FirstEnergy (FE) 10-K 18 Feb 21 2020 FY Annual report Financial data

Cover Page

Cover Page - USD ($)	12 Months Ended
	Dec. 31, 2020	Jan. 31, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
Document Transition Report	false
Entity File Number	333-21011
Entity Registrant Name	FIRSTENERGY CORP
Entity Tax Identification Number	34-1843785
Entity Incorporation, State or Country Code	OH
Entity Address, Address Line One	76 South Main Street
Entity Address, City or Town	Akron
Entity Address, State or Province	OH
Entity Address, Postal Zip Code	44308
City Area Code	(800)
Local Phone Number	736-3402
Title of 12(b) Security	Common Stock, $0.10 par value per share
Trading Symbol	FE
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 20,967,401,361
Entity Common Stock Shares Outstanding		543,215,090
Documents Incorporated by Reference	Documents Incorporated By Reference PART OF FORM 10-K INTO WHICH DOCUMENT DOCUMENT IS INCORPORATED Proxy Statement for 2021 Annual Meeting of Shareholders of FirstEnergy Corp. to be held May 18, 2021 Part III
Entity Central Index Key	0001031296
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	FY
Amendment Flag	false

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
REVENUES:
Total revenues	[1]	$ 10,790	$ 11,035	$ 11,261
OPERATING EXPENSES:
Fuel		369	497	538
Purchased power		2,701	2,927	3,109
Other operating expenses		3,291	2,952	3,133
Provision for depreciation		1,274	1,220	1,136
Deferral of regulatory assets, net		(53)	(79)	(150)
General taxes		1,046	1,008	993
Total operating expenses		8,628	8,525	8,759
OPERATING INCOME		2,162	2,510	2,502
OTHER INCOME (EXPENSE):
Miscellaneous income, net		432	243	205
Pension and OPEB mark-to-market adjustment		(477)	(674)	(144)
Interest expense		(1,065)	(1,033)	(1,116)
Capitalized financing costs		77	71	65
Total other expense		(1,033)	(1,393)	(990)
INCOME BEFORE INCOME TAXES		1,129	1,117	1,512
INCOME TAXES		126	213	490
INCOME FROM CONTINUING OPERATIONS		1,003	904	1,022
Discontinued operations (Note 3)	[2]	76	8	326
NET INCOME		1,079	912	1,348
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 1)		0	4	367
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS		$ 1,079	$ 908	$ 981
EARNINGS PER SHARE OF COMMON STOCK:
Basic - Continuing Operations (in dollars per share)		$ 1.85	$ 1.69	$ 1.33
Basic - Discontinued Operations (in dollars per share)		0.14	0.01	0.66
Basic - Net Income Attributable to Common Stockholders (in dollars per share)		1.99	1.70	1.99
Diluted - Continuing Operations (in dollars per share)		1.85	1.67	1.33
Diluted - Discontinued Operations (in dollars per share)		0.14	0.01	0.66
Diluted - Net Income Attributable to Common Stockholders (in dollars per share)		$ 1.99	$ 1.68	$ 1.99
WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:
Basic (in shares)		542	535	492
Diluted (in shares)		543	542	494
Distribution services and retail generation
REVENUES:
Total revenues		$ 8,688	$ 8,720	$ 8,937
Transmission
REVENUES:
Total revenues		1,613	1,510	1,335
Other
REVENUES:
Total revenues		$ 489	$ 805	$ 989
[1]	Includes excise and gross receipts tax collections of $362 million, $373 million and $386 million in 2020, 2019 and 2018, respectively.
[2]	Net of income tax benefit of $59 million, $5 million, and $1.3 billion in 2020, 2019 and 2018, respectively.

Consolidated Statements of In_2

Consolidated Statements of Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement [Abstract]
Excise tax collections included in Revenue	$ 362	$ 373	$ 386
Income tax benefit	$ 59	$ 5	$ 1,300

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
NET INCOME	$ 1,079	$ 912	$ 1,348
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(34)	(31)	(83)
Amortized losses on derivative hedges	1	2	21
Change in unrealized gains on available-for-sale securities	0	0	(106)
Other comprehensive loss	(33)	(29)	(168)
Income tax benefits on other comprehensive loss	(8)	(8)	(67)
Other comprehensive loss, net of tax	(25)	(21)	(101)
COMPREHENSIVE INCOME	$ 1,054	$ 891	$ 1,247

