FirstEnergy (FE) 10-Q 2020 Q2 Quarterly report

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, 2020

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, 2020
Common Stock, $0.10 par value	542,110,386

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, investor factbook, 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.

1

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 extent and duration of COVID-19 and the impacts to our business, operations and financial condition resulting from the outbreak of COVID-19 including, but not limited to, disruption of businesses in our territories, volatile capital and credit markets, legislative and regulatory actions, the effectiveness of our pandemic and business continuity plans, the precautionary measures we are taking on behalf of our customers and employees, our customers’ ability to make their utility payment and the potential for supply-chain disruptions.

•The risks and uncertainties associated with government investigations regarding Ohio House Bill 6 and related matters.

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

•Mitigating exposure for remedial activities associated with retired and formerly owned electric generation assets, including, but not limited to, risks associated with the decommissioning of TMI-2.

•The ability to accomplish or realize anticipated benefits from strategic and financial goals, including, but not limited to, executing our transmission and distribution investment plans, controlling costs, improving our credit metrics, strengthening our balance sheet and growing 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.

•Labor disruptions by our unionized workforce.

•Changes to significant accounting policies.

•Any changes in tax laws or regulations, 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, including the increasing number of financial institutions evaluating the impact of climate change on their investment decisions.

•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 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

2

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.

3

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 Stockholders’ Equity	4
Consolidated Statements of Cash Flows	5
Notes To Consolidated Financial Statements	6
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	36
Item 3. Quantitative and Qualitative Disclosures About Market Risk	75
Item 4. Controls and Procedures	75
Part II. Other Information
Item 1. Legal Proceedings	75
Item 1A. Risk Factors	75
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	76
Item 3. Defaults Upon Senior Securities	77
Item 4. Mine Safety Disclosures	77
Item 5. Other Information	77
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 Supply	Allegheny Energy Supply Company, LLC, an unregulated generation subsidiary
AGC	Allegheny Generating Company, a generation subsidiary of MP
ATSI	American Transmission Systems, Incorporated, a subsidiary of FET, which owns and operates transmission facilities
CEI	The Cleveland Electric Illuminating Company, an Ohio electric utility operating subsidiary
FE	FirstEnergy Corp., a public utility holding company
FENOC	Energy Harbor Nuclear Corp. (formerly known as FirstEnergy Nuclear Operating Company), a subsidiary of EH, which operates NG’s nuclear generating facilities
FES	Energy Harbor LLC. (formerly known as FirstEnergy Solutions Corp.), a subsidiary of EH, which provides energy-related products and services
FES Debtors	FES, FENOC, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage LLC, and FGMUC
FESC	FirstEnergy Service Company, which provides legal, financial and other corporate support services
FET	FirstEnergy Transmission, LLC, the parent company 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	Energy Harbor Generation LLC (formerly known as FirstEnergy Generation, LLC), a subsidiary of EH, which owns and operates fossil generating facilities
FGMUC	FirstEnergy Generation Mansfield Unit 1 Corp., a subsidiary of FG
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
GPUN	GPU Nuclear, Inc., a subsidiary of FE, which operates TMI-2
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	Energy Harbor Nuclear Generation LLC (formerly known as FirstEnergy Nuclear Generation, LLC), a subsidiary of EH, 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
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	Facebook®	Facebook is a registered trademark of Facebook, Inc.
ADIT	Accumulated Deferred Income Taxes	FASB	Financial Accounting Standards Board
AEP	American Electric Power Company, Inc.	FERC	Federal Energy Regulatory Commission
AFS	Available-for-sale	FES Bankruptcy	FES Debtors’ voluntary petitions for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code with the Bankruptcy Court
AFUDC	Allowance for Funds Used During Construction	Fitch	Fitch Ratings Service
AMT	Alternative Minimum Tax	FPA	Federal Power Act
AOCI	Accumulated Other Comprehensive Income	FTR	Financial Transmission Right
ARO	Asset Retirement Obligation	GAAP	Accounting Principles Generally Accepted in the United States of America
ARP	Alternative Revenue Program	GHG	Greenhouse Gases
ASC	Accounting Standard Codification	IIP	Infrastructure Investment Program
ASU	Accounting Standards Update	kW	Kilowatt
Bankruptcy Court	U.S. Bankruptcy Court in the Northern District of Ohio in Akron	LIBOR	London Inter-Bank Offered Rate
BGS	Basic Generation Service	LOC	Letter of Credit
CAA	Clean Air Act	LTIIPs	Long-Term Infrastructure Improvement Plans
CARES Act	Coronavirus Aid, Relief and Economic Security Act of 2020	MDPSC	Maryland Public Service Commission
CCR	Coal Combustion Residuals	MGP	Manufactured Gas Plants
CERCLA	Comprehensive Environmental Response, Compensation, and Liability Act of 1980	MISO	Midcontinent Independent System Operator, Inc.
CFR	Code of Federal Regulations	mmBTU	One Million British Thermal Units
CO2	Carbon Dioxide	Moody’s	Moody’s Investors Service, Inc.
COVID-19	Coronavirus disease 2019	MW	Megawatt
CPP	EPA’s Clean Power Plan	MWH	Megawatt-hour
CSAPR	Cross-State Air Pollution Rule	NAAQS	National Ambient Air Quality Standards
CTA	Consolidated Tax Adjustment	NDT	Nuclear Decommissioning Trust
CWA	Clean Water Act	NERC	North American Electric Reliability Corporation
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit	NJBPU	New Jersey Board of Public Utilities
DCR	Delivery Capital Recovery	NOI	Notice of Inquiry
DMR	Distribution Modernization Rider	NOL	Net Operating Loss
DSIC	Distribution System Improvement Charge	NOx	Nitrogen Oxide
DSP	Default Service Plan	NPDES	National Pollutant Discharge Elimination System
E&P	Earnings and Profits	NRC	Nuclear Regulatory Commission
EDC	Electric Distribution Company	NUG	Non-Utility Generation
EDIS	Electric Distribution Investment Surcharge	NYPSC	New York State Public Service Commission
EE&C	Energy Efficiency and Conservation	OCA	Office of Consumer Advocate
EGS	Electric Generation Supplier	OCC	Ohio Consumers’ Counsel
EGU	Electric Generation Units	OPEB	Other Post-Employment Benefits
EH	Energy Harbor Corp.	OPIC	Other Paid-in Capital
EmPOWER Maryland	EmPOWER Maryland Energy Efficiency Act	OVEC	Ohio Valley Electric Corporation
ENEC	Expanded Net Energy Cost	PA DEP	Pennsylvania Department of Environmental Protection
EPA	United States Environmental Protection Agency	PJM	PJM Interconnection, LLC
EPS	Earnings per Share	PJM Tariff	PJM Open Access Transmission Tariff
ERO	Electric Reliability Organization	POLR	Provider of Last Resort
ESP IV	Electric Security Plan IV	POR	Purchase of Receivables

iii

PPA	Purchase Power Agreement	SEC	United States Securities and Exchange Commission
PPB	Parts per Billion	SEET	Significantly Excessive Earnings Test
PPUC	Pennsylvania Public Utility Commission	SIP	State Implementation Plan(s) Under the Clean Air Act
PUCO	Public Utilities Commission of Ohio	SNCR	Selective Non-Catalytic Reduction
PURPA	Public Utility Regulatory Policies Act of 1978	SO2	Sulfur Dioxide
RCRA	Resource Conservation and Recovery Act	SOS	Standard Offer Service
Regulation FD	Regulation Fair Disclosure promulgated by the SEC	SREC	Solar Renewable Energy Credit
RFC	ReliabilityFirst Corporation	SSO	Standard Service Offer
RFP	Request for Proposal	Tax Act	Tax Cuts and Jobs Act adopted December 22, 2017
RGGI	Regional Greenhouse Gas Initiative	TMI-2	Three Mile Island Unit 2
ROE	Return on Equity	Twitter®	Twitter is a registered trademark of Twitter, Inc.
RTO	Regional Transmission Organization	UCC	Official committee of unsecured creditors appointed in connection with the FES Bankruptcy
S&P	Standard & Poor’s Ratings Service	VIE	Variable Interest Entity
SBC	Societal Benefits Charge	VMS	Vegetation Management Surcharge
SCOH	Supreme Court of Ohio	VSCC	Virginia State Corporation Commission
SCR	Selective Catalytic Reduction	WVPSC	Public Service Commission of West Virginia
S.D. Ohio	Southern District of Ohio	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)	2020		2019		2020		2019
REVENUES:
Distribution services and retail generation	$	2,030	$	1,931	$	4,154	$	4,240
Transmission	380		367		777		719
Other	112		218		300		440
Total revenues(1)	2,522		2,516		5,231		5,399
OPERATING EXPENSES:
Fuel	77		129		175		260
Purchased power	613		611		1,307		1,392
Other operating expenses	730		606		1,479		1,385
Provision for depreciation	321		309		638		606
Amortization of regulatory assets, net	13		37		65		42
General taxes	253		239		520		500
Total operating expenses	2,007		1,931		4,184		4,185
OPERATING INCOME	515		585		1,047		1,214
OTHER INCOME (EXPENSE):
Miscellaneous income, net	103		80		203		134
Pension and OPEB mark-to-market adjustment (Note 5)	—		—		(423)		—
Interest expense	(263)		(259)		(526)		(512)
Capitalized financing costs	18		16		36		34
Total other expense	(142)		(163)		(710)		(344)
INCOME BEFORE INCOME TAXES	373		422		337		870
INCOME TAXES	66		81		6		174
INCOME FROM CONTINUING OPERATIONS	307		341		331		696
Discontinued operations (Note 3)(2)	2		(29)		52		(64)
NET INCOME	$	309	$	312	$	383	$	632
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4)	—		4		—		9
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$	309	$	308	$	383	$	623
EARNINGS PER SHARE OF COMMON STOCK (Note 4):
Basic - Continuing Operations	$	0.57	$	0.63	$	0.61	$	1.29
Basic - Discontinued Operations	—		(0.05)		0.10		(0.12)
Basic - Net Income Attributable to Common Stockholders	$	0.57	$	0.58	$	0.71	$	1.17
Diluted - Continuing Operations	$	0.57	$	0.63	$	0.61	$	1.29
Diluted - Discontinued Operations	—		(0.05)		0.10		(0.12)
Diluted - Net Income Attributable to Common Stockholders	$	0.57	$	0.58	$	0.71	$	1.17
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic	542		532		541		531
Diluted	543		533		543		533

⁽¹⁾ Includes excise and gross receipts tax collections of $84 million and $81 million during the three months ended June 30, 2020 and 2019, respectively, and $176 million and $183 million during the six months ended June 30, 2020 and 2019, respectively.

⁽²⁾ Net of income tax expense of $1 million and $39 million for the three months ended June 30, 2020 and 2019, respectively, and $(35) million and $44 million for the six months ended June 30, 2020 and 2019, 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)	2020		2019		2020		2019
NET INCOME	$	309	$	312	$	383	$	632
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(4)		(7)		(27)		(14)
Amortized losses on derivative hedges	1		—		1		1
Other comprehensive loss	(3)		(7)		(26)		(13)
Income tax benefits on other comprehensive loss	(1)		(2)		(6)		(3)
Other comprehensive loss, net of tax	(2)		(5)		(20)		(10)
COMPREHENSIVE INCOME	$	307	$	307	$	363	$	622

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, 2020		December 31, 2019
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	116	$	627
Restricted cash	49		52
Receivables-
Customers	1,107		1,137
Less — Allowance for uncollectible customer receivables	87		46
	1,020		1,091
Affiliated companies, net of allowance for uncollectible accounts of $1,063 in 2019	—		—
Other, net of allowance for uncollectible accounts of $26 in 2020 and $21 in 2019	212		203
Materials and supplies, at average cost	303		281
Prepaid taxes and other	286		157
Current assets - discontinued operations	—		33
	1,986		2,444
PROPERTY, PLANT AND EQUIPMENT:
In service	42,794		41,767
Less — Accumulated provision for depreciation	11,818		11,427
	30,976		30,340
Construction work in progress	1,432		1,310
	32,408		31,650
PROPERTY, PLANT AND EQUIPMENT, NET - HELD FOR SALE (NOTE 9)	44		—
INVESTMENTS:
Nuclear fuel disposal trust	278		270
Other	297		299
Investments - held for sale (Note 10)	882		882
	1,457		1,451
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618		5,618
Regulatory assets	78		99
Other	812		1,039
	6,508		6,756
	$	42,403	$	42,301
LIABILITIES AND CAPITALIZATION
CURRENT LIABILITIES:
Currently payable long-term debt	$	81	$	380
Short-term borrowings	115		1,000
Accounts payable	882		918
Accounts payable - affiliated companies	—		87
Accrued interest	269		249
Accrued taxes	563		545
Accrued compensation and benefits	267		258
Other	367		1,425
	2,544		4,862
CAPITALIZATION:
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 542,110,386 and 540,652,222 shares outstanding as of June 30, 2020 and December 31, 2019, respectively	54		54
Other paid-in capital	10,673		10,868
Accumulated other comprehensive income	—		20
Accumulated deficit	(3,584)		(3,967)
Total stockholders’ equity	7,143		6,975
Long-term debt and other long-term obligations	21,980		19,618
	29,123		26,593
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	2,876		2,849
Retirement benefits	3,401		3,065
Regulatory liabilities	2,228		2,360
Asset retirement obligations	170		165
Adverse power contract liability	31		49
Other	1,321		1,667
Noncurrent liabilities - held for sale (Note 10)	709		691
	10,736		10,846
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 10)
	$	42,403	$	42,301

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

3

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

	Six Months Ended June 30, 2020
	Series A Convertible Preferred Stock				Common Stock						OPIC		AOCI		Accumulated Deficit	Total Stockholders’ Equity
(In millions)	Shares	Amount		Shares	Amount
Balance, January 1, 2020	—	$	—	541	$	54	$	10,868	$	20	$	(3,967)	$	6,975
Net income											74		74
Other comprehensive loss, net of tax									(18)				(18)
Stock Investment Plan and share-based benefit plans				1			(6)						(6)
Cash dividends declared on common stock ($0.39/common share in March)							(211)						(211)
Balance, March 31, 2020	—	$	—	542	$	54	$	10,651	$	2	$	(3,893)	$	6,814
Net income											309		309
Other comprehensive loss, net of tax									(2)				(2)
Stock Investment Plan and share-based benefit plans							22						22
Balance, June 30, 2020	—	$	—	542	$	54	$	10,673	$	—	$	(3,584)	$	7,143

	Six Months Ended June 30, 2019
	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 Investment Plan and share-based benefit plans				1			8						8
Cash dividends declared on common stock ($0.38/common share in March)							(202)						(202)
Cash dividends declared on preferred stock ($0.38/as-converted share in March)							(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 Investment Plan and share-based benefit plans				1			30						30
Balance, June 30, 2019 (1)	0.2	$	21	532	$	53	$	11,411	$	31	$	(4,247)	$	7,269

⁽¹⁾ As of June 30, 2019, there were 209,822 outstanding shares of Series A Convertible Preferred Stock.

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

4

FIRSTENERGY CORP.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

	For the Six Months Ended June 30,
(In millions)	2020		2019
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	383	$	632
Adjustments to reconcile net income to net cash from operating activities-
Loss (gain) on disposal, net of tax (Note 3)	(52)		39
Depreciation and amortization, including regulatory assets, net, and deferred debt-related costs	602		702
Deferred income taxes and investment tax credits, net	3		162
Retirement benefits, net of payments	(144)		(53)
Pension trust contributions	—		(500)
Pension and OPEB mark-to-market adjustment	423		—
Settlement agreement and tax sharing payments to the FES Debtors	(978)		—
Changes in current assets and liabilities-
Receivables	75		217
Materials and supplies	(18)		(29)
Prepaid taxes and other	(125)		(109)
Accounts payable	(83)		(183)
Accrued taxes	83		(117)
Accrued interest	20		8
Accrued compensation and benefits	(28)		(126)
Other current liabilities	(6)		(24)
Other	(5)		6
Net cash provided from operating activities	150		625
CASH FLOWS FROM FINANCING ACTIVITIES:
New financing-
Long-term debt	3,175		1,950
Redemptions and repayments-
Long-term debt	(1,082)		(757)
Short-term borrowings, net	(885)		—
Preferred stock dividend payments	—		(6)
Common stock dividend payments	(422)		(403)
Other	(44)		(28)
Net cash provided from financing activities	742		756
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,292)		(1,228)
Sales of investment securities held in trusts	39		302
Purchases of investment securities held in trusts	(53)		(322)
Asset removal costs	(102)		(103)
Other	2		15
Net cash used for investing activities	(1,406)		(1,336)
Net change in cash, cash equivalents, and restricted cash	(514)		45
Cash, cash equivalents, and restricted cash at beginning of period	679		429
Cash, cash equivalents, and restricted cash at end of period	$	165	$	474

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

5

FIRSTENERGY CORP.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

Note Number		Page Number
1	Organization and Basis of Presentation	7
2	Revenue	10
3	Discontinued Operations	13
4	Earnings Per Share of Common Stock	14
5	Pension and Other Post-Employment Benefits	17
6	Accumulated Other Comprehensive Income	18
7	Income Taxes	19
8	Fair Value Measurements	20
9	Regulatory Matters	23
10	Commitments, Guarantees and Contingencies	29
11	Segment Information	33

6

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 (a wholly owned subsidiary of MP), 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: AESC, FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPUN, Allegheny Ventures, Inc., and Suvon, LLC doing business as both FirstEnergy Home and FirstEnergy Advisors.

FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s 10 utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over 6 million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and 2 regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity, 210 MWs of which is related to the Yards Creek generating plant that is being sold pursuant to an asset purchase agreement as further discussed below.

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, 2019.

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. 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.

Capitalized Financing Costs

For each of the three months ended June 30, 2020 and 2019, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $12 million and $9 million, respectively, of allowance for equity funds used during construction and $6 million and $7 million, respectively, of capitalized interest. For each of the six months ended June 30, 2020 and 2019, capitalized financing costs on FirstEnergy’s Consolidated Statements of Income include $23 million and $22 million, respectively, of allowance for equity funds used during construction and $13 million and $12 million, respectively, of capitalized interest.

COVID-19

The outbreak of COVID-19 is a global pandemic. FirstEnergy is continuously evaluating the global pandemic and taking steps to mitigate known risks. FirstEnergy has incurred, and it is expected to incur for the foreseeable future, incremental uncollectible and other COVID-19 pandemic related expenses. COVID-19 related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements resulting from the COVID-19 pandemic. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers

7

and the health and safety of its employees, contractors and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions or any material impact on its capital spending plan.

Currently, FirstEnergy is effectively managing operations during the pandemic in order to continue to provide critical service to customers and believes it is well positioned to manage through the economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy that are presently unknown or unanticipated may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists.

