during the six months ended June 30, 2019 and 2018, respectively.

XML

Discontinued Operations - Narrative (Details) $ in Millions				1 Months Ended	3 Months Ended		6 Months Ended		9 Months Ended	12 Months Ended
	May 03, 2018	Mar. 16, 2018 USD ($)	Mar. 09, 2018 USD ($) MW	Aug. 31, 2017 Natural_gas_plant MW	Jun. 30, 2019 USD ($) MW	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) MW	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($) MW	Dec. 31, 2018 USD ($) MW
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Short-term borrowings					$ 1,250.0		$ 1,250.0		$ 1,250.0	$ 1,250.0
Interest accrued					259.0	$ 355.0	512.0	$ 603.0
Outstanding guarantees net liability					1,700.0		1,700.0
Future worthless stock deduction							4,800.0
Future worthless stock deduction, net of tax							1,000.0
Unrecognized tax benefits from worthless stock deduction							418.0
Unrecognized tax benefits from worthless stock deduction, net of tax							88.0
Current assets - discontinued operations					$ 44.0		$ 44.0		$ 25.0	$ 25.0
Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant capacity (in MW's) | MW				1,615
AE Supply | Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of gas generating plants | Natural_gas_plant				4
AGC | Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage	59.00%			59.00%
Pleasants Power Station | AE Supply | Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant capacity (in MW's) | MW					1,300		1,300		1,300	1,300
Bay Shore Unit 1 | Asset Purchase Agreement with Walleye Energy, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant capacity (in MW's) | MW			136
Promissory Notes | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest accrued							$ 18.0	8.0
Promissory Notes | AE Supply | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding borrowings					$ 102.0	102.0	102.0	102.0
Revolving Credit Facility | Line of Credit | FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Line of credit outstanding			$ 500.0		500.0		500.0
Loan reserves					500.0
Money Pool | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Short-term borrowings						92.0		92.0
Reinstated debt under settlement agreement		$ 88.0
Money Pool | Adjustment | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Short-term borrowings		$ 92.0
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investments in subsidiaries					0.0		0.0
Gain (loss) on disposal of FES and FENOC, net of tax					(15.0)	0.0	(39.0)	1,239.0		$ 435.0
Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Effects of Tax Act of included in income tax expense from discontinued operations					14.0	20.0	28.0	36.0
Services Agreements | Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amounts of transaction					67.0		101.0		$ 112.5
Benefit Obligations | Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amounts of transaction					9.0		19.0
Power Purchase Agreements | Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Due from related parties					7.0		7.0
Purchases from related party					43.0	71.0	$ 126.0	174.0
FE | Promissory Notes | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loan reserves					$ 9.0	102.0
FE | Unregulated Money Pool | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loan reserves						92.0
Financial Guarantee | Benefit Obligations | Affiliated Companies | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding guarantees net liability						$ 820.0		$ 820.0

XML

Discontinued Operations - Summarized Results (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax expense (benefit)		$ 39	$ (16)	$ 44	$ (887)
Loss from discontinued operations, net of tax				(39)	1,239
Income (loss) from discontinued operations	[1]	(29)	(9)	(64)	1,179
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues		31	90	85	826
Fuel		(20)	(54)	(55)	(218)
Purchased power		0	(1)	0	(59)
Other operating expenses		(16)	(21)	(26)	(390)
Provision for depreciation		0	(16)	0	(79)
General taxes		(5)	(5)	(9)	(28)
Other income (expense)		10	(18)	8	(80)
Income (loss) from discontinued operations, before tax		0	(25)	3	(28)
Income tax expense (benefit)		14	(16)	28	32
Loss from discontinued operations, net of tax		(14)	(9)	(25)	(60)
Gain (loss) on disposal of FES and FENOC, net of tax		(15)	0	(39)	1,239	$ 435
Income (loss) from discontinued operations		$ (29)	$ (9)	$ (64)	$ 1,179

[1] Net of income tax expense (benefits) of $39 million and $(16) million for the three months ended June 30, 2019 and 2018, respectively, and $44 million and $(887) million for the six months ended June 30, 2019 and 2018, respectively.

XML

Discontinued Operations - Gain on Deconsolidation (Details) - FES and FENOC - Discontinued Operations, Disposed of by Means Other than Sale - USD ($) $ in Millions	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Removal of investment in FES and FENOC	$ 0	$ 0	$ 0	$ 2,193
Assumption of benefit obligations retained at FE	0	0	0	(820)
Guarantees and credit support provided by FE	0	0	0	(139)
Reserve on receivables and allocated pension/OPEB mark-to-market	0	0	0	(914)
Settlement consideration and services credit	10	0	(23)	0
Gain (loss) on disposal of FES and FENOC, before tax	10	0	(23)	320
Income tax benefit (expense), including estimated worthless stock deduction	(25)	0	(16)	919
Gain (loss) on disposal of FES and FENOC, net of tax	$ (15)	$ 0	$ (39)	$ 1,239	$ 435

XML

Discontinued Operations - Major Classes of Cash Flow Items (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	[1]	$ (29)	$ (9)	$ (64)	$ 1,179
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs				702	604
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(674)	(724)	(1,228)	(1,307)
Sales of investment securities held in trusts				302	475
Purchases of investment securities held in trusts				(322)	(508)
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations		$ (29)	$ (9)	(64)	1,179
Depreciation and amortization, including regulatory assets, net, intangible assets and deferred debt-related costs				0	80
Unrealized gain on derivative transactions				0	(10)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions				0	(23)
Sales of investment securities held in trusts				0	109
Purchases of investment securities held in trusts				$ 0	$ (122)

[1] Net of income tax expense (benefits) of $39 million and $(16) million for the three months ended June 30, 2019 and 2018, respectively, and $44 million and $(887) million for the six months ended June 30, 2019 and 2018, respectively.