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
CURRENT ASSETS:
Cash and cash equivalents	$ 1,734	$ 627
Restricted cash	67	52
Receivables-
Customers	1,203	1,091
Other, net of allowance for uncollectible accounts of $26 in 2020 and $21 in 2019	236	203
Materials and supplies, at average cost	317	281
Prepaid taxes and other	157	157
Current assets - discontinued operations	0	33
Total current assets	3,714	2,444
PROPERTY, PLANT AND EQUIPMENT:
In service	43,654	41,767
Less — Accumulated provision for depreciation	11,938	11,427
Net Plant	31,716	30,340
Construction work in progress	1,578	1,310
Total	33,294	31,650
PROPERTY, PLANT AND EQUIPMENT, NET - HELD FOR SALE (NOTE 15)	45	0
INVESTMENTS:
Nuclear fuel disposal trust	283	270
Other	322	299
Investments - held for sale (Note 15)	0	882
Total other property and investments	605	1,451
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	5,618
Regulatory assets	82	99
Other	1,106	1,039
Total deferred charges and other assets	6,806	6,756
Total assets	44,464	42,301
CURRENT LIABILITIES:
Currently payable long-term debt	146	380
Short-term borrowings	2,200	1,000
Accounts payable	827	918
Accrued interest	282	249
Accrued taxes	640	545
Accrued compensation and benefits	349	258
Other	560	1,425
Total current liabilities	5,004	4,862
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 543,117,533 and 540,652,222 shares outstanding as of December 31, 2020 and December 31, 2019, respectively	54	54
Other paid-in capital	10,076	10,868
Accumulated other comprehensive income (loss)	(5)	20
Accumulated deficit	(2,888)	(3,967)
Total stockholders' equity	7,237	6,975
Long-term debt and other long-term obligations	22,131	19,618
Total capitalization	29,368	26,593
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	3,095	2,849
Retirement benefits	3,345	3,065
Regulatory liabilities	1,826	2,360
Asset retirement obligations	159	165
Adverse power contract liability	30	49
Other	1,637	1,667
Noncurrent liabilities - held for sale (Note 15)	0	691
Total noncurrent liabilities	10,092	10,846
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 15)
Total liabilities and capitalization	44,464	42,301
Affiliated companies
Receivables-
Less — Allowance for uncollectible customer receivables	0	1,063
Customers	0	0
CURRENT LIABILITIES:
Accounts payable	0	87
Customer
Receivables-
Customers	1,367	1,137
Less — Allowance for uncollectible customer receivables	164	46
Customers	$ 1,203	$ 1,091

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Stockholders’ equity-
Common stock, par value (in dollars per share)	$ 0.10	$ 0.10
Common stock, authorized (in shares)	700,000,000	700,000,000
Common stock, outstanding (in shares)	543,117,533	540,652,222
Other
Receivables-
Allowance for uncollectible accounts	$ 26	$ 21
Affiliated companies
Receivables-
Allowance for uncollectible accounts	$ 0	$ 1,063

Consolidated Statements of Comm

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) - USD ($) $ in Millions		Total	Common Stock	OPIC	AOCI	Accumulated Deficit	Series A Convertible Preferred Stock
Beginning Balance (in shares) at Dec. 31, 2017			445,000,000				0
Beginning Balance at Dec. 31, 2017		$ 3,925	$ 44	$ 10,001	$ 142	$ (6,262)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
NET INCOME		1,348				1,348
Other comprehensive loss, net of tax		(101)			(101)
Stock-based compensation		60		60
Cash dividends declared on common stock		(906)		(906)
Cash dividends declared on preferred stock		(71)		(71)
Stock Investment Plan and certain share-based benefit plans (in shares)			4,000,000
Stock Investment Plan and certain share-based benefit plans		62	$ 1	61
Stock issuance (Note 11) (in shares)	[1]		30,000,000				1,600,000
Stock issuance (Note 11)	[1]	2,462	$ 3	2,297			$ 162
Conversion of Series A Convertible Stock (Note 11) (in shares)			33,000,000				(900,000)
Conversion of Series A Convertible Stock		0	$ 3	88			$ (91)
Ending Balance (in shares) at Dec. 31, 2018			512,000,000				700,000
Ending Balance at Dec. 31, 2018		6,814	$ 51	11,530	41	(4,879)	$ 71
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Impact of adopting new accounting pronouncements		35				35
NET INCOME		912				912
Other comprehensive loss, net of tax		(21)			(21)
Stock-based compensation		41		41
Cash dividends declared on common stock		(824)		(824)
Cash dividends declared on preferred stock		(3)		(3)
Stock Investment Plan and certain share-based benefit plans (in shares)			3,000,000
Stock Investment Plan and certain share-based benefit plans		56		56
Conversion of Series A Convertible Stock (Note 11) (in shares)			26,000,000				(700,000)
Conversion of Series A Convertible Stock		$ 0	$ 3	68			$ (71)
Ending Balance (in shares) at Dec. 31, 2019		540,652,222	541,000,000				0
Ending Balance at Dec. 31, 2019		$ 6,975	$ 54	10,868	20	(3,967)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Impact of adopting new accounting pronouncements		6,975
NET INCOME		1,079				1,079
Other comprehensive loss, net of tax		(25)			(25)
Stock-based compensation		26		26
Cash dividends declared on common stock		(846)		(846)
Stock Investment Plan and certain share-based benefit plans (in shares)			2,000,000
Stock Investment Plan and certain share-based benefit plans		$ 28		28
Ending Balance (in shares) at Dec. 31, 2020		543,117,533	543,000,000				0
Ending Balance at Dec. 31, 2020		$ 7,237	$ 54	$ 10,076	$ (5)	$ (2,888)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Impact of adopting new accounting pronouncements		$ 7,237
[1]	The Preferred Stock included an embedded conversion option at a price that is below the fair value of the Common Stock on the commitment date. This BCF, which was approximately $296 million, was recorded to OPIC as well as the amortization of the BCF (deemed dividend) through the period from the issue date to the first allowable conversion date (July 22, 2018) and as such there is no net impact to OPIC for the year ended December 31, 2018.