Customer Receivables

Receivables from customers include distribution services and retail generation sales to residential, commercial and industrial customers of the Utilities. The allowance for uncollectible customer receivables is based on historical loss information comprised of a rolling 36-month average net write-off percentage of revenues, in conjunction with a qualitative assessment of elements that impact the collectability of receivables to determine if allowances for uncollectible accounts should be further adjusted in accordance with the accounting guidance for credit losses. Management contemplates available current information such as changes in economic factors, regulatory matters, industry trends, customer credit factors, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment.

During the second quarter of 2020, FirstEnergy reviewed its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment, which included consideration of the outbreak of COVID-19 and the impact on customer receivable balances outstanding and the ability of customers to continue payment since the pandemic began. FirstEnergy has suspended customer disconnections for nonpayment and ceased certain other collection activities as a result of the ongoing pandemic. FirstEnergy anticipates that it will not disconnect customers for non-payment prior to September 15, 2020. The impact of COVID-19 on customers’ ability to pay for service, along with the actions, FirstEnergy has taken in response to the pandemic, is expected to result in an increase in customer receivable write-offs as compared to historically incurred losses. In order to estimate the additional losses and impacts expected, FirstEnergy analyzed the likelihood of loss based on increases in customer accounts in arrears since the pandemic began in mid-March 2020 as well was what collection methods are suspended and that have historically been utilized to ensure payment. Based on this assessment, and consideration of other qualitative factors described above, FirstEnergy recognized incremental uncollectible expense of $43 million in the second quarter of 2020, of which approximately $27 million is not currently being collected through rates and as a result was deferred for future recovery under regulatory mechanisms described below.

The Ohio Companies and JCP&L had existing regulatory mechanisms in place prior to the outbreak of COVID-19, where incremental uncollectible expenses are able to be recovered through riders with no material impact to earnings. Additionally, in response to the COVID-19 pandemic, the MDPSC, NJBPU and WVPSC issued orders allowing PE, JCP&L and MP to track and create a regulatory asset for future recovery incremental costs, including uncollectible expenses and waived late payment charges, incurred as a result of the pandemic. In Pennsylvania, the PPUC authorized the Pennsylvania Companies to track all prudently incurred incremental costs arising from COVID-19, and to create a regulatory asset for future recovery of incremental uncollectible expenses incurred as a result of COVID-19 above what is included in the Pennsylvania Companies existing rates.

Receivables from customers also include PJM receivables resulting from transmission and wholesale sales. FirstEnergy’s credit risk on PJM receivables is reduced due to the nature of PJM’s settlement process whereby members of PJM legally agree to share the cost of defaults and as a result there is no allowance for doubtful accounts.

8

Activity in the allowance for uncollectible accounts on customer receivables for the six months ended June 30, 2020 and for the year ended December 31, 2019 are as follows:

	(In millions)
Balance, January 1, 2019	$	50
Charged to income (1)	81
Charged to other accounts (2)	47
Write-offs	(132)
Balance, December 31, 2019	$	46
Charged to income (3)	79
Charged to other accounts (2)	24
Write-offs	(62)
Balance, June 30, 2020	$	87

⁽¹⁾ $25 million of which was deferred for future recovery in the twelve months ended December 31, 2019.

⁽²⁾ Represents recoveries and reinstatements of accounts written off for uncollectible accounts.

⁽³⁾ $35 million of which was deferred for future recovery in the first six months of 2020.

Restricted Cash

Restricted cash primarily relates to cash collected from JCP&L, MP, PE and the Ohio Companies’ customers that is specifically used to service debt of their respective funding companies.

New Accounting Pronouncements

Recently Adopted Pronouncements

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. Prior to adoption, FirstEnergy analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities. The adoption of this standard upon January 1, 2020 did not have a material impact to FirstEnergy’s financial statements and required additional disclosures in these Notes to the Consolidated Financial Statements. Please see above for additional information on FirstEnergy’s allowance for uncollectible customer receivables.

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 allows 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. FirstEnergy adopted this standard as of January 1, 2020, with no material impact to its financial statements.

ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. FirstEnergy’s $3.5 billion Revolving Credit Facility bears interest at fluctuating interest rates based on LIBOR and contains provisions (requiring an amendment) in the event that LIBOR can no longer be used. As of June 30, 2020, FirstEnergy has not utilized any of the expedients discussed within this ASU.

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 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted.

9

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 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, 2020 and 2019, by type of service from each reportable segment:

	For the Three Months Ended June 30, 2020
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)		Total
	(In millions)
Distribution services (2)	$	1,241	$	—	$	(22)	$	1,219
Retail generation	826		—		(15)		811
Wholesale sales	50		—		2		52
Transmission (2)	—		380		—		380
Other	31		—		—		31
Total revenues from contracts with customers	$	2,148	$	380	$	(35)	$	2,493
ARP (3)	15		—		—		15
Other non-customer revenue	25		4		(15)		14
Total revenues	$	2,188	$	384	$	(50)	$	2,522

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

⁽²⁾ Includes $22 million reductions to revenue related to amounts subject to refund resulting from the Tax Act, primarily at Regulated Distribution.

⁽³⁾ ARP revenue for the three months ended June 30, 2020, is primarily related to the reconciliation of Ohio decoupling rates that became effective on February 1, 2020.

	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 (3)	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 to revenue at Regulated Transmission related to amounts subject to refund resulting from the Tax Act.

⁽³⁾ ARP revenue for the three months ended June 30, 2019, includes DMR revenue, and lost distribution and shared savings revenue in Ohio.

Other non-customer revenue also includes revenue from late payment charges of $6 million and $9 million for the three months

10

ended June 30, 2020 and 2019, respectively. Starting in mid-March 2020, certain late payment charges began to be waived in response to the COVID-19 pandemic, and as a result, FirstEnergy stopped recognizing these revenues. See Note 1, “Organization and Basis of Presentation,” for further discussion on the COVID-19 pandemic. Other non-customer revenue also includes revenue from derivatives of $6 million and $3 million for the three months ended June 30, 2020 and 2019, respectively.

The following tables represent a disaggregation of revenue from contracts with customers for the six months ended June 30, 2020 and 2019, by type of service from each reportable segment:

	For the Six Months Ended June 30, 2020
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments (1)		Total
	(In millions)
Distribution services (2)	$	2,497	$	—	$	(43)	$	2,454
Retail generation	1,730		—		(30)		1,700
Wholesale sales	121		—		3		124
Transmission (2)	—		777		—		777
Other	67		—		—		67
Total revenues from contracts with customers	$	4,415	$	777	$	(70)	$	5,122
ARP (3)	83		—		—		83
Other non-customer revenue	48		8		(30)		26
Total revenues	$	4,546	$	785	$	(100)	$	5,231

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

⁽²⁾ Includes $45 million in net reductions to revenue related to amounts subject to refund resulting from the Tax Act, primarily at Regulated Distribution.

⁽³⁾ ARP revenue for the six months ended June 30, 2020, is primarily related to the reconciliation of Ohio decoupling rates that became effective on February 1, 2020.

	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 (3)	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 net 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).

⁽³⁾ ARP revenue for the six months ended June 30, 2019, includes DMR revenue, and lost distribution and shared savings revenue in Ohio.

Other non-customer revenue includes revenue from late payment charges of $16 million and $20 million for the six months ended June 30, 2020 and 2019, respectively, that FirstEnergy expects are collectible. Other non-customer revenue also includes revenue from derivatives of $6 million and $5 million for the six months ended June 30, 2020 and 2019, respectively.

Regulated Distribution

The Regulated Distribution segment distributes electricity through FirstEnergy’s 10 utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey, 210 MWs of which are related to the Yards Creek generating plant that is being sold pursuant to an asset purchase agreement as further discussed below. Each of the Utilities earns revenue from state-regulated rate tariffs under which it provides distribution

11

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 9, “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, 2020 and 2019, by class:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Revenues by Customer Class	2020		2019		2020		2019
	(In millions)
Residential	$	1,280	$	1,123	$	2,599	$	2,607
Commercial	507		572		1,051		1,159
Industrial	259		251		536		500
Other	21		20		41		44
Total Revenues	$	2,067	$	1,966	$	4,227	$	4,310

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 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 the DMR in 2019 and decoupling revenue in 2020. Please see Note 9, “Regulatory Matters,” for further discussion on decoupling revenues in Ohio.

Regulated Transmission

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 MP, PE and WP. JCP&L had stated rates in 2019, but moved to forward-looking formula rates, subject to a refund, effective January 1, 2020, as further discussed in Note 9, “Regulatory Matters.”

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

12

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.

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, 2020 and 2019, by transmission owner:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
Transmission Owner	2020		2019		2020		2019
	(In millions)
ATSI	$	192	$	184	$	396	$	358
TrAIL	58		59		121		117
MAIT	58		50		115		99
Other	72		74		145		145
Total Revenues	$	380	$	367	$	777	$	719

3. DISCONTINUED OPERATIONS

        FES and FENOC Chapter 11 Bankruptcy 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. In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement 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 resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in 2020.

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.

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 June 30, 2020, subject to reductions in services if requested by the FES Debtors, and extensions of time, subject to FirstEnergy’s approval. 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.

As of June 30, 2020, FirstEnergy had substantially ceased providing post-emergence services to FES Debtors under the terms of the amended and restated shared services agreement. In connection with the FES’s emergence from bankruptcy, FirstEnergy entered into an amended separation agreement with the FES Debtors to implement the separation of FES Debtors and their businesses from FirstEnergy. Separation activities under the amended separation agreement are ongoing and a business separation committee exists between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of those separation activities.

        Income Taxes

For U.S. federal income taxes, the FES Debtors were included in FirstEnergy’s consolidated tax return until emergence from bankruptcy on February 27, 2020. As a result of the FES Debtors’ deconsolidation, FirstEnergy recognized a worthless stock deduction for the remaining tax basis in the FES Debtors of approximately $4.9 billion, net of unrecognized tax benefits of $316 million. Tax-effected, the worthless stock deduction is approximately $1 billion, net of valuation allowances recorded against the state tax benefit ($83 million) and the aforementioned unrecognized tax benefits ($72 million).

13

Additionally, the Tax Act amended Section 163(j) of the Internal Revenue Code, limiting interest expense deductions for corporations but with exemption for certain regulated utilities. Based on interpretation of subsequently issued proposed regulations, FirstEnergy has estimated the amount of deductible interest for its consolidated group in 2018 and 2019, with nondeductible portions being carried forward with an indefinite life and for which deferred tax assets have been recorded. However, full valuation allowances have been recorded against the deferred tax assets related to the carryforward of nondeductible interest as future utilization of the carryforwards requires profitability from sources other than regulated utility businesses. Final regulations or additional changes to proposed regulations under Section 163(j) could have a material impact on FirstEnergy’s results.

All tax expense related to nondeductible interest in 2018 and 2019 has been recorded in discontinued operations as it is entirely attributed to the inclusion of the FES Debtors in FirstEnergy's consolidated tax group. Upon emergence, FirstEnergy paid the FES Debtors $125 million to settle all reconciliations under the Intercompany Tax Allocation Agreement for 2018, 2019 and 2020 tax years, including all issues regarding nondeductible interest. Pursuant to certain safe harbor rules in existing proposed regulations under Section 163(j), and due to the FES Debtors’ emergence from bankruptcy on February 27, 2020, FirstEnergy expects all interest expense for 2020 to be fully deductible. See Note 7, “Income Taxes” for further information.

        Competitive Generation Asset Sales

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 operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. During the first quarter of 2020, FG paid AE Supply approximately $65 million of cash for related materials and supplies (at book value) and the settlement of FG’s economic interest in Pleasants.

        Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the three and six months ended June 30, 2020 and 2019, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(In millions)	2020		2019		2020		2019
Revenues	$	—	$	31	$	7	$	85
Fuel	—		(20)		(6)		(55)
Other operating expenses	—		(16)		(6)		(26)
General taxes	—		(5)		—		(9)
Other income (expense)	—		10		5		8
Loss from discontinued operations, before tax	—		—		—		3
Income tax expense	—		14		—		28
Loss from discontinued operations, net of tax	—		(14)		—		(25)
Settlement Consideration	3		10		(1)		(23)
Accelerated net pension and OPEB prior service credits	—		—		18		—
Gain (loss) on Disposal of FES and FENOC, before tax	3		10		17		(23)
Income tax expense (benefit) including worthless stock deduction	1		25		(35)		16
Gain (loss) on disposal of FES and FENOC, net of tax	2		(15)		52		(39)
Income (loss) from discontinued operations	$	2	$	(29)	$	52	$	(64)

FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. For the six months ended June 30, 2020 and 2019, cash flows from operating activities includes income (loss) from discontinued operations of $52 million and $(64) million, respectively.

4. EARNINGS PER SHARE OF COMMON STOCK

Basic EPS available to common stockholders is computed using the weighted average number of common shares outstanding during the relevant period as the denominator. The denominator for diluted EPS of common stock reflects the weighted average of common shares outstanding plus the potential additional common shares that could result if dilutive securities and other agreements to issue common stock were exercised.

14

During 2019, EPS was computed using the two-class method required for participating securities. The convertible preferred stock issued in January 2018 were considered participating securities since the shares participated in dividends on common stock on an “as-converted” basis. All convertible preferred stock was converted to common stock during 2019.

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

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 was 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 was 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	2020		2019		2020		2019
(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	307	$	341	$	331	$	696
Less: Preferred dividends	—		—		—		(3)
Less: Undistributed earnings allocated to preferred stockholders	—		(5)		—		(7)
Income from continuing operations available to common stockholders	307		336		331		686
Discontinued operations, net of tax	2		(29)		52		(64)
Less: Undistributed earnings allocated to preferred stockholders	—		1		—		1
Income (loss) from discontinued operations available to common stockholders	2		(28)		52		(63)
Income available to common stockholders, basic	$	309	$	308	$	383	$	623
Share Count information:
Weighted average number of basic shares outstanding	542		532		541		531
Assumed exercise of dilutive stock options and awards	1		1		2		2
Weighted average number of diluted shares outstanding	543		533		543		533
Income available to common stockholders, per common share:
Income from continuing operations, basic	$	0.57	$	0.63	$	0.61	$	1.29
Discontinued operations, basic	—		(0.05)		0.10		(0.12)
Income available to common stockholders, basic	$	0.57	$	0.58	$	0.71	$	1.17
Income from continuing operations, diluted	$	0.57	$	0.63	$	0.61	$	1.29
Discontinued operations, diluted	—		(0.05)		0.10		(0.12)
Income available to common stockholders, diluted	$	0.57	$	0.58	$	0.71	$	1.17

For the three and six months ended June 30, 2020 and 2019, 0 shares from stock options and awards were excluded from the calculation of diluted shares outstanding. For the three and six months ended June 30, 2019, 8 million shares associated with the assumed conversion of preferred stock were excluded as their inclusion would be antidilutive to basic EPS from continuing operations.

16

5. PENSION AND OTHER POST-EMPLOYMENT 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,	2020		2019		2020		2019
	(In millions)
Service costs	$	48	$	48	$	1	$	1
Interest costs	70		93		4		5
Expected return on plan assets	(155)		(135)		(8)		(7)
Amortization of prior service costs (credits)	1		2		(5)		(9)
Special termination costs (1)	—		(1)		—		—
Net periodic costs (credits), including amounts capitalized	$	(36)	$	7	$	(8)	$	(10)
Net periodic costs (credits), recognized in earnings	$	(62)	$	(14)	$	(8)	$	(10)

Components of Net Periodic Benefit Costs (Credits)	Pension									OPEB
For the Six Months Ended June 30,	2020		2019		2020			2019
	(In millions)
Service costs	$	100	$	96	$	2		$	2
Interest costs	145		186		8			10
Expected return on plan assets	(308)		(270)		(16)			(14)
Special termination costs (1)	—		14		—		—	—
Amortization of prior service costs (credits) (2)	11		4		(38)			(18)
One-time termination benefit (3)	8		—		—			—
Pension and OPEB mark-to-market adjustment	386		—		37			—
Net periodic costs (credits), including amounts capitalized	$	342	$	30	$	(7)		$	(20)
Net periodic costs (credits), recognized in earnings	$	296	$	(8)	$	(7)		$	(20)

⁽¹⁾ Subject to a cap, FirstEnergy agreed to fund a pension enhancement through its pension plan, for voluntary enhanced retirement packages offered to certain FES employees, as well as offer certain other employee benefits. The costs are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

⁽²⁾ 2020 includes the acceleration of $18 million in net credits as a result of the FES Debtors’ emergence during the first quarter of 2020 and is a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

⁽³⁾ Costs represent additional benefits provided to FES and FENOC employees under the approved settlement agreement and are a component of discontinued operations in FirstEnergy’s Consolidated Statements of Income.

FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in fair value of plan assets and net actuarial gains and losses annually in the fourth quarter of each fiscal year and whenever a plan is determined to qualify for remeasurement. Under the approved bankruptcy settlement agreement discussed above, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. The pension and OPEB mark-to-market adjustment primarily reflects a 38 bps decrease in the discount rate used to measure benefit obligations from December 31, 2019, partially offset by a slightly higher than expected return on assets.

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

Service costs, net of capitalization, are reported within Other operating expenses on FirstEnergy’s Consolidated Statements of Income. Non-service costs, other than the pension and OPEB mark-to-market adjustment, which is separately shown, are reported within Miscellaneous income, net, within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income.

17

6. ACCUMULATED OTHER COMPREHENSIVE INCOME

The following tables show the changes in AOCI for the three and six months ended June 30, 2020 and 2019:

	Gains & Losses on Cash Flow Hedges (1)		Defined Benefit Pension & OPEB Plans		Total
	(In millions)
AOCI Balance, April 1, 2020	$	(9)	$	11	$	2
Amounts reclassified from AOCI	1		(4)		(3)
Other comprehensive income (loss)	1		(4)		(3)
Income tax benefits on other comprehensive loss	—		(1)		(1)
Other comprehensive income (loss), net of tax	1		(3)		(2)
AOCI Balance, June 30, 2020	$	(8)	$	8	$	—
AOCI Balance, April 1, 2019	$	(10)	$	46	$	36
Amounts reclassified from AOCI	—		(7)		(7)
Other comprehensive income (loss)	—		(7)		(7)
Income tax benefits on other comprehensive loss	—		(2)		(2)
Other comprehensive income (loss), net of tax	—		(5)		(5)
AOCI Balance, June 30, 2019	$	(10)	$	41	$	31
	Gains & Losses on Cash Flow Hedges (1)		Defined Benefit Pension & OPEB Plans		Total
	(In millions)
AOCI Balance, January 1, 2020	$	(9)	$	29	$	20
Amounts reclassified from AOCI	1		(27)		(26)
Other comprehensive income (loss)	1		(27)		(26)
Income tax benefits on other comprehensive loss	—		(6)		(6)
Other comprehensive income (loss), net of tax	1		(21)		(20)
AOCI Balance, June 30, 2020	$	(8)	$	8	$	—
AOCI Balance, January 1, 2019	$	(11)	$	52	$	41
Amounts reclassified from AOCI	1		(14)		(13)
Other comprehensive income (loss)	1		(14)		(13)
Income taxes (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

⁽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 in the three and six months ended June 30, 2020 and 2019:

	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)	2020		2019		2020		2019
	(In millions)
Gains & losses on cash flow hedges
Long-term debt	$	1	$	—	$	1	$	1	Interest expense
	$	1	$	—	$	1	$	1	Net of tax
Defined benefit pension and OPEB plans
Prior-service costs	$	(4)	$	(7)	$	(27)	$	(14)	(2)
	1		2		6		3		Income taxes
	$	(3)	$	(5)	$	(21)	$	(11)	Net of tax
(1) Amounts in parenthesis represent credits to the Consolidated Statements of Income from AOCI.
(2) 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 Post-Employment Benefits.”