XML

Earnings Per Share Of Common Stock (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Earnings Per Share [Abstract]
Amount of beneficial conversion				$ 0	$ 296
EPS of Common Stock
Income from continuing operations		$ 341	$ 308	696	489
Less: Preferred dividends		0	0	(3)	(43)
Less: Amortization of beneficial conversion feature		0	(148)	0	(261)
Less: Undistributed earnings allocated to preferred stockholders		(5)	(18)	(7)	0
Income from continuing operations available to common stockholders		336	142	686	185
Discontinued operations, net of tax	[1]	(29)	(9)	(64)	1,179
Less: Undistributed earnings allocated to preferred stockholders		1	1	1	0
Income (loss) from discontinued operations available to common stockholders		(28)	(8)	(63)	1,179
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS		$ 308	$ 134	$ 623	$ 1,364
Share Count information:
Weighted average number of basic shares outstanding (in shares)		532	477	531	477
Assumed exercise of dilutive stock options and awards (in shares)		1	2	2	1
Weighted average number of diluted shares outstanding		533	479	533	478
Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic (in dollars per share)		$ 0.63	$ 0.30	$ 1.29	$ 0.39
Discontinued operations, basic (in dollars per share)		(0.05)	(0.02)	(0.12)	2.47
Basic - Net Income Attributable to Common Stockholders (in dollars per share)		0.58	0.28	1.17	2.86
Income from continuing operations, diluted (in dollars per share)		0.63	0.30	1.29	0.39
Discontinued operations, diluted (in dollars per share)		(0.05)	(0.02)	(0.12)	2.46
Diluted - Net Income Attributable to Common Stockholders (in dollars per share)		$ 0.58	$ 0.28	$ 1.17	$ 2.85
Stock Options
Income (loss) available to common stockholders, per common share:
Shares excluded from the calculation of diluted shares outstanding, in shares		0	1	0	1
Preferred Stock
Income (loss) available to common stockholders, per common share:
Shares excluded from the calculation of diluted shares outstanding, in shares		8	59	8	59

[1] Net of income tax expense (benefits) of $39 million and $(16) million for the three months ended June 30, 2019 and 2018, respectively, and $44 million and $(887) million for the six months ended June 30, 2019 and 2018, respectively.

XML

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
	Feb. 01, 2019	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by employer	$ 500
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs		$ 48	$ 56	$ 96	$ 112
Interest costs		93	93	186	186
Expected return on plan assets		(135)	(144)	(270)	(288)
Amortization of prior service costs (credits)		2	2	4	4
Special termination costs		(1)	0	14	0
Net periodic costs (credits), including amounts capitalized		7	7	30	14
Net periodic costs (credits), recognized in earnings		(14)	(18)	(8)	(32)
Pension | FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits), including amounts capitalized		11	13	22	26
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs		1	1	2	2
Interest costs		5	6	10	12
Expected return on plan assets		(7)	(7)	(14)	(15)
Amortization of prior service costs (credits)		(9)	(20)	(18)	(40)
Special termination costs		0	0	0	0
Net periodic costs (credits), including amounts capitalized		(10)	(20)	(20)	(41)
Net periodic costs (credits), recognized in earnings		(10)	(21)	(20)	(42)
OPEB | FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits), including amounts capitalized		(1)	$ (10)	(2)	$ (20)
Affiliated Companies | Pension Plan Enhancement | FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts of transaction				14
FES | Affiliated Companies | Benefit Obligations | FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amounts of transaction		$ 9		$ 19