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity (Parenthetical) $ in Millions	Jan. 31, 2018USD ($)
OPIC
Amount of beneficial conversion	$ 296

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$ 1,079	$ 912	$ 1,348
Adjustments to reconcile net income to net cash from operating activities-
Gain on disposal, net of tax (Note 3)	(76)	(59)	(435)
Depreciation and amortization	1,199	1,217	1,384
Pension trust contributions	0	(500)	(1,250)
Retirement benefits, net of payments	(301)	(108)	(137)
Pension and OPEB mark-to-market adjustment	477	676	144
Deferred income taxes and investment tax credits, net	113	252	485
Asset removal costs charged to income	36	28	42
Settlement agreement and tax sharing payments to the FES Debtors	(978)	0	0
Changes in current assets and liabilities-
Receivables	(129)	271	(248)
Materials and supplies	(32)	(37)	24
Prepaid taxes and other	6	10	(61)
Accounts payable	(138)	(49)	109
Accrued taxes	159	12	0
Accrued interest	33	6	(25)
Accrued compensation and benefits	97	(60)	37
Other current liabilities	(16)	(21)	(121)
Other	(106)	(83)	114
Net cash provided from operating activities	1,423	2,467	1,410
New financing-
Long-term debt	3,425	2,300	1,474
Short-term borrowings, net	1,200	0	950
Preferred stock issuance	0	0	1,616
Common stock issuance	0	0	850
Redemptions and repayments-
Long-term debt	(1,114)	(789)	(2,608)
Tender premiums paid on debt redemptions	0	0	(89)
Preferred stock dividend payments	0	(6)	(61)
Common stock dividend payments	(845)	(814)	(711)
Other	(59)	(35)	(27)
Net cash provided from financing activities	2,607	656	1,394
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,657)	(2,665)	(2,675)
Proceeds from asset sales	2	47	425
Sales of investment securities held in trusts	186	1,637	909
Purchases of investment securities held in trusts	(208)	(1,675)	(963)
Notes receivable from affiliated companies	0	0	(500)
Asset removal costs	(224)	(217)	(218)
Other	(7)	0	4
Net cash used for investing activities	(2,908)	(2,873)	(3,018)
Net change in cash, cash equivalents and restricted cash	1,122	250	(214)
Cash, cash equivalents, and restricted cash at beginning of period	679	429	643
Cash, cash equivalents, and restricted cash at end of period	1,801	679	429
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: beneficial conversion feature	0	0	296
Non-cash transaction: deemed dividend convertible preferred stock	0	0	(296)
Interest (net of amounts capitalized)	970	960	1,071
Income taxes, net of refunds	$ 6	$ 12	$ 49