7. INCOME TAXES

FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2020 and 2019. 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 on continuing operations for the three months ended June 30, 2020 and 2019, was 17.7% and 19.2%, respectively. The change in the effective tax rate was primarily due to a $10 million benefit from the accelerated amortization of certain investment tax credits.

FirstEnergy’s effective tax rate on continuing operations for the six months ended June 30, 2020 and 2019, was 1.8% and 20.0%, respectively. The change in effective tax rate was primarily due to a $52 million reduction in valuation allowances from the recognition of deferred gains on prior intercompany generation asset transfers triggered by the FES Debtors’ emergence from bankruptcy and deconsolidation from FirstEnergy’s consolidated federal income tax group in the first quarter of 2020, and a $10 million benefit from accelerated amortization of certain investment tax credits in the second quarter of 2020. See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations.

During the three months ended June 30, 2020, FirstEnergy effectively settled an uncertain tax position for a state income tax audit, resulting in an income tax benefit of approximately $2 million. During the six months ended June 30, 2020, FirstEnergy also remeasured its reserve for uncertain tax positions for federal and state tax benefits related to the worthless stock deduction, resulting in a net decrease to the reserve of approximately $28 million, none of which had an impact on the effective tax rate. As of June 30, 2020, it is reasonably possible that within the next twelve months FirstEnergy could record a net decrease of approximately $57 million to its reserve for uncertain tax positions due to the expiration of statute of limitations or resolution with taxing authorities, of which approximately $55 million would impact FirstEnergy’s effective tax rate.

On March 27, 2020, the President signed into law the CARES Act, an economic stimulus package in response to the COVID-19 pandemic. The CARES Act contains several corporate income tax provisions, including making remaining AMT credits immediately refundable; providing a 5-year carryback of NOLs generated in tax years 2018, 2019, and 2020, and removing the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before 2021; and temporarily liberalizing the interest deductibility rules under Section 163(j) of the Tax Act, by raising the adjusted taxable income limitation from 30% to 50% for tax years 2019 and 2020 and giving taxpayers the election of using 2019 adjusted taxable income for purposes of computing 2020 interest deductibility. FirstEnergy has approximately $18 million of refundable AMT credits that will be fully refundable through the CARES Act, however, does not expect to generate additional income tax refunds from the NOL carryback provision and expects interest to be fully deductible starting in 2020. FirstEnergy does not currently expect the other provisions of the CARES Act to have a material effect on current income tax expense or the realizability of deferred income tax assets.

On July 28, 2020, the IRS issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on the computation of interest expense and limitation amount, as well as rules relevant to status as a regulated utility business and the allocation of consolidated group interest expense between utility and non-utility businesses. FirstEnergy is analyzing the potential impacts of the final regulations, including any impact they have resulting from the CARES Act.

19

8. 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, 2020, from those used as of December 31, 2019. The determination of the fair value measures takes into consideration various factors, including but not limited to, nonperformance risk, counterparty credit risk and the impact of credit enhancements (such as cash deposits, LOCs and priority interests). The impact of these forms of risk was not significant to the fair value measurements.

20

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, 2020														December 31, 2019
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets	(In millions)
Corporate debt securities	$	—	$	131	$	—	$	131	$	—	$	135	$	—	$	135
Derivative assets FTRs(1)	—		—		7		7		—		—		4		4
Equity securities	2		—		—		2		2		—		—		2
U.S. state debt securities	—		274		—		274		—		271		—		271
Other(2)	116		802		—		918		627		789		—		1,416
Total assets	$	118	$	1,207	$	7	$	1,332	$	629	$	1,195	$	4	$	1,828
Liabilities
Derivative liabilities FTRs(1)	$	—	$	—	$	(2)	$	(2)	$	—	$	—	$	(1)	$	(1)
Derivative liabilities NUG contracts(1)	—		—		—		—		—		—		(16)		(16)
Total liabilities	$	—	$	—	$	(2)	$	(2)	$	—	$	—	$	(17)	$	(17)
Net assets (liabilities)(3)	$	118	$	1,207	$	5	$	1,330	$	629	$	1,195	$	(13)	$	1,811

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

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

⁽³⁾Excludes $(19) million and $(16) million as of June 30, 2020 and December 31, 2019, 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, 2020, and December 31, 2019:

	NUG Contracts(1)										FTRs(1)
	Derivative Assets		Derivative Liabilities		Net		Derivative Assets		Derivative Liabilities		Net
	(In millions)
January 1, 2019 Balance	$	—	$	(44)	$	(44)	$	10	$	(1)	$	9
Unrealized loss	—		(11)		(11)		(1)		—		(1)
Purchases	—		—		—		6		(4)		2
Settlements	—		39		39		(11)		4		(7)
December 31, 2019 Balance	$	—	$	(16)	$	(16)	$	4	$	(1)	$	3
Unrealized loss	—		(10)		(10)		—		(1)		(1)
Purchases	—		—		—		7		(2)		5
Settlements	—		26		26		(4)		2		(2)
June 30, 2020 Balance	$	—	$	—	$	—	$	7	$	(2)	$	5

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

21

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, 2020:

	Fair Value, Net (In millions)		Valuation Technique	Significant Input	Range										Weighted Average		Units
FTRs	$	5	Model	RTO auction clearing prices	$	0.20	to	$	2.00			$1.00			Dollars/MWH
NUG Contracts	$	—	Model	Generation	400		to	24,000				5,000			MWH
							Regional electricity prices			$	20.10	to	$	32.00		$26.10		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 and nuclear fuel disposal trusts 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. As further discussed in Note 10, "Commitments, Guarantees and Contingencies", assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheets associated with the TMI-2 transaction consist of an ARO of $709 million, NDTs of $882 million, as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.

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, 2020, and December 31, 2019:

	June 30, 2020(1)														December 31, 2019(2)
	Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value (3)		Cost Basis		Unrealized Gains		Unrealized Losses		Fair Value (3)
	(In millions)
Debt securities	$	407	$	8	$	(8)	$	407	$	403	$	9	$	(11)	$	401

⁽¹⁾ Excludes short-term cash investments of $753 million, of which $750 million is classified as held for sale.

        ⁽²⁾ Excludes short-term cash investments of $751 million, of which $747 million is classified as held for sale.

        ⁽³⁾ Includes $132 million and $135 million classified as held for sale as of June 30, 2020 and December 31, 2019, respectively.

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, 2020 and 2019, were as follows:

	For the Three Months Ended June 30,						For the Six Months Ended June 30,
	2020		2019		2020		2019
	(In millions)
Sale proceeds	$	26	$	149	$	39	$	302
Realized gains	—		5		4		12
Realized losses	(2)		(5)		(7)		(11)
Interest and dividend income	9		11		14		20

22

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 $297 million and $299 million as of June 30, 2020, and December 31, 2019, 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 finance lease obligations and net unamortized debt issuance costs, premiums and discounts as of June 30, 2020 and December 31, 2019:

	June 30, 2020		December 31, 2019
	(In millions)
Carrying value (1)	$	22,168	$	20,074
Fair value	$	26,278	$	22,928

⁽¹⁾ The carrying value as of June 30, 2020, includes $3,175 million of debt issuances and $1,082 million of redemptions that occurred in 2020.

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, 2020, and December 31, 2019.

9. REGULATORY MATTERS

STATE REGULATION

Each of the Utilities’ retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in 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 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.

23

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.

Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 pandemic. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently-incurred incremental costs arising from the COVID-19 pandemic, including incremental uncollectible expenses. On July 8, 2020, the MDPSC issued a notice opening a public conference to collect information from utilities and other stakeholders about the impacts of the COVID-19 pandemic on the utilities and their customers, and indicated that it would hold a hearing to discuss that information in late August 2020.

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. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.

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 May 8, 2019, the NJBPU approved a Stipulation of Settlement submitted by JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition to implement JCP&L’s infrastructure plan, JCP&L Reliability Plus. The plan provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020, to enhance the reliability and resiliency of JCP&L’s distribution system and reduce the frequency and duration of power outages. 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. The NJBPU approved adjusted rates that took effect on March 1, 2020.

On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase of $186.9 million on an annual basis, which represents an overall average increase in JCP&L rates of 7.8%. The filing seeks to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. JCP&L proposed a rate effective date of March 19, 2020. On March 9, 2020, the Board issued an order suspending JCP&L’s proposed rates for four months. Based on the historical procedures of the NJBPU Board a second suspension order is expected with revised base rates becoming effective in late November 2020. JCP&L filed updates to the requested distribution base rate in both June and July 2020, resulting in JCP&L seeking a total annual distribution base rate increase of approximately $185 million. On August 11, 2020, the administrative law judge issued a prehearing order with a procedural schedule that calls for evidentiary hearings to occur the week of November 16, 2020.

On April 6, 2020, JCP&L signed an asset purchase agreement with Yards Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility in NJ (210 MWs). Subject to terms and conditions of the agreement, the base purchase price is $155 million. Completion of the transaction is subject to several closing conditions, including approval by the NJBPU and FERC. On July 31, 2020, FERC approved transfer of JCP&L’s interest in the hydroelectric operating license; however, JCP&L’s application for authorization to transfer its ownership interest in the Yards Creek facility remains pending at FERC. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur in the first half of 2021. Assets held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of property, plant and equipment of $44 million, which is included in the regulated distribution segment. Treatment of the gain is subject to NJBPU approval.

24

On June 10, 2020, the NJBPU issued an order establishing a framework for the filing of utility-run energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act. Under the established framework, JCP&L will recover its program investments over a ten year amortization period and its operations and maintenance expenses on an annual basis, be eligible to receive lost revenues on energy savings that resulted from its programs and be eligible for incentives or subject to penalties based on its annual program performance, beginning in the fifth year of its program offerings. JCP&L’s energy efficiency and peak demand reduction program plan is required to be filed no later than September 25, 2020, and is anticipated to be implemented July 1, 2021.

On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently-incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 through September 30, 2021, or until the Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case.

OHIO

The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $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. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; and (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. ESP IV further provided for the Ohio Companies to collect through the DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that the DMR is lawful, and remanded the matter to the PUCO with instructions to remove the DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through the DMR, credit back to customers a refund of the DMR funds collected since July 2, 2019, and remove the DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of the DMR revenues 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. The Ohio Companies are contesting this appeal but are unable to predict the outcome of this matter. The SCOH heard the argument on this matter on May 12, 2020.

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 and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered that a wind-down of statutorily required energy efficiency programs shall commence on September 30, 2020, and the programs shall terminate on December 31, 2020, and that the Ohio Companies’ existing portfolio plans are extended through 2020 without changes.

On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which 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. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. Ohio Senate Bill 346 and Ohio House Bill 738 were introduced on July 28, 2020 and July 29, 2020, respectively, and each would, among other things, repeal the Ohio legislation that established support for nuclear energy supply in Ohio and a provision that provides for a decoupling mechanism for Ohio electric utilities as well as ending current energy efficiency program mandates.

On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ 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 to flow back to customers. The settlement had 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.

25

In March 2020, the PUCO issued entries directing utilities to review their service disconnection and restoration policies and suspend, for the duration of the COVID-19 pandemic, otherwise applicable requirements that may impose a service continuity hardship or service restoration hardship on customers. The Ohio Companies are utilizing their existing approved cost recovery mechanisms where applicable to address the financial impacts of these directives. On July 31, 2020, the Ohio Companies filed with the PUCO their transition plan and requests for waivers to allow for the safe resumption of normal business operations, including service disconnections for non-payment, on or after September 15, 2020.

On July 29, 2020, the PUCO consolidated the Ohio Companies’ Applications for determination of the existence of significantly excessive earnings, or SEET, under ESP IV for calendar years 2018 and 2019, which had been previously filed on July 15, 2019, and May 15, 2020, respectively, and set a procedural schedule with evidentiary hearings scheduled for October 29, 2020. The calculations included in the Ohio Companies’ SEET filings for calendar years 2018 and 2019 demonstrate that the Ohio Companies did not have significantly excessive earnings, however, FirstEnergy and the Ohio Companies are unable to predict the PUCO’s ultimate determination of the applications. On August 3, 2020, the OCC filed an interlocutory appeal asking the PUCO to stay the SEET proceeding until the SCOH determines whether DMR should be excluded from the SEET, as further discussed above. Further, on July 29, 2020, Ohio House Bill 740 was introduced, which would repeal legislation passed last year that permitted the Ohio Companies to file their SEET results on a consolidated basis instead of on an individual company basis.

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 was separately tracked and its treatment will be addressed 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.

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. On June 18, 2020, the PPUC entered a Final Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026. The Final Implementation Order set demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. Phase IV plans must be filed by November 30, 2020.

Pennsylvania EDCs may file with the PPUC for approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On August 30, 2019, the Pennsylvania Companies filed Petitions for approval of new LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On January 16, 2020, the PPUC approved the LTIIPs without modification. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016. On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. On March 12, 2020, an order was entered approving a settlement by all parties to that case which provides for a temporary increase in the recoverability cap from 5% to 7.5%, to expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program.

Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates, which decision was appealed by the Pennsylvania OCA to the Pennsylvania Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an Order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. Briefs were filed on June 25, 2020. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy.

The PPUC issued an order on March 13, 2020, forbidding utilities from terminating residential service for non-payment for the duration of the COVID-19 pandemic. On May 13, 2020, the PPUC issued a Secretarial letter directing utilities to track all prudently-incurred incremental costs arising from the COVID-19 pandemic, and to create a regulatory asset for future recovery of incremental uncollectibles incurred as a result of the COVID-19 pandemic and termination moratorium.

26

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.

On August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates.

On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019.

On March 13, 2020, the WVPSC urged all utilities to suspend utility service terminations except where necessary as a matter of safety or where requested by the customer. On May 15, 2020, the WVPSC issued an order to authorize MP and PE to record a deferral of additional, extraordinary costs directly related to complying with the various COVID-19 government shut-down orders and operational precautions, including impacts on uncollectible expense and cash flow related to temporary discontinuance of service terminations for non-payment and any credits to minimum demand charges associated with business customers adversely impacted by shut-downs or temporary closures related to the pandemic.

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 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 in the case of the Utilities major wholesale purchases remain subject to review and 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 six 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.

ATSI Transmission Formula Rate

On May 1, 2020, ATSI filed amendments to its formula rate to recover regulatory assets for certain costs that ATSI incurred as a

27

result of its 2011 move from MISO to PJM, certain costs allocated to ATSI by FERC for transmission projects that were constructed by other MISO transmission owners, certain income tax-related adjustments, including, but not limited to impacts from the Tax Act discussed further below, and certain costs for transmission-related vegetation management programs. The amount on FirstEnergy’s Consolidated Balance Sheet for these regulatory assets was approximately $76 million and $73 million, as of June 30, 2020 and December 31, 2019, respectively. Per prior FERC orders, ATSI included a “cost-benefit study” to support recovery of ATSI’s costs to move to PJM, and the MISO transmission project costs that were allocated to ATSI. Certain intervenors filed protests of the formula rate amendments on May 29, 2020, and ATSI filed a reply on June 15, 2020. On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund, suspending the effective date for five months, and setting the matter for hearing and settlement proceedings. ATSI is engaged in settlement negotiations with the other parties.

FERC Actions on Tax Act

On March 15, 2018, FERC initiated proceedings on the question of how to 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 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (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. Per FERC directives, ATSI submitted its compliance filing on May 1, 2020. MAIT submitted its compliance filing on June 1, 2020. Certain intervenors filed protests of the compliance filings, to which ATSI and MAIT responded. On May 15, 2020, TrAIL submitted its compliance filing and on June 1, 2020, PATH submitted its required compliance filing. These compliance filings each remain pending before FERC. MP, WP and PE – as holders of a “stated” transmission rate – are allowed to address these requirements in the course of their next transmission rates proceeding. JCP&L is addressing these requirements as part of its pending transmission formula rate case.

Transmission ROE Methodology

FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will 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 replacement 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. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. Certain parties, including the Utilities, sought rehearing of FERC’s decision in the MISO utilities proceeding and, on May 21, 2020, FERC issued Opinion No. 569-A that changed FERC’s ROE methodology. Under this methodology FERC established an ROE that is based on three financial models – discounted cash flow, capital-asset pricing, and risk premium – to calculate a composite zone of reasonableness. FERC noted that utilities could, in utility-specific proceedings, ask to have the expected earnings methodology included in calculating the utility’s authorized ROE. FERC also noted that, going forward, it will divide that zone into three equal parts, to be used for high risk, normal risk, and low risk utilities. A given utility will be assigned to one of these three parts of the zone of reasonableness, and its ROE will be set at the median or midpoint of the other utilities that are in the applicable third of the zone. FirstEnergy filed a request for rehearing, which FERC denied on July 22, 2020. FirstEnergy also initiated appellate proceedings of FERC’s Opinion Nos. 569 and 569-A. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis.

On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the 2005 Energy Policy Act. Initial comments were submitted July 1, 2020, and reply comments were filed on July 16, 2020. FirstEnergy participated through EEI and through a consortium of PJM Transmission Owners.

JCP&L Transmission Formula Rate

On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC proceeding are engaged in settlement negotiations.

28

10. COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

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

As of June 30, 2020, outstanding guarantees and other assurances aggregated approximately $1.7 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries ($1.0 billion), other guarantees ($114 million) and other assurances ($503 million).

COLLATERAL AND CONTINGENT-RELATED FEATURES

In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain 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 rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

Certain agreements entered into by FE and its subsidiaries have margining provisions that require posting of collateral. As of June 30, 2020, $1 million of collateral has been posted by FE or its subsidiaries.

These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2020:

Potential Collateral Obligations		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
Upon Further Downgrade		$	47	$	—	$	47
Surety Bonds (Collateralized Amount) (1)		66		257		323
Total Exposure from Contractual Obligations		$	113	$	257	$	370

⁽¹⁾Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure).

OTHER COMMITMENTS AND CONTINGENCIES

FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding’s outstanding principal balance is $114 million as of June 30, 2020. 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.