XML

Accumulated Other Comprehensive Income - Changes in AOCI (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Other comprehensive income before reclassifications						$ (97)
Amounts reclassified from AOCI	$ (7)		$ (17)		$ (13)	(34)
Deconsolidation of FES and FENOC						5
Other comprehensive loss	(7)		(17)		(13)	(126)
Income taxes (benefits) on other comprehensive income (loss)	(2)		(4)		(3)	(57)
Other comprehensive loss, net of tax	(5)	$ (5)	(13)	$ (56)	(10)	(69)
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	(10)	(11)	(15)	(22)	(11)	(22)
Other comprehensive income before reclassifications						0
Amounts reclassified from AOCI	0		2		1	4
Deconsolidation of FES and FENOC						13
Other comprehensive loss	0		2		1	17
Income taxes (benefits) on other comprehensive income (loss)	0		1		0	9
Other comprehensive loss, net of tax	0		1		1	8
Ending Balance	(10)	(10)	(14)	(15)	(10)	(14)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	0	0	0	67	0	67
Other comprehensive income before reclassifications						(97)
Amounts reclassified from AOCI	0		0		0	(1)
Deconsolidation of FES and FENOC						(8)
Other comprehensive loss	0		0		0	(106)
Income taxes (benefits) on other comprehensive income (loss)	0		0		0	(39)
Other comprehensive loss, net of tax	0		0		0	(67)
Ending Balance	0	0	0	0	0	0
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	46	52	101	97	52	97
Other comprehensive income before reclassifications						0
Amounts reclassified from AOCI	(7)		(19)		(14)	(37)
Deconsolidation of FES and FENOC						0
Other comprehensive loss	(7)		(19)		(14)	(37)
Income taxes (benefits) on other comprehensive income (loss)	(2)		(5)		(3)	(27)
Other comprehensive loss, net of tax	(5)		(14)		(11)	(10)
Ending Balance	41	46	87	101	41	87
AOCI
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance	36	41	86	142	41	142
Other comprehensive loss, net of tax	(5)	(5)	(13)	(56)
Ending Balance	$ 31	$ 36	$ 73	$ 86	$ 31	$ 73

XML

Accumulated Other Comprehensive Income - Amounts Reclassified (Details) - USD ($) $ in Millions		3 Months Ended				6 Months Ended
		Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses		$ (606)		$ (684)		$ (1,385)	$ (1,624)
Interest expense		(259)		(355)		(512)	(603)
Income taxes		(81)		(101)		(174)	(334)
Discontinued operations, net of tax	[1]	(29)		(9)		(64)	1,179
NET INCOME		312	$ 320	299	$ 1,369	632	1,668
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes		0		0		0	(1)
NET INCOME		0		2		1	3
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity Contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses		0		0		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		0		2		1	3
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Discontinued operations, net of tax		0		0		0	(1)
Reclassifications from AOCI | Net prior service costs
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses		(7)		(19)		(14)	(37)
Income taxes		2		4		3	9
NET INCOME		$ (5)		$ (15)		$ (11)	$ (28)

[1] Net of income tax expense (benefits) of $39 million and $(16) million for the three months ended June 30, 2019 and 2018, respectively, and $44 million and $(887) million for the six months ended June 30, 2019 and 2018, respectively.

XML

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	19.20%	24.70%	20.00%	40.60%
Unrecognized tax benefits from lapse of statute of limitations			$ 7
Unrecognized tax benefits decrease in period	$ 10
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year	54		54
Unrecognized tax benefits that would impact effective tax rate	$ 51		$ 51
State and Local Jurisdiction | West Virginia
Income Taxes (Textuals) [Abstract]
Re-measurement in state deferred taxes		$ 126

XML

Leases - Narrative (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Lessee, Lease, Description [Line Items]
Maximum potential loss of lease agreement	$ 16
Operating lease not yet commenced	$ 16
Expected commencement period of leases not yet commenced	18 months
Minimum
Lessee, Lease, Description [Line Items]
Operating lease renewal term	1 year
Renewal term of lease yet to be commenced	3 years
Maximum
Lessee, Lease, Description [Line Items]
Operating lease renewal term	40 years
Renewal term of lease yet to be commenced	10 years

XML

Leases - Operating Lease Expense (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2019
Lessee, Lease, Description [Line Items]
Operating lease costs	$ 12	$ 24
Amortization of right-of-use assets	4	9
Interest on lease liabilities	2	4
Total finance lease cost	6	13
Total lease cost	18	37
Short-term lease costs	2	6
Vehicles
Lessee, Lease, Description [Line Items]
Operating lease costs	8	15
Amortization of right-of-use assets	4	8
Interest on lease liabilities	1	2
Total finance lease cost	5	10
Total lease cost	13	25
Buildings
Lessee, Lease, Description [Line Items]
Operating lease costs	1	3
Amortization of right-of-use assets	0	0
Interest on lease liabilities	1	2
Total finance lease cost	1	2
Total lease cost	2	5
Other
Lessee, Lease, Description [Line Items]
Operating lease costs	3	6
Amortization of right-of-use assets	0	1
Interest on lease liabilities	0	0
Total finance lease cost	0	1
Total lease cost	$ 3	$ 7

XML

Leases - Supplemental Cash Flow Information (Details) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)
Leases [Abstract]
Operating cash flows from operating leases	$ 7	$ 15
Operating cash flows from finance leases	2	3
Finance cash flows from finance leases	5	9
Operating leases	20	26
Finance leases	$ 1	$ 2
Operating leases, weighted-average remaining lease terms	8 years 6 months 25 days	8 years 6 months 25 days
Finance leases, weighted-average remaining lease terms	4 years 9 months	4 years 9 months
Operating leases, weighted-average discount rate	4.91%	4.91%
Finance leases, weighted-average discount rate	3.45%	3.45%
Operating lease assets, net of accumulated amortization of $11 million	$ 188	$ 188
Finance lease assets, net of accumulated amortization of $89 million	74	74
Leased Asset	262	262
Operating liability, current	31	31
Finance liability, current	16	16
Operating liability, noncurrent	196	196
Finance liability, noncurrent	51	51
Total leased liabilities	294	294
Operating lease assets, accumulated amortization	11	11
Financing lease, accumulated amortization	$ 89	$ 89