ORGANIZATION AND BASIS OF PRESE

ORGANIZATION AND BASIS OF PRESENTATION	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, 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: AE Supply, FirstEnergy Properties, Inc., FEV, FirstEnergy License Holding Company, 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 ten 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 two 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. 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 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. As further discussed below, 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. Restricted Cash Restricted cash primarily relates to the consolidated VIE's discussed below. The cash collected from JCP&L, MP, PE and the Ohio Companies' customers is used to service debt of their respective funding companies. 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 is actively monitoring the continued impact COVID-19 is having on its customers’ receivable balances, which include increasing arrears balances since the pandemic has begun. 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. 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 continued impact the COVID-19 pandemic is having on its business, however, FirstEnergy does not currently expect disruptions in its ability to deliver service to customers or any material impact on its capital spending plan. FirstEnergy continues to effectively manage operations during the pandemic in order 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 RECEIVABLES Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2020, 2019 and 2018 are as follows: (In millions) 2020 2019 2018 Customer Receivables Beginning of year balance $ 46 $ 50 $ 49 Charged to income (1) 174 81 77 Charged to other accounts (2) 46 47 60 Write-offs (102) (132) (136) End of year balance $ 164 $ 46 $ 50 Other Receivables Beginning of year balance $ 21 $ 2 $ 1 Charged to income 7 27 13 Charged to other accounts (2) 10 1 — Write-offs (12) (9) (12) End of year balance $ 26 $ 21 $ 2 Affiliated Companies Receivables (3) Beginning of year balance $ 1,063 $ 920 $ — Charged to income — 143 920 Charged to other accounts (2) — — — Write-offs (1,063) — — End of year balance $ — $ 1,063 $ 920 (1) Customer receivable amounts charged to income for the years ended December 31, 2020, 2019 and 2018 include approximately $103 million, $25 million, and $24 million respectively, deferred for future recovery. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (3) Amounts relate to the FES Debtors and are included in discontinued operations. Write-off of $1.1 billion in 2020 was recognized upon their emergence in February 2020. See Note 3, "Discontinued Operations" for additional information. Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities. There was no material concentration of receivables as of December 31, 2020 and 2019, with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2020 and 2019, net of allowance for uncollectible accounts, are included below. Customer Receivables December 31, 2020 December 31, 2019 (In millions) Billed $ 636 $ 564 Unbilled 567 527 Total $ 1,203 $ 1,091 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, amount of receivable balances that are past-due, payment options and programs available to customers, and the methods that the Utilities are able to utilize to ensure payment. FirstEnergy reviews its allowance for uncollectible customer receivables utilizing a quantitative and qualitative assessment, which includes 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. Beginning March 13, 2020, FirstEnergy temporarily suspended customer disconnections for nonpayment and ceased collection activities as a result of the ongoing pandemic and in accordance with state regulatory requirements. The temporary suspension of disconnections for nonpayment and ceased collection activities extended into the fourth quarter of 2020 and resumed for most customers before the end of 2020. Customers are subject to each state's applicable regulations on winter moratoriums for residential customers, which begin as early as November 1, 2020, and are in effect until April 15, 2021. See Note 14, “Regulatory Matters,” for further discussion on applicable regulations that may alter residential customer disconnection and collection activity, such as winter moratoriums. 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 as what collection methods are or were 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 $121 million in the year 2020, of which approximately $90 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, respectively, to track and create a regulatory asset for future recovery of incremental costs, including uncollectible expenses, incurred as a result of the pandemic. In Pennsylvania, the PPUC has 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. On October 13, 2020, the PPUC entered an order that permits the Pennsylvania Companies to create a regulatory asset for incremental expenses associated with lifting the service termination moratorium, as further discussed below. 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. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers. FirstEnergy records regulatory assets and liabilities that result from the regulated rate-making process that would not be recorded under GAAP for non-regulated entities. These assets and liabilities are amortized in the Consolidated Statements of Income concurrent with the recovery or refund through customer rates. FirstEnergy believes that it is probable that its regulatory assets and liabilities will be recovered and settled, respectively, through future rates. 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 relate to 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 FirstEnergy and information on comparable companies within similar jurisdictions, as well as assessing progress of communications between FirstEnergy and regulators. Certain of these regulatory assets, totaling approximately $117 million and $111 million as of December 31, 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, $79 million and $73 million as of December 31, 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 14, "Regulatory Matters" for additional information. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2020 and December 31, 2019, and the changes during the year ended December 31, 2020: Net Regulatory Assets (Liabilities) by Source December 31, December 31, Change (In millions) Customer payables for future income taxes $ (2,369) $ (2,605) $ 236 Nuclear decommissioning and spent fuel disposal costs (102) (197) 95 Asset removal costs (721) (756) 35 Deferred transmission costs 316 298 18 Deferred generation costs 104 214 (110) Deferred distribution costs 136 155 (19) Contract valuations 41 51 (10) Storm-related costs 748 551 197 Uncollectible and COVID-19 related costs 97 3 94 Other 6 25 (19) Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (1,744) $ (2,261) $ 517 The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2020 and 2019, of which approximately $195 million and $228 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction: Regulatory Assets by Source Not Earning a Current Return December 31, December 31, Change (in millions) Deferred transmission costs $ 29 $ 27 $ 2 Deferred generation costs 5 15 (10) Storm-related costs 654 471 183 COVID-19 related costs 66 — 66 Other 35 32 3 Regulatory Assets Not Earning a Current Return $ 789 $ 545 $ 244 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. During 2019 and 2018, 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. Year Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2020 2019 2018 (In millions, except per share amounts) EPS of Common Stock Income from continuing operations $ 1,003 $ 904 $ 1,022 Less: Preferred dividends — (3) (71) Less: Amortization of beneficial conversion feature — — (296) Less: Undistributed earnings allocated to preferred stockholders (1) N/A (1) — Income from continuing operations available to common stockholders 1,003 900 655 Discontinued operations, net of tax 76 8 326 Less: Undistributed earnings allocated to preferred stockholders (1) N/A — — Income from discontinued operations available to common stockholders 76 8 326 Income attributable to common stockholders, basic $ 1,079 $ 908 $ 981 Income allocated to preferred stockholders, preferred dilutive (2) N/A 4 N/A Income attributable to common stockholders, dilutive $ 1,079 $ 912 $ 981 Share Count information: Weighted average number of basic shares outstanding 542 535 492 Assumed exercise of dilutive stock options and awards 1 3 2 Assumed conversion of preferred stock — 4 — Weighted average number of diluted shares outstanding 543 542 494 Income attributable to common stockholders, per common share: Income from continuing operations, basic $ 1.85 $ 1.69 $ 1.33 Discontinued operations, basic 0.14 0.01 0.66 Income attributable to common stockholders, basic $ 1.99 $ 1.70 $ 1.99 Income from continuing operations, diluted $ 1.85 $ 1.67 $ 1.33 Discontinued operations, diluted 0.14 0.01 0.66 Income attributable to common stockholders, diluted $ 1.99 $ 1.68 $ 1.99 (1) Undistributed earnings were not allocated to participating securities for the year ended December 31, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss. Undistributed earning allocated to participating securities for the years ended December 31, 2019 and 2020 were immaterial. (2) The shares of common stock issuable upon conversion of the preferred shares (26 million shares) were not included for 2018 as their inclusion would be anti-dilutive to basic EPS from continuing operations. Amounts allocated to preferred stockholders of $4 million for the year ended December 31, 2019 are included within Income from continuing operations available to common stockholders for diluted earnings. For the year ended December 31, 2018, approximately 1 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. For the year ended December 31, 2019, no shares from stock options or awards were excluded from the calculation of diluted shares. For the year ended December 31, 2020, approximately 80 thousand shares from stock options and awards were excluded from the calculation of diluted shares outstanding, as their inclusion would be antidilutive. PROPERTY, PLANT AND EQUIPMENT Property, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred. Property, plant and equipment balances by segment as of December 31, 2020 and 2019, were as follows: December 31, 2020 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 29,775 $ (8,800) $ 20,975 $ 841 $ 21,816 Regulated Transmission 12,912 (2,609) 10,303 671 10,974 Corporate/Other 1,039 (556) 483 66 549 Total $ 43,726 $ (11,965) $ 31,761 $ 1,578 $ 33,339 December 31, 2019 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 28,735 $ (8,540) $ 20,195 $ 744 $ 20,939 Regulated Transmission 12,023 (2,383) 9,640 526 10,166 Corporate/Other 1,009 (504) 505 40 545 Total $ 41,767 $ (11,427) $ 30,340 $ 1,310 $ 31,650 (1) Includes finance leases of $153 million and $163 million as of December 31, 2020 and 2019, respectively. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above. Regulated Distribution has approximately $2.1 billion of total regulated generation property, plant and equipment. Included within Regulated Distribution is $882 million of assets classified as held for sale as of December 31, 2019 associated with the asset purchase and sale agreements with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC. With the receipt of all required regulatory approvals, the transaction was consummated on December 18, 2020. As a result, during the fourth quarter of 2020 FirstEnergy recognized an after tax-gain of approximately $33 million, primarily associated with the write-off of a tax related regulatory liability. See Note 15, "Commitments, Guarantees and Contingencies" for additional information. Also included within the segment is $45 million of assets classified as held for sale as of December 31, 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 14, "Regulatory Matters" for additional information. FirstEnergy provides for depreciation on a straight-line basis at various rates over the estimated lives of property included in plant in service. The respective annual composite depreciation rates for FirstEnergy were 2.7%, 2.7% and 2.6% in 2020, 2019 and 2018, respectively. For the years ended December 31, 2020, 2019 and 2018, capitalized financing costs on FirstEnergy's Consolidated Statements of Income include $49 million, $45 million and $46 million, respectively, of allowance for equity funds used during construction and $28 million, $26 million and $19 million, respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 16.25% interest (487 MWs) in the 3,003 MW Bath County pumped-storage, hydroelectric station in Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Total property, plant and equipment includes $157 million representing AGC's share in this facility as of December 31, 2020. AGC is obligated to pay its share of the costs of this jointly owned facility in the same proportion as its ownership interests using its own financing. AGC's share of direct expenses of the joint plant is included in operating expenses on FirstEnergy's Consolidated Statements of Income. AGC provides the generation capacity from this facility to its owner, MP. Asset Retirement Obligations FE recognizes an ARO for the future remediation of environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2020, including the transfer of TMI-2, its NDT and related decommissioning liabilities to TMI-2 Solutions, LLC, a subsidiary of Energy Solutions , LLC, in the fourth quarter of 2020, are described further in Note 13, "Asset Retirement Obligations." Asset Impairments FirstEnergy evaluates long-lived assets classified as held and used for impairment when events or changes in circumstances indicate the carrying value of the long-lived assets may not be recoverable. First, the estimated undiscounted future cash flows attributable to the assets is compared with the carrying value of the assets. If the carrying value is greater than the undiscounted future cash flows, an impairment charge is recognized equal to the amount the carrying value of the assets exceeds its estimated fair value. GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any. As of July 31, 2020, FirstEnergy performed a qualitative assessment of the Regulated Distribution and Regulated Transmission reporting units' goodwill, assessing economic, industry and market considerations in addition to the reporting units' overall financial performance. Key factors used in the assessment included: growth rates, interest rates, expected capital expenditures, utility sector market performance, regulatory and legal developments, and other market considerations. It was determined that the fair values of these reporting units were, more likely than not, greater than their carrying values and a quantitative analysis was not necessary. FirstEnergy's reporting units are consistent with its reportable segments and consist of Regulated Distribution and Regulated Transmission. The following table presents goodwill by reporting unit as of December 31, 2020: (In millions) Regulated Distribution Regulated Transmission Consolidated Goodwill $ 5,004 $ 614 $ 5,618 INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed. DERIVATIVES FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. • JCP&L Securitization - JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. • MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds. See Note 11, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic

REVENUE

REVENUE	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
REVENUE	REVENUE FirstEnergy accounts for revenues from contracts with customers under ASC 606, “ Revenue from Contracts with Customers. ” Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the 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 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 represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2020: Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,259 $ — $ (88) $ 5,171 Retail generation 3,577 — (60) 3,517 Wholesale sales 251 — 9 260 Transmission (2) — 1,613 — 1,613 Other 140 — — 140 Total revenues from contracts with customers $ 9,227 $ 1,613 $ (139) $ 10,701 ARP (3) 43 — — 43 Other non-customer revenue 93 17 (64) 46 Total revenues $ 9,363 $ 1,630 $ (203) $ 10,790 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($2 million at Regulated Distribution and $7 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2020, is primarily related to shared savings revenue in Ohio. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2019: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,133 $ — $ (83) $ 5,050 Retail generation 3,727 — (57) 3,670 Wholesale sales (2) 411 — 12 423 Transmission (2) — 1,510 — 1,510 Other 150 — 2 152 Total revenues from contracts with customers $ 9,421 $ 1,510 $ (126) $ 10,805 ARP (3) 181 — — 181 Other non-customer revenue 96 16 (63) 49 Total revenues $ 9,698 $ 1,526 $ (189) $ 11,035 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($16 million at Regulated Distribution and $19 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2019, includes DMR revenue, lost distribution and shared savings revenue in Ohio. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2018: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,159 $ — $ (104) $ 5,055 Retail generation 3,936 — (54) 3,882 Wholesale sales (2) 502 — 22 524 Transmission (2) — 1,335 — 1,335 Other 144 — 4 148 Total revenues from contracts with customers $ 9,741 $ 1,335 $ (132) $ 10,944 ARP (3) 254 — — 254 Other non-customer revenue 108 18 (63) 63 Total revenues $ 10,103 $ 1,353 $ (195) $ 11,261 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($131 million at Regulated Distribution and $16 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2018, includes DMR revenue, lost distribution and shared savings revenue in Ohio. Other non-customer revenue includes revenue from late payment charges of $31 million, $37 million and $39 million, respectively, for the years ended December 31, 2020, 2019 and 2018. During 2020, certain late payment charges began to be waived in response to the COVID-19 pandemic, and as a result, FirstEnergy did not recognize these revenues. Late payment charges have resumed for most customers as of December 31, 2020. 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 $14 million, $8 million and $18 million, respectively, for the years ended December 31, 2020, 2019 and 2018. Regulated Distribution The Regulated Distribution segment distributes electricity through FirstEnergy’s ten utility operating companies and also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey, 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 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 14 "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 years ended December 31, 2020, 2019 and 2018 by class: For the Years Ended December 31, Revenues by Customer Class 2020 2019 2018 (In millions) Residential $ 5,539 $ 5,412 $ 5,598 Commercial 2,140 2,252 2,350 Industrial 1,076 1,106 1,056 Other 81 90 91 Total $ 8,836 $ 8,860 $ 9,095 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, lost distribution and shared savings revenue in 2019, and shared savings in 2020. 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 JCP&L, MP, PE and WP, although as further discussed in Note 14, “Regulatory Matters,” MP, PE and WP filed with FERC on October 29, 2020, to convert their existing stated transmission rates to forward-looking formula rates, effective January 1, 2021. 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 14, “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 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 for the years ended December 31, 2020, 2019 and 2018: For the Years Ended December 31, Transmission Owner 2020 2019 2018 (In millions) ATSI $ 804 $ 754 $ 664 TrAIL 247 242 237 MAIT 250 224 150 JCP&L 178 160 159 Other 134 130 125 Total Revenues $ 1,613 $ 1,510 $ 1,335