29

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. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. 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, 2020, 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, 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 nine states (including 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. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On May 19, 2020, the D.C. Circuit affirmed the EPA’s denial of the Delaware petition and affirmed in part the denial of Maryland petition deferring to the EPA’s finding that upwind sources with SCR controls, including Harrison, are already optimizing their use and therefore it is not cost effective to require additional control measures. Thus, the D.C. Circuit dismissed the appeals filed by the States of Delaware and Maryland as to Harrison. The D.C. Circuit Court remanded to the EPA the issue raised in the Maryland petition, of whether EGU’s in upwind states utilizing SNCR controls could increase operating time thereby reducing NOx emissions that may impact downwind states’ ozone compliance. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. 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 GHG 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

30

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. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes 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. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. 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.

On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. The EPA has proposed a penalty of $900,000 to settle alleged past boron exceedances at the Mingo and Springdale landfills. Negotiations are continuing and WP is unable to predict the outcome of this matter.

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. On December 2, 2019, the EPA published a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August

31

31, 2020. The proposed rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria. On July 29, 2020, the EPA published a final rule revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria.

FE 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, 2020, 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 $104 million have been accrued through June 30, 2020. Included in the total are accrued liabilities of approximately $68 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

United States v. Larry Householder, et al

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. FirstEnergy is cooperating fully in the investigation. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

Legal Proceedings Relating to United States v. Larry Householder, et al

In addition to the subpoenas referenced above under “—United States v. Larry Householder, et. al,”, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to Ohio House Bill 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder.

•Gendrich v. Anderson, et al and Sloan v. Anderson, et al (Common Pleas Court, Summit County, OH); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty.

•Smith v. FirstEnergy Corp. et al (Federal District Court, S.D. Ohio); on July 27, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE and FESC, alleging civil Racketeer Influenced and Corrupt Organizations Act violations.

•Owens v. FirstEnergy Corp. et al (Federal District Court, S.D. Ohio); on July 28, 2020, a purported stockholder of FE filed a putative class action lawsuit against FE and certain FE officers, purportedly on behalf of all purchasers of FE common stock from February 21, 2017 through July 21, 2020, asserting claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, alleging misrepresentations or omissions by FirstEnergy concerning its business and results of operations.

•Buldas v. FirstEnergy Corp. et al and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al (Federal District Court, S.D. Ohio); on July 31, 2020 and August 5, 2020, respectively, purported customers of FirstEnergy filed putative class action lawsuits against FE and FESC alleging civil violations of the Racketeer Influenced and Corrupt Organizations Act and the Ohio Corrupt Activity Act.

•Emmons v. FirstEnergy Corp. et al (Common Pleas Court, Cuyahoga County, OH); on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, OE, TE and CEI, alleging several causes of action, including negligence and/or gross negligence, breach of contract, unjust enrichment, and unfair or deceptive consumer acts or practices.

•Miller v. Anderson, et al (Federal District Court, N.D. Ohio); on August 7, 2020, a purported stockholder of FE filed a shareholder derivative action lawsuit against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty and violations of Section 14(a) of the Securities Exchange Act of 1934.

The plaintiffs in each of the above cases, seek, among other things, to recover an unspecified amount of damages. The Ohio Attorney General may be considering legal action and, in a letter dated July 24, 2020, notified FE of its duty to not destroy documents in its custody or control regarding Ohio House Bill 6. The outcome of any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

32

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, 2020, JCP&L, ME and PN had in total approximately $882 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 October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of June 30, 2020. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. On Monday, August 10, 2020, JCP&L, ME, PN, GPUN, TMI-2 Solutions, LLC, and the PA DEP reached a settlement agreement regarding the decommissioning of TMI-2. The settlement agreement provides for increased and detailed oversight by the PA DEP over the decommissioning work, expenditures, and environmental impacts of the dismantlement of TMI-2 by TMI-2 Solutions, LLC. In addition, the PA DEP withdrew its objection to the TMI-2 transfer in the NRC proceedings. Both the NRC and NJBPU proceedings are ongoing. Assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $709 million, NDTs of $882 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.

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 and emerged on February 27, 2020. See Note 3, “Discontinued Operations,” for additional discussion.

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 9, “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.

11. SEGMENT INFORMATION

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

The Regulated Distribution segment distributes electricity through FirstEnergy’s 10 utility operating companies, serving approximately 6000000 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, of which, 210 MWs are related to the Yards Creek generating station that is being sold pursuant to an asset purchase agreement as further discussed below. 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. Included within the segment are $882 million of assets classified as held for sale as of June 30, 2020 and December 31, 2019 associated with the asset purchase and sale agreements with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC. See Note 10, "Commitments, Guarantees and Contingencies" for additional information. Also included within the segment is $44 million of assets classified as held for sale as of June 30, 2020 associated with the asset purchase agreement with Yards Creek Energy, LLC to transfer JCP&L’s 50% interest in the Yards Creek pumped-storage hydro generation station (210 MWs). See Note 9, "Regulatory Matters" for additional information.

33

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 JCP&L, MP, PE and WP. Effective January 1, 2020, JCP&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. 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.

Corporate/Other reflects corporate support costs not charged to FE’s subsidiaries, including FE’s retained Pension and OPEB assets and liabilities of the FES Debtors, 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, 2020, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of June 30, 2020, Corporate/Other had approximately $7.85 billion of FE holding company debt.

34

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		FirstEnergy Consolidated
	(In millions)
June 30, 2020
External revenues	$	2,140	$	380	$	2	$	—	$	2,522
Internal revenues	48		4		—		(52)		—
Total revenues	$	2,188	$	384	$	2	$	(52)	$	2,522
Depreciation	226		78		—		17		321
Amortization of regulatory assets, net	10		3		—		—		13
Miscellaneous income (expense), net	90		8		7		(2)		103
Interest expense	123		55		87		(2)		263
Income taxes (benefits)	67		34		(35)		—		66
Income (loss) from continuing operations	251		114		(58)		—		307
Property additions	$	386	$	270	$	20	$	—	$	676
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 (expense), 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
For the Six Months Ended
June 30, 2020
External revenues	$	4,451	$	777	$	3	$	—	$	5,231
Internal revenues	95		8		—		(103)		—
Total revenues	$	4,546	$	785	$	3	$	(103)	$	5,231
Depreciation	449		154		2		33		638
Amortization of regulatory assets, net	59		6		—		—		65
Miscellaneous income (expense), net	165		14		32		(8)		203
Interest expense	250		107		177		(8)		526
Income taxes (benefits)	35		68		(97)		—		6
Income (loss) from continuing operations	387		231		(287)		—		331
Property additions	$	724	$	539	$	29	$	—	$	1,292
June 30, 2019
External revenues	$	4,671	$	720	$	8	$	—	$	5,399
Internal revenues	94		8		—		(102)		—
Total revenues	$	4,765	$	728	$	8	$	(102)	$	5,399
Depreciation	429		140		3		34		606
Amortization (deferral) of regulatory assets, net	37		5		—		—		42
Miscellaneous income (expense), 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
As of June 30, 2020
Total assets	$	29,863	$	11,914	$	626	$	—	$	42,403
Total goodwill	$	5,004	$	614	$	—	$	—	$	5,618
As of December 31, 2019
Total assets	$	29,642	$	11,611	$	1,015	$	33	$	42,301
Total goodwill	$	5,004	$	614	$	—	$	—	$	5,618

35

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.

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, of which, 210 MWs are related to the Yards Creek generating station that is being sold pursuant to an asset purchase agreement as further discussed below. 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 JCP&L, MP, PE and WP. Effective January 1, 2020, JCP&L's transmission rates became forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. 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.

Corporate/Other reflects corporate support costs not charged to FE’s subsidiaries, including FE’s retained Pension and OPEB assets and liabilities of the FES Debtors, 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, 2020, 67 MWs of electric generating capacity, representing AE Supply’s OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of June 30, 2020, Corporate/Other had approximately $7.85 billion of FE holding company debt.

36

EXECUTIVE SUMMARY

FirstEnergy is a forward-thinking fully regulated electric utility focused 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 that supports FE's dividend.

The outbreak of COVID-19 is a global pandemic. FirstEnergy is taking steps to mitigate known risks and is continuously evaluating the rapidly evolving situation based on guidance from governmental officials and public health experts. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of FirstEnergy’s employees, contractors and customers is its first priority. FirstEnergy is effectively managing its operations, while still providing flexibility for approximately 7,000 of its 12,000 employees to work from home.

Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing pandemic. FirstEnergy anticipates that it will not disconnect customers for non-payment prior to September 15, 2020. Additionally, FirstEnergy has incurred, and it is expected to incur for the foreseeable future, incremental uncollectible and other COVID-19 related expenses. Such incrementally incurred COVID-19 pandemic related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements resulting from the COVID-19 pandemic. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The Ohio Companies and JCP&L had existing regulatory mechanisms in place prior to the outbreak of COVID-19, where incremental uncollectible expenses are able to be recovered through riders with no material impact to earnings. Additionally, in response to the COVID-19 pandemic, the MDPSC, NJBPU and WVPSC issued orders allowing PE, JCP&L and MP to track and create a regulatory asset for future recovery of incremental costs, including uncollectible expenses and waived late payment charges, incurred as a result of the pandemic. In Pennsylvania, the PPUC authorized utilities to track all prudently-incurred incremental costs arising from COVID-19, and to create a regulatory asset for future recovery of incremental uncollectible expense incurred as a result of COVID-19 above what is included in the Pennsylvania Companies existing rates.

FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions or any material impact to its capital spending plan. FirstEnergy’s Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory. Two-thirds of base distribution revenues come from the residential customer class, along with a decoupled rate structure in Ohio, which accounts for approximately 20% of total retail load. FirstEnergy’s commercial and industrial revenues are primarily fixed and demand-based, rather than volume-based. As a result of this, FirstEnergy’s Distribution and Transmission investments provide stable and predictable earnings. However, due to the actions taken by state governments in our service territories limiting certain commercial and industrial activities, FirstEnergy’s residential load has increased, while commercial and industrial loads have declined, however, the magnitude of future load trends are currently unknown and difficult to predict. Related to FirstEnergy’s pension investments, the asset allocation is conservative, with no required contributions until 2022 and the funded status was at 77% as of June 30, 2020, which is essentially unchanged from the end of 2019 at 79%. FirstEnergy believes it is well positioned to manage the economic slowdown resulting from the COVID-19 pandemic. However, the situation remains fluid and future impacts to FirstEnergy, that are presently unknown or unanticipated, may occur.

In 2020, FirstEnergy continues to execute its regulated growth plans, through the following achievements and plans:

•Implemented forward-looking rates, subject to refund, at JCP&L effective January 1, 2020,

•OH Decoupling rider went into effect on February 1, 2020,

•JCP&L applied for a distribution base rate increase of $185 million annually, and, subject to NJBPU approval, would anticipate that the new rates become effective in late November 2020,

•PAPUC-approved Penn DSIC waiver on March 12, 2020,

•Completed final step of FirstEnergy’s strategy to exit the competitive generation business with FES Debtors’ emergence on February 27, 2020, and

•IRP filing in West Virginia to be made by December 30, 2020.

With an operating territory of 65,000 square miles, 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 over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. 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.

37

With approximately 24,500 miles of transmission lines in operation, the Regulated Transmission business is the centerpiece of FirstEnergy’s regulated investment strategy with nearly 90% of its capital investments recovered under forward-looking formula rates at the Transmission Companies, and beginning in 2020, JCP&L. Regulated Transmission has also experienced significant growth as part of its Energizing the Future transmission plan with plans to invest over $7 billion in capital from 2018 to 2023, which is expected to result in Regulated Transmission rate base compounded annual growth rate of approximately 10% from 2018 through 2023.

FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, 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 November 2018, the Board of Directors approved a dividend policy that includes a targeted payout ratio. As a first step, the Board declared a $0.02 increase to the common dividend payable March 1, 2019, to $0.38 per share, which represents an increase of 6% compared to the quarterly dividend of $0.36 per share that had been paid since 2014. In November 2019, the Board declared a $0.01 increase to the common dividend payable March 1, 2020, to $0.39 per share, which represents a 3% increase. Modest dividend growth enables enhanced shareholder returns, while still allowing for continued substantial regulated investments. Dividend payments are subject to declaration by the Board and future dividend decisions determined by the Board may be impacted by earnings growth, cash flows, credit metrics and other business conditions.

FirstEnergy is progressing in its sustainability efforts. In 2019, FirstEnergy's Sustainability group focused on the continued realization of sustainability accomplishments. In November 2019, FirstEnergy's Corporate Responsibility Report was published. The report addresses FirstEnergy's work to reduce the environmental impact of our operations, including progress on our CO₂ reduction goal, as we continue to build, strengthen and modernize our transmission and distribution system. The report also describes FirstEnergy's high standards for corporate governance and our work to improve lives in our communities, while providing safe, reliable electric service to our customers. In 2020, FirstEnergy is focusing on additional initiatives that aim to inform, engage and achieve its sustainability goals, and demonstrate its commitment to stakeholders.

The $2.5 billion equity issuance in 2018 strengthened FirstEnergy’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for its regular stock investment and employee benefit plans.

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. In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement 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 resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in 2020.

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 operated Pleasants until ownership was transferred on January 30, 2020. AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which was not transferred, and FE will provide guarantees for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

As of June 30, 2020, FirstEnergy had substantially ceased providing post-emergence services to FES Debtors under the terms of the amended and restated shared services agreement. In connection with the FES’s emergence from bankruptcy, FirstEnergy entered into an amended separation agreement with the FES Debtors to implement the separation of FES Debtors and their businesses from FirstEnergy. Separation activities under the amended separation agreement are ongoing and a business separation committee exists between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of those separation activities.

38

The emergence of the FES Debtors from bankruptcy represents the final step 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.

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. FirstEnergy is cooperating fully in the investigation. In addition to the subpoenas referenced above, certain FE shareholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, each relating to the allegations against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. FE, at the direction of the independent members of its Board of Directors, is conducting an internal investigation into the matters raised in the Householder complaint. The FirstEnergy leadership team remains focused on executing its strategy and running the business. See “Outlook - Other Legal Proceedings” below for additional details on the government investigation and subsequent litigation surrounding the investigation of Ohio House Bill 6. The outcome of the government investigation and any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows.

FINANCIAL OVERVIEW AND RESULTS OF OPERATIONS

(In millions)	For the Three Months Ended June 30,														For the Six Months Ended June 30,
	2020		2019		Change						2020		2019		Change
Revenues	$	2,522	$	2,516	$	6	—	%	$	5,231	$	5,399	$	(168)	(3)	%
Operating expenses	2,007		1,931		76		4	%	4,184		4,185		(1)		—	%
Operating income	515		585		(70)		(12)	%	1,047		1,214		(167)		(14)	%
Other expenses, net	(142)		(163)		21		13	%	(710)		(344)		(366)		(106)	%
Income before income taxes	373		422		(49)		(12)	%	337		870		(533)		(61)	%
Income taxes	66		81		(15)		(19)	%	6		174		(168)		(97)	%
Income from continuing operations	307		341		(34)		(10)	%	331		696		(365)		(52)	%
Discontinued operations, net of tax	2		(29)		31		107	%	52		(64)		116		181	%
Net income	$	309	$	312	$	(3)	(1)	%	$	383	$	632	$	(249)	(39)	%

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 11, “Segment Information,” of the Notes to Consolidated Financial Statements.

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

39

Summary of Results of Operations — Second Quarter 2020 Compared with Second Quarter 2019

Financial results for FirstEnergy’s business segments in the second quarter of 2020 and 2019 were as follows:

Second Quarter 2020 Financial Results	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	2,132	$	380	$	(35)	$	2,477
Other	56		4		(15)		45
Total Revenues	2,188		384		(50)		2,522
Operating Expenses:
Fuel	77		—		—		77
Purchased power	610		—		3		613
Other operating expenses	733		62		(65)		730
Provision for depreciation	226		78		17		321
Amortization of regulatory assets, net	10		3		—		13
General taxes	189		56		8		253
Total Operating Expenses	1,845		199		(37)		2,007
Operating Income (Loss)	343		185		(13)		515
Other Income (Expense):
Miscellaneous income, net	90		8		5		103
Interest expense	(123)		(55)		(85)		(263)
Capitalized financing costs	8		10		—		18
Total Other Expense	(25)		(37)		(80)		(142)
Income (Loss) Before Income Taxes (Benefits)	318		148		(93)		373
Income taxes (benefits)	67		34		(35)		66
Income (Loss) From Continuing Operations	251		114		(58)		307
Discontinued operations, net of tax	—		—		2		2
Net Income (Loss)	$	251	$	114	$	(56)	$	309

40

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

41

Changes Between Second Quarter 2020 and Second Quarter 2019 Financial Results	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	1	$	13	$	(3)	$	11
Other	(5)		(1)		1		(5)
Total Revenues	(4)		12		(2)		6
Operating Expenses:
Fuel	(52)		—		—		(52)
Purchased power	4		—		(2)		2
Other operating expenses	103		(2)		23		124
Provision for depreciation	6		7		(1)		12
Amortization of regulatory assets, net	(24)		—		—		(24)
General taxes	12		4		(2)		14
Total Operating Expenses	49		9		18		76
Operating Income (Loss)	(53)		3		(20)		(70)
Other Income (Expense):
Miscellaneous income, net	44		4		(25)		23
Pension and OPEB mark-to-market adjustment	—		—		—		—
Interest expense	1		(7)		2		(4)
Capitalized financing costs	1		2		(1)		2
Total Other Expense	46		(1)		(24)		21
Income (Loss) Before Income Taxes (Benefits)	(7)		2		(44)		(49)
Income taxes (benefits)	—		4		(19)		(15)
Income (Loss) From Continuing Operations	(7)		(2)		(25)		(34)
Discontinued operations, net of tax	—		—		31		31
Net Income (Loss)	$	(7)	$	(2)	$	6	$	(3)

42

Regulated Distribution — Second Quarter 2020 Compared with Second Quarter 2019  

Regulated Distribution’s net income decreased $7 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to the absence of the DMR revenues, higher uncollectible and other COVID-19 related costs, net of amounts deferred for future recovery, and higher employee benefit costs, partially offset by lower pension and OPEB non-service expenses, and higher revenues from incremental riders in Ohio and Pennsylvania, higher weather-related customer usage and increased residential sales due to the COVID-19 stay-at-home orders mandated by governmental authorities in our service territories.

Revenues —

The $4 million decrease in total revenues resulted from the following sources:

	For the Three Months Ended June 30,						Increase
Revenues by Type of Service	2020		2019		(Decrease)
	(In millions)
Distribution(1)	$	1,256	$	1,215	$	41
Generation sales:
Retail	826		806		20
Wholesale	50		110		(60)
Total generation sales	876		916		(40)
Other	56		61		(5)
Total Revenues	$	2,188	$	2,192	$	(4)

⁽¹⁾ Includes $15 million and $55 million of ARP revenues for the three months ended June 30, 2020 and 2019, respectively.