XML

Leases - Maturities of Lease Liabilities (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Operating Leases
2019	$ 18
2020	38
2021	36
2022	35
2023	32
2024	27
Thereafter	99
Total lease payments	285
Less imputed interest	(58)
Total net present value	227
Finance Leases
2019	11
2020	19
2021	17
2022	15
2023	8
2024	4
Thereafter	12
Total lease payments	86
Less imputed interest	(19)
Total net present value	67
Total
2019	29
2020	57
2021	53
2022	50
2023	40
2024	31
Thereafter	111
Total lease payments	371
Less imputed interest	(77)
Total leased liabilities	294
Sublease receipts	$ 13
Term of sublease income	14 years

XML

Leases - Future Minimum Capital Lease Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Capital Leases
2019	$ 24
2020	19
2021	16
2022	13
2023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	55
Operating Leases
2019	34
2020	36
2021	34
2022	30
2023	28
Years thereafter	127
Total minimum lease payments	$ 289

XML

Capitalization - Narrative (Details) - USD ($)			1 Months Ended	3 Months Ended		6 Months Ended		12 Months Ended
	Jul. 22, 2019	Jan. 22, 2018	Jan. 31, 2019	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Class of Stock [Line Items]
Dividends declared (in usd per share)						$ 0.38	$ 0.72
Proceeds from issuance of equity		$ 2,500,000,000
Par Value, in dollars per share		$ 100		$ 100		100		$ 100
Amount of private placement shares		30,120,482
Common stock, par value (in dollars per share)		$ 0.10		$ 0.1		$ 0.1		$ 0.1
Amount of private placement		$ 850,000,000
Conversion threshold of Preferred Stock (in shares)		323,200
Number of shares to be converted within two years		0
Common stock share cap (in shares)		58,964,222
Amortization of beneficial conversion				$ 0	$ 148,000,000	$ 0	$ 261,000,000
Liquidation preference value		$ 1,000
Conversion price (in dollars per share)				$ 27.42		$ 27.42
Preferred stock shares outstanding			209,822
Preferred Stock
Class of Stock [Line Items]
Number of shares converted (in shares)			494,767					911,411
OPIC
Class of Stock [Line Items]
Amount of private placement		847,000,000
Common Stock
Class of Stock [Line Items]
Amount of private placement		$ 3,000,000
Number of shares issued (in shares)			18,044,018					33,238,910
Series A Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock shares issued		1,616,000		1,616,000		1,616,000		1,616,000
Amount of preferred stock investment		$ 1,620,000,000
Preferred stock shares outstanding				209,822		209,822		704,589
Series A Convertible Preferred Stock | Preferred Stock
Class of Stock [Line Items]
Amount of preferred stock investment		162,000,000
Series A Convertible Preferred Stock | OPIC
Class of Stock [Line Items]
Amount of preferred stock investment		$ 1,460,000,000
Subsequent Event
Class of Stock [Line Items]
Preferred stock shares outstanding	181,520
Subsequent Event | Preferred Stock
Class of Stock [Line Items]
Number of shares converted (in shares)	28,302
Subsequent Event | Common Stock
Class of Stock [Line Items]
Number of shares issued (in shares)	1,032,165