DISCONTINUED OPERATIONS

DISCONTINUED OPERATIONS	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
DISCONTINUED OPERATIONS	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 of 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 FES 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 Agreement 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 Debtors 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. 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 $1.1 billion, net of valuation allowances recorded against the state tax benefit ($80 million) and the aforementioned unrecognized tax benefits ($72 million). 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 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 were recorded. However, full valuation allowances were recorded against the deferred tax assets related to the carryforward of nondeductible interest as future utilization of the carryforwards requires taxable income from sources other than regulated utility businesses. Final regulations under Section 163(j) were issued in July 2020 and January 2021 but do not materially change these results. All tax expense related to nondeductible interest in 2018 and 2019 was recorded in discontinued operations as it was entirely attributed to the inclusion of the FES Debtors in FirstEnergy's consolidated tax group. Pursuant to certain safe harbor rules in the final 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 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. In September 2020, FirstEnergy filed its 2019 federal income tax return with the IRS and recognized a $6 million charge to discontinued operations in the third quarter of 2020, resulting from final adjustments to 2019 intercompany tax sharing related to the FES Debtors. The final intercompany tax sharing adjustment for the 2020 federal income tax return to be filed during 2021 is an estimated $12 million tax benefit and was recorded during the fourth quarter of 2020 in discontinued operations. 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 years ended December 31, 2020, 2019, and 2018 were as follows: For the Years Ended December 31, (In millions) 2020 2019 2018 (1) Revenues $ 7 $ 188 $ 989 Fuel (6) (140) (304) Purchased power — — (84) Other operating expenses (6) (63) (435) Provision for depreciation — — (96) General taxes — (14) (35) Pleasants economic interest (2) 5 27 — Other expense, net — (2) (83) Loss from discontinued operations, before tax — (4) (48) Income tax expense (benefit) — 47 61 Loss from discontinued operations, net of tax — (51) (109) Removal of investment in FES and FENOC — — 2,193 Assumption of benefit obligations retained at FE — — (820) Guarantees and credit support provided by FE — — (139) Reserve on receivables and allocated pension/OPEB mark-to-market — — (914) Settlement consideration and services credit (1) 7 (1,197) Accelerated net pension and OPEB prior service credits 18 — — Gain (loss) on Disposal of FES and FENOC, before tax 17 7 (877) Income tax benefit including worthless stock deduction (59) (52) (1,312) Gain on disposal of FES and FENOC, net of tax 76 59 435 Income from discontinued operations $ 76 $ 8 $ 326 (1) Discontinued operations include results of FES and FENOC through March 31, 2018, when deconsolidated from FirstEnergy's financial statements. (2) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019. As discussed above, settlement of the economic interests occurred during the first quarter of 2020. FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2020, 2019 and 2018: For the Years Ended December 31, (In millions) 2020 2019 2018 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ 76 $ 8 $ 326 Gain on disposal, net of tax (76) (59) (435) Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs — — 110 Deferred income taxes and investment tax credits, net — 47 61 Unrealized (gain) loss on derivative transactions — — (10) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions — — (27) Sales of investment securities held in trusts — — 109 Purchases of investment securities held in trusts — — (122)