Distribution revenues increased $41 million in the second quarter of 2020, as compared to the same period of 2019, primarily resulting from increased residential sales due to the COVID-19 stay-at-home orders mandated by governmental authorities in our service territories, higher rates associated with incremental riders in Ohio and Pennsylvania, including the recovery of distribution capital investment programs and transmission expenses, and higher weather-related customer usage, partially offset by lower commercial and industrial sales resulting from the pandemic and the absence of the DMR revenues that ended in 2019. Distribution services by customer class are summarized in the following table:

	For the Three Months Ended June 30,
(In thousands)	Including Ohio Decoupled MWH						Excluding Ohio Decoupled MWH
Electric Distribution MWH	2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Residential	12,764	10,900	17.1	%	8,633	7,413	16.5	%
Commercial	7,687	9,004	(14.6)	%	4,607	5,583	(17.5)	%
Industrial	12,009	13,594	(11.7)	%	12,009	13,594	(11.7)	%
Other	138	138	—	%	138	138	—	%
Total Electric Distribution MWH	32,598	33,636	(3.1)	%	25,387	26,728	(5.0)	%

Distribution services to residential customers primarily reflects an increase in customer load due to the COVID-19 stay-at-home orders mandated by governmental authorities in our service territories and higher weather-related usage. Deliveries to commercial customers were lower due to the impact of the COVID-19 pandemic, partially offset by higher weather-related usage. Cooling degree days were 6% above 2019, and 2% above normal, and heating degree days were 58% above 2019, and 27% above normal. Deliveries to industrial customers were also negatively impacted by the COVID-19 pandemic contributing to lower steel, mining, educational services, and automotive customer usage, partially offset by higher shale customer usage.

43

The following table summarizes the price and volume factors contributing to the $40 million decrease in generation revenues for the second quarter of 2020, as compared to the same period of 2019:

Source of Change in Generation Revenues	Increase (Decrease)
	(In millions)
Retail:
Change in sales volumes	$	50
Change in prices	(30)
	20
Wholesale:
Change in sales volumes	(39)
Change in prices	1
Capacity revenue	(22)
	(60)
Decrease in Generation Revenues	$	(40)

The increase in retail generation sales volumes was primarily due to decreased customer shopping in New Jersey and Pennsylvania, an increase in residential load due to the COVID-19 stay-at-home orders mandated by governmental authorities in our service territories, and higher weather-related usage. Total generation provided by alternative suppliers as a percentage of total MWH deliveries decreased to 48% from 51% in New Jersey and to 64% from 69% in Pennsylvania. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in New Jersey and Pennsylvania.

Wholesale generation revenues decreased $60 million in the second quarter of 2020, as compared to the same period in 2019, primarily due to lower wholesale sales volumes and capacity revenues. 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 $49 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to the following:

•Fuel expense decreased $52 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to lower unit costs and lower fuel consumption as a result of economic dispatch.

•Purchased power costs were $4 million higher in the second quarter of 2020, as compared to the same period in 2019, primarily due to increased volumes as described above, partially offset by lower prices and capacity expense.

Source of Change in Purchased Power	Increase (Decrease)
	(In millions)
Purchases
Change due to unit costs	$	(11)
Change due to volumes	41
	30
Capacity expense	(26)
Increase in Purchased Power Costs	$	4

44

•Other operating expenses increased $103 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to the following:

•Higher incremental uncollectible and other COVID-19 related expenses of $61 million, of which $31 million was deferred for future recovery.

•Higher employee benefit costs of approximately $26 million.

•Increased storm restoration costs of $22 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.

•Higher network transmission expenses of $11 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.

•Higher pension and OPEB service costs of $9 million.

•Other operating and maintenance expenses associated with increased labor, materials and contractor spend were offset by lower corporate support costs.

•Lower vegetation management spend and energy efficiency program costs of $26 million. These costs are deferred for future recovery, resulting in no material impact on earnings.

•Depreciation expense increased $6 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to a higher asset base.

•Amortization expense decreased $24 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to lower energy efficiency, generation and transmission deferrals, partially offset by higher storm restoration, uncollectible and other COVID-19 related cost deferrals.

•General Taxes increased $12 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to higher payroll taxes associated with employee benefits and higher Pennsylvania gross receipts tax associated with increased sales volumes.

Other Expenses —

Other Expense decreased $46 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to higher net miscellaneous income resulting from lower pension non-service costs.

Income Taxes —

Regulated Distribution’s effective tax rate was 21.1% and 20.6% for the three months ended June 30, 2020 and 2019, respectively.

Regulated Transmission — Second Quarter 2020 Compared with Second Quarter 2019

Regulated Transmission’s net income decreased $2 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to higher interest expense and a true-up of the forward-looking formula rate at ATSI and MAIT, partially offset by higher rate base at ATSI and MAIT.

Revenues —

Total revenues increased $12 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by the impact of a true-up of the forward-looking rate.

The following table shows revenues by transmission asset owner:

	For the Three Months Ended June 30,						Increase
Revenues by Transmission Asset Owner	2020		2019		(Decrease)
	(In millions)
ATSI	$	193	$	185	$	8
TrAIL	60		61		(1)
MAIT	59		51		8
Other	72		75		(3)
Total Revenues	$	384	$	372	$	12

45

Operating Expenses —

Total operating expenses increased $9 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to higher property taxes and depreciation due to a higher asset base, partially offset by lower operating and maintenance expenses. The majority of operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.

Other Expense —

Higher net miscellaneous income, due to lower pension and OPEB non-service costs, was offset by the impact of higher net financing costs from money pool borrowing and lending activity and debt issuances at MAIT.

Income Taxes —

Regulated Transmission’s effective tax rate was 23.0% and 20.5% for the three months ended June 30, 2020 and 2019, respectively.

Corporate / Other — Second Quarter 2020 Compared with Second Quarter 2019

Financial results at Corporate/Other resulted in a $25 million increase in loss from continuing operations in the second quarter of 2020, as compared to the same period of 2019, primarily due to lower returns on certain equity method investments and decreased Pension and OPEB non-service costs, partially offset by $10 million in tax benefits from accelerated amortization of certain investment tax credits and lower net benefit expenses.

For the three months ended June 30, 2020, FirstEnergy recorded income from discontinued operations, net of tax, of $2 million compared to a loss, net of tax, of $29 million for the three months ended June 30, 2019. The change in discontinued operations, net of tax, was primarily due to the emergence of the FES Debtors from bankruptcy on February 27, 2020.

46

Summary of Results of Operations — First Six Months of 2020 Compared with First Six Months of 2019

Financial results for FirstEnergy’s business segments in the first six months of 2020 and 2019 were as follows:

First Six Months 2020 Financial Results	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	4,431	$	777	$	(70)	$	5,138
Other	115		8		(30)		93
Total Revenues	4,546		785		(100)		5,231
Operating Expenses:
Fuel	175		—		—		175
Purchased power	1,300		—		7		1,307
Other operating expenses	1,432		115		(68)		1,479
Provision for depreciation	449		154		35		638
Amortization of regulatory assets, net	59		6		—		65
General taxes	384		118		18		520
Total Operating Expenses	3,799		393		(8)		4,184
Operating Income (Loss)	747		392		(92)		1,047
Other Income (Expense):
Miscellaneous income, net	165		14		24		203
Pension and OPEB mark-to-market adjustment	(257)		(19)		(147)		(423)
Interest expense	(250)		(107)		(169)		(526)
Capitalized financing costs	17		19		—		36
Total Other Expense	(325)		(93)		(292)		(710)
Income (Loss) Before Income Taxes (Benefits)	422		299		(384)		337
Income taxes (benefits)	35		68		(97)		6
Income (Loss) From Continuing Operations	387		231		(287)		331
Discontinued operations, net of tax	—		—		52		52
Net Income (Loss)	$	387	$	231	$	(235)	$	383

47

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
Pension and OPEB mark-to-market adjustment	—		—		—		—
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

48

Changes Between First Six Months 2020 and First Six Months 2019 Financial Results	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments		FirstEnergy Consolidated
	(In millions)
Revenues:
Electric	$	(212)	$	58	$	(7)	$	(161)
Other	(7)		(1)		1		(7)
Total Revenues	(219)		57		(6)		(168)
Operating Expenses:
Fuel	(85)		—		—		(85)
Purchased power	(83)		—		(2)		(85)
Other operating expenses	31		(15)		78		94
Provision for depreciation	20		14		(2)		32
Amortization (deferral) of regulatory assets, net	22		1		—		23
General taxes	9		15		(4)		20
Total Operating Expenses	(86)		15		70		(1)
Operating Income (Loss)	(133)		42		(76)		(167)
Other Income (Expense):
Miscellaneous income (expense), net	73		6		(10)		69
Pension and OPEB mark-to-market adjustment	(257)		(19)		(147)		(423)
Interest expense	(4)		(14)		4		(14)
Capitalized financing costs	—		3		(1)		2
Total Other Expense	(188)		(24)		(154)		(366)
Income (Loss) Before Income Taxes (Benefits)	(321)		18		(230)		(533)
Income taxes (benefits)	(121)		7		(54)		(168)
Income (Loss) From Continuing Operations	(200)		11		(176)		(365)
Discontinued operations, net of tax	—		—		116		116
Net Income (Loss)	$	(200)	$	11	$	(60)	$	(249)

49

Regulated Distribution — First Six Months of 2020 Compared with First Six Months of 2019

Regulated Distribution’s net income decreased $200 million in the first six months of 2020, as compared to the same period of 2019, primarily resulting from the pension and OPEB mark-to-market adjustment in 2020, lower weather-related customer usage, the absence of the DMR revenues that ended in July 2019 and higher depreciation and other operating expenses, partially offset by higher revenues from incremental riders in Ohio and Pennsylvania and increased residential sales due to the COVID-19 stay-at-home orders mandated by governmental authorities in our service territories.

Revenues —

The $219 million decrease in total revenues resulted from the following sources:

	For the Six Months Ended June 30,						Increase
Revenues by Type of Service	2020		2019		(Decrease)
	(In millions)
Distribution services(1)	$	2,580	$	2,563	$	17
Generation sales:
Retail	1,730		1,864		(134)
Wholesale	121		216		(95)
Total generation sales	1,851		2,080		(229)
Other	115		122		(7)
Total Revenues	$	4,546	$	4,765	$	(219)

⁽¹⁾ Includes $83 million and $117 million of ARP revenues for the six months ended June 30, 2020 and 2019, respectively.

Distribution services revenues increased $17 million in the first six months of 2020, as compared to the same period of 2019, primarily resulting from the implementation of Ohio decoupling rates in 2020, higher rates associated with incremental riders in Ohio and Pennsylvania, including the recovery of distribution capital investment programs and transmission expenses, increased residential sales due to the COVID-19 stay-at-home orders mandated by governmental authorities in our service territories, and the implementation of the New Jersey Zero Emission Program in June 2019, partially offset by the absence of the DMR revenues that ended in 2019, and lower weather-related customer usage. Distribution services by customer class are summarized in the following table:

	For the Six Months Ended June 30,
(in thousands)	Including Ohio Decoupled MWH						Excluding Ohio Decoupled MWH
Electric Distribution MWH	2020	2019	(Decrease)		2020	2019	(Decrease)
Residential	25,968	26,003	(0.1)	%	17,630	17,817	(1.0)	%
Commercial	16,454	18,481	(11.0)	%	10,003	11,468	(12.8)	%
Industrial	25,558	27,553	(7.2)	%	25,558	27,553	(7.2)	%
Other	273	279	(2.2)	%	273	279	(2.2)	%
Total Electric Distribution MWH	68,253	72,316	(5.6)	%	53,464	57,117	(6.4)	%

Lower distribution services to residential and commercial customers reflect lower weather-related usage and the impact of COVID-19. Heating degree days were 7% below 2019, and 11% below normal. Deliveries to industrial customers were also negatively impacted by the COVID-19 pandemic contributing to lower steel, mining, educational services, and automotive customer usage, partially offset by higher shale customer usage.

50

The following table summarizes the price and volume factors contributing to the $229 million decrease in generation revenues for the first six months of 2020, as compared to the same period of 2019:

Source of Change in Generation Revenues	(Decrease)
	(In millions)
Retail:
Change in sales volumes	$	(80)
Change in prices	(54)
	(134)
Wholesale:
Change in sales volumes	(48)
Change in prices	(4)
Capacity revenue	(43)
	(95)
Decrease in Generation Revenues	$	(229)

The decrease in retail generation sales volumes was primarily due to lower weather-related usage. The decrease in retail generation prices primarily resulted from lower non-shopping generation auction rates in New Jersey and Pennsylvania.

Wholesale generation revenues decreased $95 million in the first six months of 2020, as compared to the same period in 2019, primarily due to lower wholesale sales volumes and capacity revenues. 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 decreased $86 million, primarily due to the following:

•Fuel costs were $85 million lower during the first six months of 2020, as compared to the same period of 2019, primarily due to lower unit costs and lower fuel consumption as a result of economic dispatch.

•Purchased power costs decreased $83 million during the first six months of 2020, as compared to the same period of 2019, primarily due to decreased volumes as described above and lower capacity expense, partially offset by the implementation of the NJ Zero Emission Program in June 2019.

Source of Change in Purchased Power	(Decrease)
	(In millions)
Purchases:
Change due to unit costs	$	—
Change due to volumes	(31)
	(31)
Capacity	(52)
Decrease in Purchased Power Costs	$	(83)

51

•Other operating expenses increased $31 million in the first six months of 2020, as compared to the same period of 2019, primarily due to:

•Higher incremental uncollectible and other COVID-19 related expenses of $65 million, of which $33 million was deferred for future recovery.

•Higher employee benefit costs of approximately $30 million.

•Higher other operating and maintenance expense of $8 million, primarily associated with higher labor, materials and contractor spend, partially offset by lower corporate support costs.

•Higher network transmission expenses of $21 million. These costs are deferred for future recovery, resulting in no material impact on current period earnings.

•Higher pension and OPEB service costs of $14 million.

•Decreased storm restoration costs of $78 million, which were mostly deferred for future recovery, resulting in no material impact on current period earnings.

•Lower vegetation management spend and energy efficiency program costs of $29 million. These costs are deferred for future recovery, resulting in no material impact on earnings.

•Depreciation expense increased $20 million in the first six months of 2020, as compared to the same period of 2019, primarily due to a higher asset base.

•Amortization expense increased $22 million in the first six months of 2020, as compared to the same period of 2019, primarily due to lower storm restoration, energy efficiency, and generation and transmission deferrals, partially offset by higher uncollectible and other COVID-19 cost deferrals.

•General Taxes increased $9 million in the second quarter of 2020, as compared to the same period of 2019, primarily due to higher payroll taxes associated with employee benefits.

Other Expense —

Total other expense increased $188 million in the first six months of 2020, as compared to the same period of 2019, primarily due to a $257 million pension and OPEB mark-to-market adjustment in the first quarter of 2020, higher interest expense from debt issuances primarily at WP and MP, partially offset by higher net miscellaneous income primarily resulting from lower pension and OPEB non-service costs.

Income Taxes —

Regulated Distribution’s effective tax rate was 8.3% and 21.0% for the six months ended June 30, 2020 and 2019, respectively. The change in the effective tax rate was primarily due to the recognition of $52 million in deferred gains relating to prior intercompany transfers of generation assets that were triggered by the deconsolidation of the FES Debtors from FirstEnergy’s consolidated federal income tax group as a result of their emergence from bankruptcy in the first quarter of 2020.

Regulated Transmission — First Six Months of 2020 Compared with First Six Months of 2019

Regulated Transmission’s net income increased $11 million in the first six months of 2020, as compared to the same period of 2019, primarily resulting from the impact of a higher rate base at ATSI and MAIT, partially offset by higher interest expense and a true-up of the forward-looking formula rate at ATSI and MAIT.

Revenues —

Total revenues increased $57 million, primarily due to the recovery of incremental operating expenses and a higher rate base at ATSI and MAIT, partially offset by the impact of a true-up of the forward-looking rate.

52

The following table shows revenues by transmission asset owner:

	For the Six Months Ended June 30,
Revenues by Transmission Asset Owner	2020		2019		Increase (Decrease)
	(In millions)
ATSI	$	398	$	360	$	38
TrAIL	125		121		4
MAIT	117		101		16
Other	145		146		(1)
Total Revenues	$	785	$	728	$	57

Operating Expenses —

Total operating expenses increased $15 million in the first six months of 2020, as compared to the same period of 2019, primarily due to higher property taxes and depreciation due to a higher asset base, partially offset by lower operating and maintenance expenses. The majority of operating expenses are recovered through formula rates, resulting in no material impact on current period earnings.

Other Expense —

Total other expense increased $24 million in the first six months of 2020, as compared to the same period of 2019, primarily due to a $19 million pension and OPEB mark-to-market adjustment in the first quarter of 2020 and higher interest expense associated with new debt issuances at ATSI, MAIT and FET.

Income Taxes —

Regulated Transmission’s effective tax rate was 22.7% and 21.7% for the six months ended June 30, 2020 and 2019, respectively.

Corporate / Other — First Six Months of 2020 Compared with First Six Months of 2019

Financial results at Corporate/Other resulted in a $176 million increased loss from continuing operations in the first six months of 2020, as compared to the same period of 2019, primarily due to the $147 million pension and OPEB mark-to-market adjustment in the first quarter of 2020, higher other operating expenses and lower returns on certain equity method investments, partially offset by $10 million in tax benefits from accelerated amortization of certain investment tax credits and decreased other Pension and OPEB non-service costs.

For the six months ended June 30, 2020, FirstEnergy recorded income from discontinued operations, net of tax, of $52 million compared to a loss, net of tax, of $64 million for the six months ended June 30, 2019. The change in discontinued operations, net of tax, was primarily due to lower settlement-related expenses, including adjustments to the estimated worthless stock deduction and Intercompany Tax Allocation Agreement with the FES Debtors, as well as the acceleration of net pension and OPEB service credits in 2020 and the absence of tax expense in 2019 associated with non-deductible interest.

53

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.

Management assesses the probability of recovery of regulatory assets at each balance sheet date and whenever new events occur. Factors that may affect probability include changes in the regulatory environment, issuance of a regulatory commission order or passage of new legislation. Management applies judgment in evaluating the evidence available to assess the probability of recovery of regulatory assets from customers, including, but not limited to evaluating evidence related to precedent for similar items at the Company and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between the Company and regulators. Certain of these regulatory assets, totaling approximately $114 million and $111 million as of June 30, 2020 and December 31, 2019, respectively, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order, of which, $76 million and $73 million as of June 30, 2020 and December 31, 2019, respectively, are being sought for recovery in a formula rate amendment filing at ATSI that is pending before FERC. See Note 9, "Regulatory Matters" for additional information.

The following table provides information about the composition of net regulatory assets and liabilities as of June 30, 2020, and December 31, 2019, and the changes during the six months ended June 30, 2020:

Net Regulatory Assets (Liabilities) by Source	June 30, 2020		December 31, 2019		Change
	(In millions)
Customer payables for future income taxes	$	(2,507)	$	(2,605)	$	98
Nuclear decommissioning and spent fuel disposal costs	(190)		(197)		7
Asset removal costs	(732)		(756)		24
Deferred transmission costs	285		298		(13)
Deferred generation costs	150		214		(64)
Deferred distribution costs	215		155		60
Contract valuations	42		51		(9)
Storm-related costs	555		551		4
Uncollectible and COVID-19 related costs	40		3		37
Other	(8)		25		(33)
Net Regulatory Liabilities included on the Consolidated Balance Sheets	$	(2,150)	$	(2,261)	$	111

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

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 - Primarily 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.