XML

Capitalization - Changes in Stockholders' Equity (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2018	Mar. 31, 2018	Jun. 30, 2019	Jun. 30, 2018	Jan. 01, 2018
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 6,932	$ 6,814	$ 7,375	$ 3,925	$ 6,814	$ 3,925
Beginning balance, shares		511,915,450			511,915,450
Net income	312	$ 320	299	1,369	$ 632	1,668
Other comprehensive loss, net of tax	(5)	(5)	(13)	(56)	(10)	(69)
Stock-based compensation	9	7	19	19
Stock Investment Plan and certain share-based benefit plans	21	1	19	6
Cash dividends declared on common stock		(202)		(343)
Cash dividends declared on preferred stock		(3)		(42)
Stock issuance				2,462
Impact of adopting new accounting pronouncements				35
Conversion of Series A Convertible Preferred Stock		0
Ending balance	$ 7,269	6,932	7,699	7,375	$ 7,269	7,699
Ending balance, shares	532,092,829				532,092,829
Amount of beneficial conversion					$ 0	296
Amortization of beneficial conversion	$ 0		148		0	261
Series A Convertible Preferred Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 21	$ 71	$ 162	$ 0	$ 71	$ 0
Beginning balance, shares	200,000	700,000	1,600,000	0	700,000	0
Stock issuance				$ 162
Stock issuance, shares				1,600,000
Conversion of Series A Convertible Preferred Stock		$ (50)
Conversion of Series A Convertible Preferred Stock, shares		500,000
Ending balance	$ 21	$ 21	$ 162	$ 162	$ 21	$ 162
Ending balance, shares	200,000	200,000	1,600,000	1,600,000	200,000	1,600,000
Common Stock
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 53	$ 51	$ 48	$ 44	$ 51	$ 44
Beginning balance, shares	531,000,000	512,000,000	477,000,000	445,000,000	512,000,000	445,000,000
Stock Investment Plan and certain share-based benefit plans				$ 1
Stock Investment Plan and certain share-based benefit plans, shares	1,000,000	1,000,000	1,000,000	2,000,000
Stock issuance				$ 3
Stock issuance, shares				30,000,000
Conversion of Series A Convertible Preferred Stock		$ 2
Conversion of Series A Convertible Preferred Stock, shares		18,000,000
Ending balance	$ 53	$ 53	$ 48	$ 48	$ 53	$ 48
Ending balance, shares	532,000,000	531,000,000	478,000,000	477,000,000	532,000,000	478,000,000
OPIC
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	$ 11,381	$ 11,530	$ 11,937	$ 10,001	$ 11,530	$ 10,001
Stock-based compensation	9	7	19	19
Stock Investment Plan and certain share-based benefit plans	21	1	19	5
Cash dividends declared on common stock		(202)		(343)
Cash dividends declared on preferred stock		(3)		(42)
Stock issuance				2,297
Conversion of Series A Convertible Preferred Stock		48
Ending balance	11,411	11,381	11,975	11,937	11,411	11,975
Amount of beneficial conversion			296
AOCI
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	36	41	86	142	41	142
Other comprehensive loss, net of tax	(5)	(5)	(13)	(56)
Ending balance	31	36	73	86	31	73
Accumulated Deficit
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Beginning balance	(4,559)	(4,879)	(4,858)	(6,262)	(4,879)	(6,262)
Net income	312	320	299	1,369
Impact of adopting new accounting pronouncements				35
Ending balance	$ (4,247)	$ (4,559)	$ (4,559)	$ (4,858)	$ (4,247)	$ (4,559)
ASU 2016-01 | Accumulated Deficit
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Effect of new accounting principle in period of adoption							$ 57
ASU 2018-02 | Accumulated Deficit
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Effect of new accounting principle in period of adoption							$ 22

XML

Variable Interest Entities (Details)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2019 USD ($)	Jun. 30, 2018 USD ($)	Jun. 30, 2019 USD ($) agreement entity	Jun. 30, 2018 USD ($)	Dec. 31, 2018 USD ($)
Variable Interest Entities (Textuals) [Abstract]
Long-term transition bond	$ 33,000,000		$ 33,000,000		$ 41,000,000
Long-term pollution control bond	345,000,000		345,000,000		358,000,000
Guarantor obligations	350,000,000		$ 350,000,000
Number of contracts that may contain variable interest | entity			1,000,000
Purchased power	$ 611,000,000	$ 697,000,000	$ 1,392,000,000	$ 1,517,000,000
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	0.00%		0.00%
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement			11
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 280,000,000		$ 280,000,000		292,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees					$ 445,000
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 30,000,000	26,000,000	$ 61,000,000	58,000,000
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%		100.00%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series	50.00%		50.00%
Equity method investments	$ 17,000,000		$ 17,000,000
Global Holding
Variable Interest Entities (Textuals) [Abstract]
Equity method investments	14,000,000		14,000,000
Global Holding | Line of Credit | Term Loan Facility Due March 2020
Variable Interest Entities (Textuals) [Abstract]
Face amount of debt	300,000,000		300,000,000
Global Holding | Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations	$ 180,000,000		$ 180,000,000
Signal Peak | Global Holding | FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	33.33%		33.33%
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Variable Interest Entities (Textuals) [Abstract]
Fair value of investments	$ 0	$ 0	$ 0	$ 0

XML

Fair Value Measurements - Recurring Assets and Liabilities (Details) - Recurring - USD ($) $ in Millions	Jun. 30, 2019	Dec. 31, 2018
Assets
Fair value, assets	$ 1,596	$ 1,438
Liabilities
Fair value, liabilities	(39)	(45)
Net assets (liabilities)	1,557	1,393
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(4)	(1)
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(35)	(44)
Corporate debt securities
Assets
Fair value, assets	439	405
FTRs | Derivative Assets
Assets
Fair value, assets	6	10
Equity securities
Assets
Fair value, assets	395	339
Foreign government debt securities
Assets
Fair value, assets	16	13
U.S. government debt securities
Assets
Fair value, assets	19	20
U.S. state debt securities
Assets
Fair value, assets	263	250
Other
Assets
Fair value, assets	458	401
Level 1
Assets
Fair value, assets	817	706
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	817	706
Level 1 | FTRs | Derivative Liabilities
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 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	395	339
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 1 | Other
Assets
Fair value, assets	422	367
Level 2
Assets
Fair value, assets	773	722
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	773	722
Level 2 | FTRs | Derivative Liabilities
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	439	405
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	16	13
Level 2 | U.S. government debt securities
Assets
Fair value, assets	19	20
Level 2 | U.S. state debt securities
Assets
Fair value, assets	263	250
Level 2 | Other
Assets
Fair value, assets	36	34
Level 3
Assets
Fair value, assets	6	10
Liabilities
Fair value, liabilities	(39)	(45)
Net assets (liabilities)	(33)	(35)
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(4)	(1)
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(35)	(44)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	6	10
Level 3 | Equity securities
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 3 | Other
Assets
Fair value, assets	$ 0	$ 0