54

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 (amortized through 2036), as well as the Ohio Companies’ deferrals related to the decoupling mechanism which are recorded as a regulatory asset or liability and recovered or refunded, respectively, in subsequent periods.

Contract valuations - Includes the changes in fair value of PN above-market NUG costs and the amortization of purchase accounting adjustments at PE which were 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 $158 million and $193 million are currently being recovered through rates as of June 30, 2020 and December 31, 2019, respectively.

Uncollectible and COVID-19 related costs - Includes the deferral of prudently-incurred incremental costs and certain waived late payment charges arising from COVID-19, including uncollectible expenses under new and existing riders prior to the pandemic.

The following table provides information about the composition of net regulatory assets that do not earn a current return as of June 30, 2020 and December 31, 2019, of which approximately $193 million and $228 million, respectively, are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction.

Regulatory Assets by Source Not Earning a Current Return	June 30, 2020		December 31, 2019		Change
	(In millions)
Deferred transmission costs	$	31	$	27	$	4
Deferred generation costs	9		15		(6)
Storm-related costs	477		471		6
COVID-19 related costs	16		—		16
Other	32		32		—
Regulatory Assets Not Earning a Current Return	$	565	$	545	$	20

55

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.

The $2.5 billion equity issuance in 2018 strengthened FirstEnergy’s balance sheet, supported the company’s transition to a fully regulated utility company and positions FirstEnergy for sustained investment-grade credit metrics. The shares of preferred stock participated in the dividend paid on common stock on an as-converted basis and were non-voting except in certain limited circumstances. Because of this investment, FirstEnergy does not currently anticipate the need to issue additional equity through 2021 and expects to issue, subject to, among other things, market conditions, pricing terms and business operations, up to $600 million of equity annually in 2022 and 2023, including approximately $100 million in equity for 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 2020 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 FE and certain of its 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. FirstEnergy expects no required contributions through 2021.

With an operating territory of 65,000 square miles, 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 over $10 billion in forecasted capital investments from 2018 through 2023, Regulated Distribution’s rate base compounded annual growth rate is expected to be approximately 4% from 2018 through 2023. 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.

FirstEnergy believes there are incremental investment opportunities for its existing transmission infrastructure of over $20 billion beyond those identified through 2023, 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 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 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. In September 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement 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 resolved certain claims by FirstEnergy against the FES Debtors, all claims by the FES Debtors and the FES Key Creditor Groups against FirstEnergy, as well as releases from third parties who voted in favor the FES Debtors' plan of reorganization, in return for among other things, a cash payment of $853 million upon emergence. The FES Bankruptcy settlement was conditioned on the FES Debtors confirming and effectuating a plan of reorganization acceptable to FirstEnergy.

On February 18, 2020, the FES Debtors and FirstEnergy entered into an IT Access Agreement that provided IT support to enable the Debtors to emerge from bankruptcy prior to full IT separation by the FES Debtors. As part of the IT Access Agreement, the FES Debtors and FirstEnergy resolved, among other things, the on-going reconciliation of outstanding tax sharing payments for tax years 2018, 2019 and 2020 for a total of $125 million. On February 25, 2020, the Bankruptcy Court approved the IT Access Agreement. On February 27, 2020, the FES Debtors effectuated their plan, emerged from bankruptcy and FirstEnergy tendered

56

the settlement payments totaling $853 million and the $125 million tax sharing payment to the FES Debtors, with no material impact to net income in 2020.

The outbreak of COVID-19 is a global pandemic. FirstEnergy is continuously evaluating the global pandemic and taking steps to mitigate known risks. FirstEnergy has incurred, and it is expected to incur for the foreseeable future, incremental uncollectible and other COVID-19 pandemic related expenses. COVID-19 related expenses consist of additional costs that FirstEnergy is incurring to protect its employees, contractors and customers, and to support social distancing requirements resulting from the COVID-19 pandemic. These costs include, but are not limited to, new or added benefits provided to employees, the purchase of additional personal protection equipment and disinfecting supplies, additional facility cleaning services, initiated programs and communications to customers on utility response, and increased technology expenses to support remote working, where possible. The full impact on FirstEnergy’s business from the COVID-19 pandemic, including the governmental and regulatory responses, is unknown at this time and difficult to predict. FirstEnergy provides a critical and essential service to its customers and the health and safety of its employees, contractors and customers is its first priority. FirstEnergy is continuously monitoring its supply chain and is working closely with essential vendors to understand the impact of COVID-19 to its business and does not currently expect service disruptions or any material impact on its capital spending plan.

Currently, FirstEnergy is effectively managing operations during the pandemic in order to continue to provide critical and essential service to customers and believes it is well positioned to manage through the economic slowdown. FirstEnergy Distribution and Transmission revenues benefit from geographic and economic diversity across a five-state service territory, which also allows for flexibility with capital investments and measures to maintain sufficient liquidity over the next twelve months. As of August 10, 2020, the Company had $3.6 billion of available liquidity, and projects to remain at this level for the next twelve months. However, the situation remains fluid and future impacts to FirstEnergy, that are presently unknown or unanticipated, may occur. Furthermore, the likelihood of an impact to FirstEnergy, and the severity of any impact that does occur, could increase the longer the global pandemic persists. The extent to which COVID-19 may materially impact results, if at all, is highly uncertain and will depend on future developments.

As of June 30, 2020, FirstEnergy’s net deficit in working capital (current assets less current liabilities) was due in large part to accounts payable of $882 million, accrued taxes of $563 million, currently payable long-term debt of $81 million, and other current liabilities of $367 million, primarily attributable to customer deposits. Currently payable long-term debt as of June 30, 2020, consisted of the following:

Currently Payable Long-Term Debt	(In millions)
Sinking fund requirements	$	66
Other notes	15
	$	81

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, which are available until December 6, 2022. Under the FE credit 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 credit 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 the credit 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 credit 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 credit facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the credit facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter.

FirstEnergy’s revolving credit facilities bear interest at fluctuating interest rates, primarily based on LIBOR. LIBOR tends to fluctuate based on general interest rates, rates set by the U.S. Federal Reserve and other central banks, the supply of and demand for credit in the London interbank market and general economic conditions. FirstEnergy has not hedged its interest rate exposure with respect to its floating rate debt. Accordingly, FirstEnergy’s interest expense for any particular period will fluctuate based on LIBOR and other variable interest rates. On July 27, 2017, the Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021. It is unclear whether new methods of calculating LIBOR will be established such that it continues to exist after 2021. The U.S. Federal Reserve, in conjunction with the Alternative Reference Rates Committee, is considering replacing U.S. dollar LIBOR with a newly created index, calculated based on repurchase agreements backed by treasury securities. It is not possible to predict the effect of these changes, other reforms or the establishment of alternative reference rates in the United Kingdom, the United States or elsewhere. To the extent these interest rates increase, interest expense will increase. If sources of capital for FirstEnergy are

57

reduced, capital costs could increase materially. Restricted access to capital markets and/or increased borrowing costs could have an adverse effect on our results of operations, cash flows, financial condition and liquidity.

FirstEnergy had $115 million and $1,000 million of short-term borrowings as June 30, 2020 and December 31, 2019, respectively. FirstEnergy’s available liquidity from external sources as of August 10, 2020, was as follows:

Borrower(s)	Type	Maturity	Commitment		Available Liquidity
			(In millions)
FirstEnergy(1)	Revolving	December 2022	$	2,500	$	2,496
FET(2)	Revolving	December 2022	1,000		1,000
		Subtotal	$	3,500	$	3,496
	Cash and cash equivalents				—		141
		Total	$	3,500	$	3,637

⁽¹⁾FE and the Utilities. Available liquidity includes impact of $4 million of LOCs issued under various terms.

⁽²⁾Includes FET and the Transmission Companies.

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, 2020:

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, 2020, 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.

58

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 2020 was 1.14% per annum for the regulated companies’ money pool and 1.38% 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 August 14, 2020:

Corporate Credit Rating

Senior Secured

Senior Unsecured

Outlook/Watch (1)

Issuer

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

S&P

Moody’s

Fitch

FE

BBB

Baa3

BBB

—

—

—

BBB-

Baa3

BBB

CW-N

N

N

AGC

BBB-

Baa2

BBB

—

—

—

—

—

—

CW-N

S

S

ATSI

BBB

A3

BBB+

—

—

—

BBB

A3

A-

CW-N

S

N

CEI

BBB

Baa2

BBB+

A-

A3

A

BBB

Baa2

A-

CW-N

S

N

FET

BBB

Baa2

BBB

—

—

—

BBB-

Baa2

BBB

CW-N

S

N

JCP&L

BBB

A3

BBB+

—

—

—

BBB

A3

A-

CW-N

S

N

ME

BBB

A3

BBB+

—

—

—

BBB

A3

A-

CW-N

S

N

MAIT

BBB

A3

BBB+

—

—

—

BBB

A3

A-

CW-N

S

N

MP

BBB

Baa2

BBB

A-

A3

A-

BBB

Baa2

—

CW-N

S

S

OE

BBB

A3

BBB+

A-

A1

A

BBB

A3

A-

CW-N

S

N

PN

BBB

Baa1

BBB+

—

—

—

BBB

Baa1

A-

CW-N

S

N

Penn

BBB

A3

BBB+

—

A1

A

—

—

—

CW-N

S

N

PE

BBB

Baa2

BBB

—

—

A-

—

—

—

CW-N

S

S

TE

BBB

Baa1

BBB+

A-

A2

A

—

—

—

CW-N

S

N

TrAIL

BBB

A3

BBB+

—

—

—

BBB

A3

A-

CW-N

S

N

WP

BBB

A3

BBB+

—

—

A

—

—

—

CW-N

S

N

⁽¹⁾ S = Stable, P = Positive, N = Negative, CW-N = CreditWatch Negative

On May 27, 2020, Moody’s upgraded the issuer and senior unsecured ratings of JCP&L to A3 from Baa1 and the rating outlook was changed to stable.

On July 23, 2020, S&P placed the ratings of FE and its subsidiaries on CreditWatch with negative implications.

On July 24, 2020, Moody’s revised FE’s ratings outlook to negative from stable. FE’s Baa3 corporate credit rating and Baa3 senior unsecured rating were affirmed.

On July 28, 2020, Fitch revised FE and its subsidiaries, with the exception of MP, AGC and PE, ratings outlook to negative from stable. The outlook of MP, AGC and PE is stable. Fitch also affirmed FE and its subsidiary ratings.

On August 14, 2020, Moody’s affirmed OE’s A3 senior unsecured and issuer ratings and Penn’s A3 issuer rating. The outlooks were changed to stable from positive.

Debt capacity is subject to the consolidated debt-to-total-capitalization limits in the credit facilities previously discussed. As of June 30, 2020, FE and its subsidiaries could issue additional debt of approximately $6.9 billion, or incur a $3.7 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, 2020, FirstEnergy had $116 million of cash and cash equivalents and approximately $49 million of restricted cash compared to $627 million of cash and cash equivalents and approximately $52 million of restricted cash as of December 31, 2019, on the Consolidated Balance Sheets.

59

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.

FirstEnergy’s Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. For the six months ended June 30, 2020 and 2019, cash flows from operating activities includes income (loss) from discontinued operations of $52 million and $(64) million, respectively.

In the first six months of 2020, cash provided from operating activities was $150 million compared to $625 million in the same period of 2019. The decrease in cash provided for operating activities is primarily due to the $978 million cash settlement and tax sharing payments made to the FES Debtors upon their emergence in February 2020, partially offset by the absence of a $500 million cash contribution to the qualified pension plan in February 2019.

Cash Flows From Financing Activities

In the first six months of 2020, cash provided from financing activities was $742 million compared to $756 million in the same period of 2019. The following table summarizes new debt financing, redemptions, repayments, short-term borrowings and dividends:

	For the Six Months Ended June 30,
Securities Issued or Redeemed / Repaid	2020		2019
	(In millions)
New Issues
Unsecured notes	$	3,000	$	1,850
FMBs	175		100
	$	3,175	$	1,950
Redemptions / Repayments
Term loan	$	(750)	$	—
Unsecured notes	(250)		(725)
FMBs	(50)		—
Senior secured notes	(32)		(32)
	$	(1,082)	$	(757)
Short-term borrowings, net	$	(885)	$	—
Preferred stock dividend payments	$	—	$	(6)
Common stock dividend payments	$	(422)	$	(403)

On February 20, 2020, FE issued $1.75 billion in senior unsecured notes in three separate series: (i) $300 million aggregate principal amount of 2.050% Notes, Series A, due 2025, (ii) $600 million aggregate principal amount of 2.650% Notes, Series B, due 2030 and (iii) $850 million aggregate principal amount of 3.400% Notes, Series C, due 2050. Proceeds from the issuance of the notes, together with cash on hand, were used: (i) to repay the entire $750 million two-year term loan due September 2021, (ii) to make the $853 million in bankruptcy settlement payments and $125 million tax sharing agreement payment with the FES Debtors as discussed above, (iii) to repay $250 million of the $1 billion outstanding 364-day term loan due September 2020, and (iv) for working capital needs and general corporate purposes.

On March 31, 2020, MAIT issued $125 million of 3.60% senior unsecured notes due 2032 and $125 million of 3.70% senior notes due 2035. Proceeds from the issuance of the senior notes were used: (i) to refinance existing debt, (ii) for capital expenditures, and (iii) for general corporate purposes.

On April 20, 2020, PN issued $125 million of 3.61% senior notes due 2032 and $125 million of 3.71% senior notes due 2035. Proceeds of the issuance of the senior notes were used: (i) to refinance indebtedness, including short-term borrowings incurred under the FirstEnergy regulated money pool to repay a portion of the $250 million aggregate principle amount of PN’s 5.20% Senior Notes due April 1, 2020, (ii) to fund capital expenditures, (iii) to fund general corporate purposes, or (iv) for any combination of the above.

60

On June 8, 2020, FE issued $750 million in senior unsecured notes in two separate series: (i) $300 million aggregate principal amounts of 1.600% Notes, Series A, due 2026 and (ii) $450 million aggregate principal amount of 2.250% Notes, Series B, due 2030. Proceeds from the issuance of the notes were used to repay all amounts outstanding under the 364-day term loan due September 2020.

On June 29, 2020, PE issued $75 million of 2.67% FMBs due 2032 and $100 million of 3.43% FMBs due 2051. Proceeds of the issuance of the FMBs were used to repay short-term borrowings under the FirstEnergy regulated money pool, to fund capital expenditures, and for general corporate purposes.

On July 20, 2020, CEI issued $150 million of 2.77% senior unsecured notes due 2034 and $100 million of 3.23% senior unsecured notes due 2040. Proceeds from the issuance of the senior notes were used to refinance existing short-term borrowings, to fund capital expenditures, for general corporate purposes, or any combination of the above.

Cash Flows From Investing Activities

Cash used for investing activities in the first six months of 2020 principally represented cash used for property additions. The following table summarizes investing activities for the first six months of 2020 and 2019:

	For the Six Months Ended June 30,						Increase
Cash Used for Investing Activities	2020		2019		(Decrease)
	(In millions)
Property Additions:
Regulated Distribution	$	724	$	672	$	52
Regulated Transmission	539		531		8
Corporate / Other	29		25		4
Investments	14		20		(6)
Asset removal costs	102		103		(1)
Other	(2)		(15)		13
	$	1,406	$	1,336	$	70

Cash used for investing activities for the first six months of 2020 increased $70 million, compared to the same period of 2019, primarily due to higher property additions. The increase in property additions was due to an increase of $52 million at Regulated Distribution for investments to improve and modernize the electric system.

61

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, 2020, was approximately $1.7 billion, as summarized below:

Guarantees and Other Assurances	Maximum Exposure
	(In millions)
FE’s Guarantees on Behalf of its Consolidated Subsidiaries
AE Supply asset sales(1)	$	570
Deferred compensation arrangements	474
Fuel related contracts and other	5
	1,049
FE’s Guarantees on Other Assurances
Global holding facility	114
Deferred compensation arrangements	148
Surety Bonds	339
LOCs and other	16
	617
Total Guarantees and Other Assurances	$	1,666

⁽¹⁾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 addition, as a condition to closing AE Supply’s transfer of Pleasants Power Station and as contemplated under the FES Bankruptcy settlement agreement, FE has provided two guarantees totaling $15 million for certain retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility.

Collateral and Contingent-Related Features

In the normal course of business, FE and its subsidiaries may enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain 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 rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

Certain agreements entered into by FE and its subsidiaries have margining provisions that require posting of collateral. As of June 30, 2020, $1 million of collateral has been posted by FE or its subsidiaries.

These credit-risk-related contingent features stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of June 30, 2020:

Potential Collateral Obligations		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
Upon further downgrade		$	47	$	—	$	47
Surety Bonds (collateralized amount)(1)		66		257		323
Total Exposure from Contractual Obligations		$	113	$	257	$	370

⁽¹⁾Surety Bonds are not tied to a credit rating. Surety Bonds’ impact assumes maximum contractual obligations (typical obligations require 30 days to cure).

Other Commitments and Contingencies

FE is a guarantor under a $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding’s outstanding principal balance is $114 million as of June 30, 2020. 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.

62

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 and Risk Policy Committees are 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, 2020, FirstEnergy has a net liability of $5 million in non-hedge derivative contracts that are related to FTRs at certain of the Utilities. FTRs are subject to regulatory accounting and do not impact earnings.

Equity Price Risk

As of June 30, 2020, the FirstEnergy pension plan assets were allocated approximately as follows: 29% in equity securities, 42% in fixed income securities, 9% in absolute return strategies, 9% in real estate, 4% in private equity, 4% in derivatives and 3% in cash and short-term securities. A decline in the value of pension plan assets could result in additional funding requirements. FirstEnergy’s funding policy is based on actuarial computations using the projected unit credit method. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. As a result of this contribution and pension investment performance returns to date, FirstEnergy expects no required contributions through 2021. As of June 30, 2020, FirstEnergy’s OPEB plan assets were allocated approximately 52% in equity securities, 43% in fixed income securities and 5% in cash and short-term securities. See Note 5, “Pension and Other Post-Employment Benefits,” of the Notes to Consolidated Financial Statements for additional details on FirstEnergy’s pension and OPEB plans.

Through June 30, 2020, FirstEnergy’s pension and OPEB plan assets have gained approximately 5.7% and 0.3%, respectively, as compared to an annual expected return on plan assets of 7.5%. On February 27, 2020, FirstEnergy remeasured its plan assets, and from that date through June 30, 2020, FirstEnergy’s pension and OPEB plan assets have gained approximately 2.7% and 2.2%, respectively.

NDT funds have been established to satisfy JCP&L, ME and PN’s nuclear decommissioning obligations associated with TMI-2. As of June 30, 2020, approximately 15% of the funds were invested in fixed income securities and 85% 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 $132 million and $769 million for fixed income securities and short-term investments, respectively, as of June 30, 2020, excluding $19 million of net receivables, payables and accrued income. 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, 2020, 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 and the difference between expected and actual returns on the plans’ assets.

Under the approved bankruptcy settlement agreement discussed above, upon emergence, FES and FENOC employees ceased earning years of service under the FirstEnergy pension and OPEB plans. The emergence on February 27, 2020, triggered a remeasurement of the affected pension and OPEB plans and as a result, FirstEnergy recognized a non-cash, pre-tax pension and OPEB mark-to-market adjustment of approximately $423 million in the first quarter of 2020. The pension and OPEB mark-to-market adjustment primarily reflects a 38 bps decrease in the discount rate used to measure benefit obligations from December 31, 2019, partially offset by a slightly higher than expected return on assets.

At this time, FirstEnergy is unable to determine or project the mark-to-market that may be recorded as of December 31, 2020.

63

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. In addition, in response to the COVID-19 pandemic, FirstEnergy has increased reviews of counterparties, customers and industries that have been negatively impacted, which could affect meeting contractual obligations with FirstEnergy. FirstEnergy 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, it is expected that 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, and surveys to determine negative impacts to essential vendors as a result of the COVID-19 pandemic. 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

CARES ACT

On March 27, 2020, the President signed into law the CARES Act, an economic stimulus package in response to the COVID-19 pandemic. The CARES Act contains several corporate income tax provisions, including making remaining AMT credits immediately refundable; providing a 5-year carryback of NOLs generated in tax years 2018, 2019, and 2020, and removing the 80% taxable income limitation on utilization of those NOLs if carried back to prior tax years or utilized in tax years beginning before 2021; and temporarily liberalizing the interest deductibility rules under Section 163(j) of the Tax Act, by raising the adjusted taxable income limitation from 30% to 50% for tax years 2019 and 2020 and giving taxpayers the election of using 2019 adjusted taxable income for purposes of computing 2020 interest deductibility. FirstEnergy has approximately $18 million of refundable AMT credits that will be fully refundable through the CARES Act, however, does not expect to generate additional income tax refunds from the NOL carryback provision and expects interest to be fully deductible starting in 2020. FirstEnergy does not currently expect the other provisions of the CARES Act to have a material effect on current income tax expense or the realizability of deferred income tax assets.

On July 28, 2020, the IRS issued final regulations implementing interest expense deduction limitation rules under section 163(j) of the Internal Revenue Code. The final regulations changed certain rules on the computation of interest expense and limitation amount, as well as rules relevant to status as a regulated utility business and the allocation of consolidated group interest expense between utility and non-utility businesses. FirstEnergy is analyzing the potential impacts of the final regulations, including any impact they have resulting from the CARES Act.

        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 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.

64

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.

Maryland’s Governor issued an order on March 16, 2020, forbidding utilities from terminating residential service or charging late fees for non-payment for the duration of the COVID-19 pandemic. On April 9, 2020, the MDPSC issued an order allowing utilities to track and create a regulatory asset for future recovery of all prudently-incurred incremental costs arising from the COVID-19 pandemic, including incremental uncollectible expenses. On July 8, 2020, the MDPSC issued a notice opening a public conference to collect information from utilities and other stakeholders about the impacts of the COVID-19 pandemic on the utilities and their customers, and indicated that it would hold a hearing to discuss that information in late August 2020.

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. JCP&L is contesting this appeal but is unable to predict the outcome of this matter.

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 May 8, 2019, the NJBPU approved a Stipulation of Settlement submitted by JCP&L, Rate Counsel, NJBPU Staff and New Jersey Large Energy Users Coalition to implement JCP&L’s infrastructure plan, JCP&L Reliability Plus. The plan provides that JCP&L will invest up to approximately $97 million in capital investments beginning on June 1, 2019 through December 31, 2020, to enhance the reliability and resiliency of JCP&L’s distribution system and reduce the frequency and duration of power outages. 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. The NJBPU approved adjusted rates that took effect on March 1, 2020.

On February 18, 2020, JCP&L submitted a filing with the NJBPU requesting a distribution base rate increase of $186.9 million on an annual basis, which represents an overall average increase in JCP&L rates of 7.8%. The filing seeks to recover certain costs associated with providing safe and reliable electric service to JCP&L customers, along with recovery of previously incurred storm costs. JCP&L proposed a rate effective date of March 19, 2020. On March 9, 2020, the Board issued an order suspending JCP&L’s proposed rates for four months. Based on the historical procedures of the NJBPU Board a second suspension order is expected with revised base rates becoming effective in late November 2020. JCP&L filed updates to the requested distribution base rate in both June and July 2020, resulting in JCP&L seeking a total annual distribution base rate increase of approximately

65

$185 million. On August 11, 2020, the administrative law judge issued a prehearing order with a procedural schedule that calls for evidentiary hearings to occur the week of November 16, 2020.

On April 6, 2020, JCP&L signed an asset purchase agreement with Yards Creek Energy, LLC, a subsidiary of LS Power to sell its 50% interest in the Yards Creek pumped-storage hydro generation facility in NJ (210 MWs). Subject to terms and conditions of the agreement, the base purchase price is $155 million. Completion of the transaction is subject to several closing conditions, including approval by the NJBPU and FERC. On July 31, 2020, FERC approved transfer of JCP&L’s interest in the hydroelectric operating license; however, JCP&L’s application for authorization to transfer its ownership interest in the Yards Creek facility remains pending at FERC. There can be no assurance that all regulatory approvals will be obtained and/or all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur in the first half of 2021. Assets held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of property, plant and equipment of $44 million, which is included in the regulated distribution segment. Treatment of the gain is subject to NJBPU approval.

On June 10, 2020, the NJBPU issued an order establishing a framework for the filing of utility-run energy efficiency and peak demand reduction programs in accordance with the New Jersey Clean Energy Act. Under the established framework, JCP&L will recover its program investments over a ten year amortization period and its operations and maintenance expenses on an annual basis, be eligible to receive lost revenues on energy savings that resulted from its programs and be eligible for incentives or subject to penalties based on its annual program performance, beginning in the fifth year of its program offerings. JCP&L’s energy efficiency and peak demand reduction program plan is required to be filed no later than September 25, 2020, and is anticipated to be implemented July 1, 2021.

On July 2, 2020, the NJBPU issued an order allowing New Jersey utilities to track and create a regulatory asset for future recovery of all prudently-incurred incremental costs arising from the COVID-19 pandemic beginning March 9, 2020 through September 30, 2021, or until the Governor issues an order stating that the COVID-19 pandemic is no longer in effect. New Jersey utilities can request recovery of such regulatory asset in a stand-alone COVID-19 regulatory asset filing or future base rate case.

OHIO

The Ohio Companies operate under base distribution rates approved by the PUCO effective in 2009. The Ohio Companies’ residential and commercial base distribution revenues are decoupled, through a mechanism that took effect on February 1, 2020, to the base distribution revenue and lost distribution revenue associated with energy efficiency and peak demand reduction programs recovered as of the twelve-month period ending on December 31, 2018. The Ohio Companies currently operate under ESP IV effective June 1, 2016, and continuing through May 31, 2024, that continues the supply of power to non-shopping customers at a market-based price set through an auction process. ESP IV also continues the DCR rider, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $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. In addition, ESP IV includes: (1) continuation of a base distribution rate freeze through May 31, 2024; (2) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (3) a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; and (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. ESP IV further provided for the Ohio Companies to collect through the DMR $132.5 million annually for three years beginning in 2017, grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. On appeal, the SCOH, on June 19, 2019, reversed the PUCO’s determination that the DMR is lawful, and remanded the matter to the PUCO with instructions to remove the DMR from ESP IV. On August 20, 2019, the SCOH denied the Ohio Companies’ motion for reconsideration. The PUCO entered an Order directing the Ohio Companies to cease further collection through the DMR, credit back to customers a refund of the DMR funds collected since July 2, 2019, and remove the DMR from ESP IV. On July 15, 2019, OCC filed a Notice of Appeal with the SCOH, challenging the PUCO’s exclusion of the DMR revenues 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. The Ohio Companies are contesting this appeal but are unable to predict the outcome of this matter. The SCOH heard the argument on this matter on May 12, 2020.

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 and ending current energy efficiency program mandates on December 31, 2020, provided that statewide energy efficiency mandates are achieved as determined by the PUCO. On February 26, 2020, the PUCO ordered that a wind-down of statutorily required energy efficiency programs shall commence on September 30, 2020, and the programs shall terminate on December 31, 2020, and that the Ohio Companies’ existing portfolio plans are extended through 2020 without changes.

On November 21, 2019, the Ohio Companies applied to the PUCO for approval of a decoupling mechanism, which 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

66

also providing revenue certainty to the Ohio Companies. On January 15, 2020, the PUCO approved the Ohio Companies’ decoupling application, and the decoupling mechanism took effect on February 1, 2020. Ohio Senate Bill 346 and Ohio House Bill 738 were introduced on July 28, 2020 and July 29, 2020, respectively, and each would, among other things, repeal the Ohio legislation that established support for nuclear energy supply in Ohio and a provision that provides for a decoupling mechanism for Ohio electric utilities as well as ending current energy efficiency program mandates.

On July 17, 2019, the PUCO approved, with no material modifications, a settlement agreement that provides for the implementation of the Ohio Companies’ 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 to flow back to customers. The settlement had 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.

In March 2020, the PUCO issued entries directing utilities to review their service disconnection and restoration policies and suspend, for the duration of the COVID-19 pandemic, otherwise applicable requirements that may impose a service continuity hardship or service restoration hardship on customers. The Ohio Companies are utilizing their existing approved cost recovery mechanisms where applicable to address the financial impacts of these directives. On July 31, 2020, the Ohio Companies filed with the PUCO their transition plan and requests for waivers to allow for the safe resumption of normal business operations, including service disconnections for non-payment, on or after September 15, 2020.

On July 29, 2020, the PUCO consolidated the Ohio Companies’ Applications for determination of the existence of significantly excessive earnings, or SEET, under ESP IV for calendar years 2018 and 2019, which had been previously filed on July 15, 2019, and May 15, 2020, respectively, and set a procedural schedule with evidentiary hearings scheduled for October 29, 2020. The calculations included in the Ohio Companies’ SEET filings for calendar years 2018 and 2019 demonstrate that the Ohio Companies did not have significantly excessive earnings, however, FirstEnergy and the Ohio Companies are unable to predict the PUCO’s ultimate determination of the applications. On August 3, 2020, the OCC filed an interlocutory appeal asking the PUCO to stay the SEET proceeding until the SCOH determines whether DMR should be excluded from the SEET, as further discussed above. Further, on July 29, 2020, Ohio House Bill 740 was introduced, which would repeal legislation passed last year that permitted the Ohio Companies to file their SEET results on a consolidated basis instead of on an individual company basis.

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 was separately tracked and its treatment will be addressed 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.

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. On June 18, 2020, the PPUC entered a Final Implementation Order for a Phase IV EE&C Plan, operating from June 2021 through May 2026. The Final Implementation Order set demand reduction targets, relative to 2007 to 2008 peak demands, at 2.9% MW for ME, 3.3% MW for PN, 2.0% MW for Penn, and 2.5% MW for WP; and energy consumption reduction targets, as a percentage of the Pennsylvania Companies’ historic 2009 to 2010 reference load at 3.1% MWH for ME, 3.0% MWH for PN, 2.7% MWH for Penn, and 2.4% MWH for WP. Phase IV plans must be filed by November 30, 2020.

Pennsylvania EDCs may file with the PPUC for approval of an LTIIP for infrastructure improvements and costs related to highway relocation projects, after which a DSIC may be approved to recover LTIIP costs. On August 30, 2019, the Pennsylvania Companies filed Petitions for approval of new LTIIPs for the five-year period beginning January 1, 2020 and ending December 31, 2024 for a total capital investment of approximately $572 million for certain infrastructure improvement initiatives. On January 16, 2020, the PPUC approved the LTIIPs without modification. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016. On August 30, 2019, Penn filed a Petition seeking approval of a waiver of the statutory DSIC cap of 5% of distribution rate revenue and approval to increase the maximum allowable DSIC to 11.81% of distribution rate revenue for the five-year period of its proposed LTIIP. On March 12, 2020, an order was entered approving a settlement by all parties to that case which provides for a temporary increase in the recoverability cap from 5% to 7.5%, to expire on the earlier of the effective date of new base rates following Penn’s next base rate case or the expiration of its LTIIP II program.

Following the Pennsylvania Companies’ 2016 base rate proceedings, the PPUC ruled in a separate proceeding related to the DSIC mechanisms that the Pennsylvania Companies were not required to reflect federal and state income tax deductions related to DSIC-eligible property in DSIC rates, which decision was appealed by the Pennsylvania OCA to the Pennsylvania

67

Commonwealth Court. The Commonwealth Court reversed the PPUC’s decision and remanded the matter to require the Pennsylvania Companies to revise their tariffs and DSIC calculations to include ADIT and state income taxes. On April 7, 2020, the Pennsylvania Supreme Court issued an Order granting Petitions for Allowance of Appeal by both the PPUC and the Pennsylvania Companies of the Commonwealth Court’s Opinion and Order. Briefs were filed on June 25, 2020. An adverse ruling by the Pennsylvania Supreme Court is not expected to result in a material impact to FirstEnergy.

The PPUC issued an order on March 13, 2020, forbidding utilities from terminating residential service for non-payment for the duration of the COVID-19 pandemic. On May 13, 2020, the PPUC issued a Secretarial letter directing utilities to track all prudently-incurred incremental costs arising from the COVID-19 pandemic, and to create a regulatory asset for future recovery of incremental uncollectibles incurred as a result of the COVID-19 pandemic and termination moratorium.

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.

On August 21, 2019, MP and PE filed with the WVPSC their annual ENEC case requesting a decrease in ENEC rates of $6.1 million beginning January 1, 2020, representing a 0.4% decrease in rates versus those in effect on August 21, 2019. On October 11, 2019, MP and PE filed a supplement requesting approval of the termination of the 50 MW PPA with Morgantown Energy Associates, a NUG entity. A settlement between MP, PE, and the majority of the intervenors fully resolving the ENEC case, which maintains 2019 ENEC rates into 2020, and supports the termination of the Morgantown Energy Associates PPA was filed with the WVPSC on October 18, 2019. An order was issued on December 20, 2019, approving the ENEC settlement and termination of the PPA with Morgantown Energy Associates.

On August 21, 2019, MP and PE filed with the WVPSC for a reconciliation of their VMS and a periodic review of its vegetation management program requesting an increase in VMS rates of $7.6 million beginning January 1, 2020. The increase is due to moving from a 5-year maintenance cycle to a 4-year cycle and performing more operation and maintenance work and less capital work on the rights of way. The increase is a 0.5% increase in rates versus those in effect on August 21, 2019. All the parties reached a settlement in the case, and the WVPSC issued its order approving the settlement without change on December 20, 2019.

On March 13, 2020, the WVPSC urged all utilities to suspend utility service terminations except where necessary as a matter of safety or where requested by the customer. On May 15, 2020, the WVPSC issued an order to authorize MP and PE to record a deferral of additional, extraordinary costs directly related to complying with the various COVID-19 government shut-down orders and operational precautions, including impacts on uncollectible expense and cash flow related to temporary discontinuance of service terminations for non-payment and any credits to minimum demand charges associated with business customers adversely impacted by shut-downs or temporary closures related to the pandemic.

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 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 in the case of the Utilities major wholesale purchases remain subject to review and 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 six 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

68

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.

ATSI Transmission Formula Rate

On May 1, 2020, ATSI filed amendments to its formula rate to recover regulatory assets for certain costs that ATSI incurred as a result of its 2011 move from MISO to PJM, certain costs allocated to ATSI by FERC for transmission projects that were constructed by other MISO transmission owners, certain income tax-related adjustments, including, but not limited to impacts from the Tax Act discussed further below, and certain costs for transmission-related vegetation management programs. The amount on FirstEnergy’s Consolidated Balance Sheet for these regulatory assets was approximately $76 million and $73 million, as of June 30, 2020 and December 31, 2019, respectively. Per prior FERC orders, ATSI included a “cost-benefit study” to support recovery of ATSI’s costs to move to PJM, and the MISO transmission project costs that were allocated to ATSI. Certain intervenors filed protests of the formula rate amendments on May 29, 2020, and ATSI filed a reply on June 15, 2020. On June 30, 2020, FERC issued an initial order accepting the tariff amendments subject to refund, suspending the effective date for five months, and setting the matter for hearing and settlement proceedings. ATSI is engaged in settlement negotiations with the other parties.

FERC Actions on Tax Act

On March 15, 2018, FERC initiated proceedings on the question of how to 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 21, 2019, FERC issued a final rule (Order No. 864). Order No. 864 requires utilities with transmission formula rates to update their formula rate templates to include mechanisms to (i) deduct any excess ADIT from or add any deficient ADIT to their rate base; (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. Per FERC directives, ATSI submitted its compliance filing on May 1, 2020. MAIT submitted its compliance filing on June 1, 2020. Certain intervenors filed protests of the compliance filings, to which ATSI and MAIT responded. On May 15, 2020, TrAIL submitted its compliance filing and on June 1, 2020, PATH submitted its required compliance filing. These compliance filings each remain pending before FERC. MP, WP and PE – as holders of a “stated” transmission rate – are allowed to address these requirements in the course of their next transmission rates proceeding. JCP&L is addressing these requirements as part of its pending transmission formula rate case.

Transmission ROE Methodology

FERC’s methodology for calculating electric transmission utility ROE has been in transition as a result of an April 14, 2017 ruling by the D.C. Circuit that vacated FERC’s then-effective methodology. On October 16, 2018, FERC issued an order in which it proposed a revised ROE methodology. FERC proposed that, for complaint proceedings alleging that an existing ROE is not just and reasonable, FERC will 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 replacement 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. On November 21, 2019, FERC announced in a complaint proceeding involving MISO utilities that FERC would rely on the discounted cash flow and capital-asset pricing models as the basis for establishing ROE. Certain parties, including the Utilities, sought rehearing of FERC’s decision in the MISO utilities proceeding and, on May 21, 2020, FERC issued Opinion No. 569-A that changed FERC’s ROE methodology. Under this methodology FERC established an ROE that is based on three financial models – discounted cash flow, capital-asset pricing, and risk premium – to calculate a composite zone of reasonableness. FERC noted that utilities could, in utility-specific proceedings, ask to have the expected earnings methodology included in calculating the utility’s authorized ROE. FERC also noted that, going forward, it will divide that zone into three equal parts, to be used for high risk, normal risk, and low risk utilities. A given utility will be assigned to one of these three parts of the zone of reasonableness, and its ROE will be set at the median or midpoint of the other utilities that are in the applicable third of the zone. FirstEnergy filed a request for rehearing, which FERC denied on July 22, 2020. FirstEnergy also initiated appellate proceedings of FERC’s Opinion Nos. 569 and 569-A. Any changes to FERC’s transmission rate ROE and incentive policies would be applied on a prospective basis.