XML

Fair Value Measurements - Level 3 Rollforward (Details) - Level 3 - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
NUG contracts
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	$ 0	$ 0
Beginning Balance, Derivative Liabilities	(44)	(79)
Beginning Balance, Net	(44)	(79)
Unrealized gain (loss), Derivative Assets	0	0
Unrealized loss, Derivative Liabilities	(11)	2
Unrealized loss, Net	(11)	2
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	0	0
Settlements, Derivative Liabilities	20	33
Settlements, Net	20	33
Ending Balance, Derivative Assets	0	0
Ending Balance, Derivative Liabilities	(35)	(44)
Ending Balance, Net	(35)	(44)
FTRs
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	10	3
Beginning Balance, Derivative Liabilities	(1)	0
Beginning Balance, Net	9	3
Unrealized gain (loss), Derivative Assets	0	8
Unrealized loss, Derivative Liabilities	0	1
Unrealized loss, Net	0	9
Purchases, Derivative Assets	6	5
Purchases, Derivative Liabilities	(4)	(5)
Purchases, Net	2	0
Settlements, Derivative Assets	(10)	(6)
Settlements, Derivative Liabilities	1	3
Settlements, Net	(9)	(3)
Ending Balance, Derivative Assets	6	10
Ending Balance, Derivative Liabilities	(4)	(1)
Ending Balance, Net	$ 2	$ 9

XML

Fair Value Measurements - Level 3 Quantitative Information (Details) - Level 3 $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) MWh $ / MWh	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 2	$ 9	$ 3
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(35)	$ (44)	$ (79)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	2
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (35)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	0.50
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)	33.50
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	2.70
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	776,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	34.10
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	1.00
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) | MWh	160,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	33.80

XML

Fair Value Measurements - Investments Held in Trusts (Details) - USD ($) $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2019	Dec. 31, 2018
Debt securities
Debt Securities, Available-for-sale [Line Items]
Cost Basis	$ 730	$ 714
Unrealized Gains	22	2
Unrealized Losses	(15)	(28)
Fair Value	737	688
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	346	339
Unrealized Gains	48	15
Unrealized Losses	(1)	(16)
Fair Value	$ 393	$ 338

XML

Fair Value Measurements - Proceeds from the Sale of Investments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sale Proceeds	$ 149	$ 175	$ 302	$ 366
Realized Gains	5	9	12	28
Realized Losses	(5)	(11)	(11)	(27)
Interest and Dividend Income	$ 11	$ 10	$ 20	$ 20

XML

Fair Value Measurements - Carrying Amounts of Long-term Debt (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Fair value and related carrying amounts of long-term debt and other long-term obligations
Debt issuances	$ 1,950	$ 450
Debt redemptions	757	$ 2,251
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	19,508		$ 18,315
Debt issuances	1,950
Debt redemptions	757
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	$ 21,890		$ 19,266

XML

Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Jun. 30, 2019
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income	$ 4	$ (15)
Cash balance excluded from available for sale securities	20	(2)
Investments not required to be disclosed	$ 253	$ 275
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	2 years

XML

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions								6 Months Ended	36 Months Ended
	Apr. 23, 2019 USD ($) rate_adjustment	Mar. 22, 2019 USD ($) program	Aug. 24, 2018 USD ($) program	Jul. 13, 2018 USD ($)	Mar. 26, 2018 USD ($)	Jan. 19, 2018 USD ($)	Jul. 16, 2015	Jun. 30, 2019	Dec. 31, 2020 USD ($)
PE | Maryland
Regulatory Matters [Line Items]
Incremental energy savings goal in the next 12 months (percent)							0.97%
Incremental energy savings goal per year (percent)							0.20%
Incremental energy savings goal thereafter (percent)							2.00%
Amortization period								5 years
PE | MPSC | Maryland
Regulatory Matters [Line Items]
Cost of charging equipment rebates						$ 12.0
Charging equipment rebates amortization period						5 years
Amount of requested rate increase (decrease)			$ 19.7
Approved amount of annual increase (decrease)			$ 18.0
Number of enhanced service reliability programs | program			4
Revised requested rate increase			$ 7.3
Amount of approved annual rate increase		$ 6.2
Number of enhanced service reliability programs | program		3
Enhanced service reliability program term		4 years
Period to file new depreciation study		18 months
Enhanced service reliability program renewal period		4 years
JCP&L | NJBPU | New Jersey
Regulatory Matters [Line Items]
Approved amount of annual increase (decrease)	$ (28.6)				$ (28.6)
Approved rider due to change in tax rate					$ 1.3
Approved amount of rate refund	7.0
JCP&L | NJBPU | JCP&L Reliability Plus
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)				$ 386.8
JCP&L | NJBPU | JCP&L Reliability Plus | New Jersey
Regulatory Matters [Line Items]
Approved amount of annual increase (decrease)	$ 97.0
Processes for rate adjustments | rate_adjustment	2
Infrastructure investment period				4 years
Scenario, Forecast | PE | Maryland
Regulatory Matters [Line Items]
Recovery period for expenditures for cost recovery program									3 years
Expenditures for cost recovery program									$ 116.0