On March 20, 2020, FERC initiated a rulemaking proceeding on the transmission rate incentives provisions of Section 219 of the

69

2005 Energy Policy Act. Initial comments were submitted July 1, 2020, and reply comments were filed on July 16, 2020. FirstEnergy participated through EEI and through a consortium of PJM Transmission Owners.

JCP&L Transmission Formula Rate

On October 30, 2019, JCP&L filed tariff amendments with FERC to convert JCP&L’s existing stated transmission rate to a forward-looking formula transmission rate. JCP&L requested that the tariff amendments become effective January 1, 2020. On December 19, 2019, FERC issued its initial order in the case, allowing JCP&L to transition to a forward-looking formula rate as of January 1, 2020 as requested, subject to refund, pending further hearing and settlement proceedings. JCP&L and the parties to the FERC proceeding are engaged in settlement negotiations.

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. On September 13, 2019, the D.C. Circuit remanded the CSAPR update rule to the EPA citing that the rule did not eliminate upwind states’ significant contributions to downwind states’ air quality attainment requirements within applicable attainment deadlines. 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, 2020, 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, 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 nine states (including 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. On September 20, 2019, the EPA denied New York’s CAA Section 126 petition. On October 29, 2019, the State of New York appealed the denial of its petition to the D.C. Circuit. On May 19, 2020, the D.C. Circuit affirmed the EPA’s denial of the Delaware petition and affirmed in part the denial of Maryland petition deferring to the EPA’s finding that upwind sources with SCR controls, including Harrison, are already optimizing their use and therefore it is not cost effective to require additional control measures. Thus, the D.C. Circuit dismissed the appeals filed by the States of Delaware and Maryland as to Harrison. The D.C. Circuit Court remanded to the EPA the issue raised in the Maryland petition, of whether EGU’s in upwind states utilizing SNCR controls could increase operating time thereby reducing NOx emissions that may impact downwind states’ ozone compliance. On July 14, 2020, the D.C. Circuit reversed and remanded the New York petition to the EPA for further consideration. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss.

70

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 GHG 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. On June 19, 2019, the EPA repealed the CPP and replaced it with the ACE rule that establishes guidelines for states to develop standards of performance to address GHG emissions from existing coal-fired power plants. Depending on the outcomes 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. On November 4, 2019, the EPA issued a proposed rule revising the effluent limits for discharges from wet scrubber systems and extending the deadline for compliance to December 31, 2025. The EPA’s proposed rule retains the zero discharge standard and 2023 compliance date for ash transport water, but adds some allowances for discharge under certain circumstances. In addition, the EPA allows for less stringent limits for sub-categories of generating units based on capacity utilization, flow volume from the scrubber system, and unit retirement date. 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.

On September 29, 2016, FirstEnergy received a request from the EPA for information pursuant to CWA Section 308(a) for information concerning boron exceedances of effluent limitations established in the NPDES Permit for the former Mitchell Power Station’s Mingo landfill, owned by WP. On November 1, 2016, WP provided an initial response that contained information related

71

to a similar boron issue at the former Springdale Power Station’s landfill. The EPA requested additional information regarding the Springdale landfill and on November 15, 2016, WP provided a response and intends to fully comply with the Section 308(a) information request. On March 3, 2017, WP proposed to the PA DEP a re-route of its wastewater discharge to eliminate potential boron exceedances at the Springdale landfill. On January 29, 2018, WP submitted an NPDES permit renewal application to PA DEP proposing to re-route its wastewater discharge to eliminate potential boron exceedances at the Mingo landfill. On February 20, 2018, the DOJ issued a letter and tolling agreement on behalf of EPA alleging violations of the CWA at the Mingo landfill while seeking to enter settlement negotiations in lieu of filing a complaint. The EPA has proposed a penalty of $900,000 to settle alleged past boron exceedances at the Mingo and Springdale landfills. Negotiations are continuing and WP is unable to predict the outcome of this matter.

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. On December 2, 2019, the EPA published a proposed rule accelerating the date that certain CCR impoundments must cease accepting waste and initiate closure to August 31, 2020. The proposed rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria. On July 29, 2020, the EPA published a final rule revising the date that certain CCR impoundments must cease accepting waste and initiate closure to April 11, 2021. The final rule allows for an extension of the closure deadline based on meeting proscribed site-specific criteria.

FE 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, 2020, 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 $104 million have been accrued through June 30, 2020. Included in the total are accrued liabilities of approximately $68 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

United States v. Larry Householder, et al

On July 21, 2020, a complaint and supporting affidavit containing federal criminal allegations were unsealed against the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. Also, on July 21, 2020, and in connection with the investigation, FirstEnergy received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio. FirstEnergy was not aware of the criminal allegations, affidavit or subpoenas before July 21, 2020. FirstEnergy is cooperating fully in the investigation. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

Legal Proceedings Relating to United States v. Larry Householder, et al

In addition to the subpoenas referenced above under “—United States v. Larry Householder, et. al,”, certain FE stockholders and FirstEnergy customers filed several lawsuits against FirstEnergy and certain current and former directors, officers and other employees, and the complaints in each of these suits is related to allegations in the complaint and supporting affidavit relating to Ohio House Bill 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder.

•Gendrich v. Anderson, et al and Sloan v. Anderson, et al (Common Pleas Court, Summit County, OH); on July 26, 2020 and July 31, 2020, respectively, purported stockholders of FE filed shareholder derivative action lawsuits against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty.

72

•Smith v. FirstEnergy Corp. et al (Federal District Court, S.D. Ohio); on July 27, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE and FESC, alleging civil Racketeer Influenced and Corrupt Organizations Act violations.

•Owens v. FirstEnergy Corp. et al (Federal District Court, S.D. Ohio); on July 28, 2020, a purported stockholder of FE filed a putative class action lawsuit against FE and certain FE officers, purportedly on behalf of all purchasers of FE common stock from February 21, 2017 through July 21, 2020, asserting claims under Sections 10(b) and 20(a) of the Securities Exchange Act of 1934 and Rule 10b-5 promulgated thereunder, alleging misrepresentations or omissions by FirstEnergy concerning its business and results of operations.

•Buldas v. FirstEnergy Corp. et al and Hudock and Cameo Countertops, Inc. v. FirstEnergy Corp. et al (Federal District Court, S.D. Ohio); on July 31, 2020 and August 5, 2020, respectively, purported customers of FirstEnergy filed putative class action lawsuits against FE and FESC alleging civil violations of the Racketeer Influenced and Corrupt Organizations Act and the Ohio Corrupt Activity Act.

•Emmons v. FirstEnergy Corp. et al (Common Pleas Court, Cuyahoga County, OH); on August 4, 2020, a purported customer of FirstEnergy filed a putative class action lawsuit against FE, FESC, OE, TE and CEI, alleging several causes of action, including negligence and/or gross negligence, breach of contract, unjust enrichment, and unfair or deceptive consumer acts or practices.

•Miller v. Anderson, et al (Federal District Court, N.D. Ohio); on August 7, 2020, a purported stockholder of FE filed a shareholder derivative action lawsuit against certain FE directors and officers, alleging, among other things, breaches of fiduciary duty and violations of Section 14(a) of the Securities Exchange Act of 1934.

The plaintiffs in each of the above cases, seek, among other things, to recover an unspecified amount of damages. The Ohio Attorney General may be considering legal action and, in a letter dated July 24, 2020, notified FE of its duty to not destroy documents in its custody or control regarding Ohio House Bill 6. The outcome of any of these lawsuits is uncertain and could have a material adverse effect on FE’s or its subsidiaries’ financial condition, results of operations and cash flows. No contingency has been reflected in FirstEnergy’s consolidated financial statements as a loss is neither probable, nor is a loss or range of a loss reasonably estimable.

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, 2020, JCP&L, ME and PN had in total approximately $882 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 October 15, 2019, JCP&L, ME, PN and GPUN executed an asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of EnergySolutions, LLC, concerning the transfer and dismantlement of TMI-2. This transfer of TMI-2 to TMI-2 Solutions, LLC will include the transfer of: (i) the ownership and operating NRC licenses for TMI-2; (ii) the external trusts for the decommissioning and environmental remediation of TMI-2; and (iii) related liabilities of approximately $900 million as of June 30, 2020. There can be no assurance that the transfer will receive the required regulatory approvals and, even if approved, whether the conditions to the closing of the transfer will be satisfied. On November 12, 2019, JCP&L filed a Petition with the NJBPU seeking approval of the transfer and sale of JCP&L’s entire 25% interest in TMI-2 to TMI-2 Solutions, LLC. Also on November 12, 2019, JCP&L, ME, PN, GPUN and TMI-2 Solutions, LLC filed an application with the NRC seeking approval to transfer the NRC license for TMI-2 to TMI-2 Solutions, LLC. On Monday, August 10, 2020, JCP&L, ME, PN, GPUN, TMI-2 Solutions, LLC, and the PA DEP reached a settlement agreement regarding the decommissioning of TMI-2. The settlement agreement provides for increased and detailed oversight by the PA DEP over the decommissioning work, expenditures, and environmental impacts of the dismantlement of TMI-2 by TMI-2 Solutions, LLC. In addition, the PA DEP withdrew its objection to the TMI-2 transfer in the NRC proceedings. Both the NRC and NJBPU proceedings are ongoing. Assets and liabilities held for sale on the FirstEnergy Consolidated Balance Sheet associated with the transaction consist of asset retirement obligations of $709 million, NDTs of $882 million as well as property, plant and equipment with a net book value of zero, which are included in the regulated distribution segment.

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 and emerged on February 27, 2020. See Note 3, “Discontinued Operations,” for additional discussion.

73

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 9, “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 2016-13, “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. Prior to adoption, FirstEnergy analyzed its financial instruments within the scope of this guidance, primarily trade receivables and AFS debt securities. The adoption of this standard upon January 1, 2020 did not have a material impact to FirstEnergy’s financial statements and required additional disclosures in these Notes to the Consolidated Financial Statements. Please see above for additional information on FirstEnergy’s allowance for uncollectible customer receivables.

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 allows 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. FirstEnergy adopted this standard as of January 1, 2020, with no material impact to its financial statements.

ASU 2020-04, "Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting” (Issued March 2020): ASU 2020-04 provides temporary optional expedients and exceptions to the current guidance on contract modifications to ease the financial reporting burdens related to the expected market transition from LIBOR and other interbank offered rates to alternative reference rates. FirstEnergy’s $3.5 billion Revolving Credit Facility bears interest at fluctuating interest rates based on LIBOR and contains provisions (requiring an amendment) in the event that LIBOR can no longer be used. As of June 30, 2020, FirstEnergy has not utilized any of the expedients discussed within this ASU.

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 2019-12, "Simplifying the Accounting for Income Taxes" (Issued in December 2019): ASU 2019-12 enhances and simplifies various aspects of the income tax accounting guidance including the elimination of certain exceptions related to the approach for intra-period tax allocation, the methodology for calculating income taxes in an interim period and the recognition of deferred tax liabilities for outside basis differences. The new guidance also simplifies aspects of the accounting for franchise taxes and enacted changes in tax laws or rates and clarifies the accounting for transactions that result in a step-up in the tax basis of goodwill. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2020, with early adoption permitted.

74

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, 2020, 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 9, “Regulatory Matters,” and Note 10, “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

You should carefully consider the risk factors discussed in "Item 1A. Risk Factors" in FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2019, and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, which could materially affect FirstEnergy’s business, financial condition or future results. The information set forth in this report, including without limitation, the risk factors presented below, updates and should be read in conjunction with, the risk factors and information disclosed in FirstEnergy’s Annual Report on Form 10-K for the year ended December 31, 2019, and its Quarterly Report on Form 10-Q for the quarter ended March 31, 2020. In addition, because we cannot predict the impact that COVID-19 will ultimately have, its actual impact may also exacerbate other risks discussed in Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, and our Form 10-Q for the quarter ended March 31, 2020, any of which could have a material effect on us. The situation remains fluid and while we have not incurred significant disruptions thus far from the COVID-19 global pandemic, the likelihood of an adverse impact could increase the longer the global pandemic persists.

We Have Received Requests for Information Related to a Government Investigation, Which Could Divert Management’s Focus and Result in Substantial Investigation Expenses. The Investigation and Related Litigation Has Adversely Impacted the Trading Prices of our Securities and Could Have a Material Adverse Effect on our Reputation, Business, Financial Condition, Results of Operations or Cash Flows.

On July 21, 2020, we received subpoenas for records from the U.S. Attorney’s Office for the S.D. Ohio requesting the production of information concerning an investigation surrounding Ohio House Bill 6 involving the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. We are reviewing the details of the subpoenas and the investigation, and we are cooperating fully with the U.S. Attorney’s Office in its investigation. Following the announcement of the investigation surrounding Ohio House Bill 6, certain of our stockholders and customers filed several lawsuits against us and certain current and former directors, officers and other employees. See Note 10, “Commitments, Guarantees and Contingencies,” of the Notes to Consolidated Financial Statements for additional details on the government investigation and subsequent litigation surrounding the investigation of Ohio House Bill 6.

The investigation and related litigation could divert management’s focus and result in substantial investigation expenses, or otherwise require the commitment of substantial corporate resources. Furthermore, the publicity of the investigation has had an adverse impact on the trading prices of our securities. The outcome of the government investigation and related litigation is inherently uncertain. If one or more legal matters were resolved against us, our reputation, business, financial condition, results of operations or cash flow may be adversely affected. Further, such an outcome could result in significant compensatory or punitive monetary damages, remedial corporate measures or other relief against us that could adversely impact our operations.

We are unable to predict the outcome, duration, scope, result or related costs of the investigation and related litigation and, therefore, any of these risks could impact us significantly beyond expectations. Moreover, we are unable to predict the potential

75

for any additional investigations, litigation or regulatory actions, any of which could exacerbate these risks or expose us to potential criminal or civil liabilities, sanctions or other remedial measures.

We Could be Subject to Higher Costs and/or Penalties Related to Mandatory Reliability Standards Set by NERC/FERC or Changes in the Rules of Organized Markets, Which Could Have an Adverse Effect on our Financial Condition

Owners, operators, and users of the bulk electric system are subject to mandatory reliability standards promulgated by NERC and approved by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. NERC, RFC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject us to higher operating costs and/or increased capital expenditures. If we were found not to be in compliance with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties. FERC has authority to impose penalties up to and including $1 million per day for failure to comply with these mandatory electric reliability standards.

In addition to direct regulation by FERC, we are also subject to rules and terms of participation imposed and administered by various RTOs and ISOs that can have a material adverse impact on our business. For example, the independent market monitors of ISOs and RTOs may impose bidding and scheduling rules to curb the perceived potential for exercise of market power and to ensure the markets function appropriately. Such actions may materially affect our ability to sell, and the price we receive for, our energy and capacity. In addition, PJM may direct our transmission-owning affiliates to build new transmission facilities to meet PJM's reliability requirements or to provide new or expanded transmission service under the PJM Tariff.

We may be allocated a portion of the cost of transmission facilities built by others due to changes in RTO transmission rate design. We may be required to expand our transmission system according to decisions made by an RTO rather than our own internal planning processes. Various proposals and proceedings before FERC may cause transmission rates to change from time to time. In addition, RTOs have been developing rules associated with the allocation and methodology of assigning costs associated with improved transmission reliability, reduced transmission congestion and firm transmission rights that may have a financial impact on us.

As a member of an RTO, we are subject to certain additional risks, including those associated with the allocation among members of losses caused by unreimbursed defaults of other participants in that RTO’s market and those associated with complaint cases filed against the RTO that may seek refunds of revenues previously earned by its members.

In July 2020, as part of the PJM stakeholder process, proposed controversial amendments to the PJM Tariff were filed, which, if accepted by FERC, could limit discretionary investment in our transmission business. The terms of this proposed amendment would transfer control over parts of the transmission investment planning process from transmission owners, including us, to PJM. The inability to control the investment planning process could adversely affect our business operations, including the Energizing the Future program. In addition, the inability to control the investment planning process for our transmission business could adversely affect our results of operations and our financial condition.

Future Distributions to Shareholders May be Characterized for Shareholders’ Tax Purposes as a Return of Capital

When we make distributions to shareholders, we are required to subsequently determine and report the tax characterization of those distributions for purposes of shareholders’ income taxes. Whether a distribution is characterized as a dividend or a return of capital (and possible capital gain) depends upon an internal tax calculation to determine E&P for income tax purposes. E&P should not be confused with earnings or net income under GAAP. E&P is computed in the ordinary course following the completion of the taxable year and, therefore, it is possible that the final tax characterization of distributions may differ from estimates made at the time the distributions were actually paid.

In general, distributions are characterized as dividends to the extent the amount of such distributions do not exceed our calculation of current or accumulated E&P. Distributions in excess of current and accumulated E&P may be treated as a non-taxable return of capital. Generally, a non-taxable return of capital will reduce an investor’s basis in our stock for federal tax purposes, which will impact the calculation of gain or loss when the stock is sold.

Our internal calculation of E&P can be impacted by a variety of factors. It has been determined that a portion of the 2019 distributions to shareholders exceeds both current and accumulated E&P and, therefore has been characterized for shareholders’ tax purposes as a return of capital. Further, due to the FES Debtors’ emergence from bankruptcy in February 2020, which generated a large taxable loss for FirstEnergy’s consolidated tax group, it is anticipated that at least a portion of our current and future distributions will be characterized for shareholders’ tax purposes as a return of capital. Shareholders are urged to consult their own tax advisors regarding the income tax treatment of our distributions to them.

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

None.

76

ITEM 3.  DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4.  MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5.  OTHER INFORMATION

None.

ITEM 6.  EXHIBITS

Exhibit Number			Description
(A)	3.2(a)	Amendment to the Amended and Restated Code of Regulations of FirstEnergy Corp.
	4.1	Officer’s Certificate dated June 8, 2020 (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.1, File No. 333-21011).
	4.2	Form of Series A Note (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.2, File No. 333-21011).
	4.3	Form of Series B Note (incorporated by reference to FE’s Form 8-K filed June 8, 2020, Exhibit 4.3, File No. 333-21011).
(B)	10.1	FirstEnergy Corp. 2020 Incentive Compensation Plan (incorporated by reference to FE’s Form 8-K filed May 20, 2020, Exhibit 10.1, File No. 333-21011).
(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, 2020, 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.
	104	Cover Page Interactive Data File (the cover page XBRL tags are embedded within the Inline XBRL document contained in Exhibit 101).

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

(B) Management contract or compensatory plan contract or arrangement filed pursuant to Item 601 of Regulation S-K.

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.

August 17, 2020

FIRSTENERGY CORP.

Registrant

/s/ Jason J. Lisowski

Jason J. Lisowski

Vice President, Controller
and Chief Accounting Officer 

78