XML

Regulatory Matters - Ohio (Details) - USD ($) $ in Millions								6 Months Ended
	Apr. 19, 2019	Mar. 29, 2019	Feb. 01, 2019	Nov. 09, 2018	Mar. 12, 2018	Dec. 01, 2017	Oct. 12, 2016	Jun. 30, 2019	Feb. 15, 2018
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)								90.00%
OHIO
Regulatory Matters [Line Items]
Estimated cost of plans								$ 268.0
OHIO | PUCO
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)							90.00%
Requested removal of cost cap					4.00%
OHIO | Distribution Modernization Rider | PUCO
Regulatory Matters [Line Items]
Annual revenue cap for rider							$ 132.5
Recovery period							3 years
Possible extension period							2 years
Approved amount for rider							$ 168.0
Excessive earnings test exclusion period							3 years
Renewal period for excessive earnings test exclusion period			2 years				2 years
OHIO | Delivery Capital Recovery Rider | PUCO
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 | Distribution Platform Modernization Plan | PUCO
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)						$ 450.0
Approved amount of annual increase (decrease)				$ 516.0
Period of grid modernization plan				3 years
OHIO | Energy Conservation, Economic Development and Job Retention | PUCO
Regulatory Matters [Line Items]
Contribution amount							$ 51.0
The Ohio Companies | OHIO | PUCO
Regulatory Matters [Line Items]
Impact on base rate									$ 40.0
The Ohio Companies | OHIO | Regional Transmission Expansion Plan | PUCO
Regulatory Matters [Line Items]
Amount excluded from approved rate recovery		$ 95.0
The Ohio Companies | OHIO | OCC DMR Refund | PUCO
Regulatory Matters [Line Items]
Loss contingency, damages sought	$ 42.0

XML

Regulatory Matters - Pennsylvania and West Virginia (Details) - Pennsylvania $ in Millions		1 Months Ended	6 Months Ended
	Jan. 18, 2019 USD ($)	Mar. 31, 2016 USD ($)	Jun. 30, 2019 proposal
DSP June 2019- May 2023
Regulatory Matters [Line Items]
Number of RFP's | proposal			2
RFP term			2 years
Three Month Period | DSP June 2019- May 2023
Regulatory Matters [Line Items]
Term of energy contract			3 months
Twelve month period | DSP June 2019- May 2023
Regulatory Matters [Line Items]
Term of energy contract			12 months
Twenty-four month period | DSP June 2019- May 2023
Regulatory Matters [Line Items]
Term of energy contract			24 months
Pennsylvania Companies | PPUC | EE&C Phase III
Regulatory Matters [Line Items]
Approved amount of annual increase		$ 390
ME
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)	$ 45
Penn
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)	26
WP
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)	51
PN
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)	$ 25

XML

Regulatory Matters - Reliability Matters and FERC (Details) $ in Millions	Jun. 30, 2019 USD ($)
FERC
Regulatory Matters [Line Items]
Denied recovery charges of exit fees	$ 78.8

XML

Commitments, Guarantees and Contingencies - Potential Collateral Obligations (Details) $ in Millions	6 Months Ended
	Jun. 30, 2019 USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 350
Curing period	30 days
At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	$ 1
Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	43
Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	306
Utilities and FET
Guarantor Obligations [Line Items]
Guarantor obligations	102
Utilities and FET | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
Utilities and FET | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	43
Utilities and FET | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	59
FirstEnergy
Guarantor Obligations [Line Items]
Guarantor obligations	246
FirstEnergy | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
FirstEnergy | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
FirstEnergy | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	246
AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations	2
AE Supply | At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	1
AE Supply | Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
AE Supply | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 1

XML

Commitments, Guarantees and Contingencies - Narrative (Details) T in Millions	6 Months Ended
	Jun. 30, 2019 USD ($) phase T	Dec. 31, 2018 USD ($)
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	$ 1,700,000,000
Proposed goal to reduce CO2 pollution (percent)	90.00%
Nuclear plant decommissioning trusts	$ 863,000,000	$ 790,000,000
Clean Water Act
Guarantor Obligations [Line Items]
Waste water discharge permit renewal cycle	5 years
Regulation of Waste Disposal
Guarantor Obligations [Line Items]
Accrual for environmental loss contingencies	$ 119,000,000
Environmental liabilities former gas facilities	$ 83,000,000
National Ambient Air Quality Standards
Guarantor Obligations [Line Items]
Capping of SO2 Emissions Under CSAPR | T	2.4
Capping of NOx emissions under CSAPR | T	1.2
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 | phase	2
Regulated Distribution
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions	$ 2,000,000
Global Holding | Senior Secured Term Loan | Senior Loans | Signal Peak, Global Rail and Affiliates
Guarantor Obligations [Line Items]
Investment ownership percentage	69.99%
FEV | Senior Secured Term Loan | Senior Loans | Signal Peak | Global Holding
Guarantor Obligations [Line Items]
Investment ownership percentage	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%
AE Supply
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions	$ 0
JCP&L, ME and PN | Nuclear Plant Matters | Financial Guarantee
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts	900,000,000
FES and FENOC
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	350,000,000
FE
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	1,000,000,000
Other Guarantee
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	180,000,000
Other Assurances
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	140,000,000
Term Loan Facility Due March 2020 | Line of Credit | Global Holding
Guarantor Obligations [Line Items]
Face amount of debt	300,000,000
Little Bull Run | Line of Credit | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Maximum amount borrowed under revolving credit facility	169,000,000
Hatfield Ferry | Line of Credit | Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Maximum amount borrowed under revolving credit facility	$ 31,000,000

XML

Segment Information - Narrative (Details) mi² in Thousands, customer in Millions, $ in Billions	6 Months Ended
	Jun. 30, 2019 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	3,790
Other/Corporate | OVEC
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	67
FirstEnergy | Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 7.1

XML

Segment Information - Financial Data (Details) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2019	Jun. 30, 2018	Jun. 30, 2019	Jun. 30, 2018	Dec. 31, 2018
Segment Financial Information
Revenues	[1]	$ 2,516	$ 2,625	$ 5,399	$ 5,487
Depreciation		309	283	606	560
Amortization (deferral) of regulatory assets, net		37	(107)	42	(255)
Miscellaneous income (expense), net		80	48	134	115
Interest expense		259	355	512	603
Income taxes (benefits)		81	101	174	334
Income (loss) from continuing operations		341	308	696	489
Total assets		40,884		40,884		$ 40,063
Goodwill		5,618		5,618		5,618
Property additions		674	724	1,228	1,307
External Customers
Segment Financial Information
Revenues		2,516	2,625	5,399	5,487
Internal Customers
Segment Financial Information
Revenues		0	0	0	0
Regulated Distribution
Segment Financial Information
Revenues		1,966	2,110	4,310	4,431
Income (loss) from continuing operations				587	699
Regulated Transmission
Segment Financial Information
Revenues		367	336	719	655
Income (loss) from continuing operations		116	104	220	203
Operating Segments | Regulated Distribution
Segment Financial Information
Revenues		2,192	2,352	4,765	4,928
Depreciation		220	200	429	396
Amortization (deferral) of regulatory assets, net		34	(107)	37	(259)
Miscellaneous income (expense), net		46	56	92	112
Interest expense		124	129	246	257
Income taxes (benefits)		67	138	156	231
Income (loss) from continuing operations		258	377
Total assets		29,240		29,240		28,690
Goodwill		5,004		5,004		5,004
Property additions		354	391	672	655
Operating Segments | Regulated Distribution | External Customers
Segment Financial Information
Revenues		2,145	2,285	4,671	4,823
Operating Segments | Regulated Distribution | Internal Customers
Segment Financial Information
Revenues		47	67	94	105
Operating Segments | Regulated Transmission
Segment Financial Information
Revenues		372	341	728	664
Depreciation		71	62	140	123
Amortization (deferral) of regulatory assets, net		3	0	5	4
Miscellaneous income (expense), net		4	3	8	7
Interest expense		48	42	93	81
Income taxes (benefits)		30	38	61	70
Total assets		11,070		11,070		10,404
Goodwill		614		614		614
Property additions		300	282	531	574
Operating Segments | Regulated Transmission | External Customers
Segment Financial Information
Revenues		368	336	720	655
Operating Segments | Regulated Transmission | Internal Customers
Segment Financial Information
Revenues		4	5	8	9
Corporate/Other
Segment Financial Information
Revenues		3	11	8	22
Depreciation		1	3	3	5
Amortization (deferral) of regulatory assets, net		0	0	0	0
Miscellaneous income (expense), net		38	(1)	49	15
Interest expense		95	194	188	284
Income taxes (benefits)		(16)	(75)	(43)	33
Income (loss) from continuing operations		(33)	(173)	(111)	(413)
Total assets		574		574		969
Goodwill		0		0		0
Property additions		20	44	25	55
Corporate/Other | External Customers
Segment Financial Information
Revenues		3	4	8	9
Corporate/Other | Internal Customers
Segment Financial Information
Revenues		0	7	0	13
Reconciling Adjustments
Segment Financial Information
Revenues		(51)	(79)	(102)	(127)
Depreciation		17	18	34	36
Amortization (deferral) of regulatory assets, net		0	0	0	0
Miscellaneous income (expense), net		(8)	(10)	(15)	(19)
Interest expense		(8)	(10)	(15)	(19)
Income taxes (benefits)		0	0	0	0
Income (loss) from continuing operations		0	0	0	0
Total assets		0		0		0
Goodwill		0		0		$ 0
Property additions		0	7	0	23
Reconciling Adjustments | External Customers
Segment Financial Information
Revenues		0	0	0	0
Reconciling Adjustments | Internal Customers
Segment Financial Information
Revenues		$ (51)	$ (79)	$ (102)	$ (127)

[1] Includes excise and gross receipts tax collections of $81 million and $87 million during the three months ended June 30, 2019 and 2018, respectively, and $183 million and $189 million during the six months ended June 30, 2019 and 2018, respectively.