ACCUMULATED OTHER COMPREHENSIVE

ACCUMULATED OTHER COMPREHENSIVE INCOME	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2020, 2019 and 2018, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2018 $ (22) $ 67 $ 97 $ 142 Other comprehensive income before reclassifications — (97) (9) (106) Amounts reclassified from AOCI 8 (1) (74) (67) Deconsolidation of FES and FENOC 13 (8) — 5 Other comprehensive income (loss) 21 (106) (83) (168) Income tax (benefits) on other comprehensive income (loss) 10 (39) (38) (67) Other comprehensive income (loss), net of tax 11 (67) (45) (101) AOCI Balance, December 31, 2018 $ (11) $ — $ 52 $ 41 Other comprehensive income before reclassifications — — (2) (2) Amounts reclassified from AOCI 2 — (29) (27) Other comprehensive income (loss) 2 — (31) (29) Income tax (benefits) on other comprehensive income (loss) — — (8) (8) Other comprehensive income (loss), net of tax 2 — (23) (21) AOCI Balance, December 31, 2019 $ (9) $ — $ 29 $ 20 Amounts reclassified from AOCI 1 — (34) (33) Other comprehensive income (loss) 1 — (34) (33) Income tax (benefits) on other comprehensive income (loss) — — (8) (8) Other comprehensive income (loss), net of tax 1 — (26) (25) AOCI Balance, December 31, 2020 $ (8) $ — $ 3 $ (5) (1) Relates to previous cash flow hedges used to hedge fixed rate long-term debt securities prior to their issuance. The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2020, 2019 and 2018: Year Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (1) 2020 2019 2018 (2) (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — $ 1 Other operating expenses Long-term debt 1 2 7 Interest expense — — (2) Income taxes $ 1 $ 2 $ 6 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ — $ — $ (1) Discontinued operations Defined benefit pension and OPEB plans Prior-service costs $ (34) $ (29) $ (74) (3) 8 8 19 Income taxes $ (26) $ (21) $ (55) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ". (3) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Postemployment Benefits," for additional details.

PENSION AND OTHER POST-EMPLOYME

PENSION AND OTHER POST-EMPLOYMENT BENEFITS	12 Months Ended
	Dec. 31, 2020
Retirement Benefits [Abstract]
PENSION AND OTHER POST-EMPLOYMENT BENEFITS	PENSION AND OTHER POST-EMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the 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 a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. 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 first quarter 2020 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. In the fourth quarter 2020, FirstEnergy recognized a $54 million pension and OPEB mark-to-market adjustment, primarily reflecting a 29 bps decrease in the discount rate used to measure benefit obligations from February 27, 2020, partially offset by higher than expected return on assets. Of the $54 million, approximately $21 million was allocated to certain of the Transmission Companies that are expected to be recovered through formula transmission rates. The annual pension and OPEB mark-to-market adjustments for the years ended December 31, 2020, 2019, and 2018 were $477 million (including the $423 million in the first quarter of 2020 described above), $676 million, and $145 million, respectively. Of these amounts, approximately $2 million and $1 million are included in discontinued operations for the years ended December 31, 2019, and 2018, respectively. Furthermore, of these annual pension and OPEB mark-to-market amounts, approximately $40 million, $47 million and $8 million were allocated to certain of the Transmission Companies and expected to be recovered through formula transmission rates, respectively. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions until 2022. Pension and OPEB costs are affected by employee demographics (including age, compensation levels and employment periods), the level of contributions made to the plans and earnings on plan assets. Pension and OPEB costs may also be affected by changes in key assumptions, including anticipated rates of return on plan assets, the discount rates and health care trend rates used in determining the projected benefit obligations for pension and OPEB costs. FirstEnergy uses a December 31 measurement date for its pension and OPEB plans. The fair value of the plan assets represents the actual market value as of the measurement date. FirstEnergy’s assumed rate of return on pension plan assets considers historical market returns and economic forecasts for the types of investments held by the pension trusts. In 2020, FirstEnergy’s qualified pension and OPEB plan assets experienced gains of $1,225 million or 14.7%, compared to gains of $1,492 million, or 20.2% in 2019, and losses of $371 million, or (4.0)% in 2018 and assumed a 7.50% rate of return on plan assets in 2020, 2019 and 2018, which generated $651 million, $569 million and $605 million of expected returns on plan assets, respectively. The expected return on pension and OPEB assets is based on the trusts’ asset allocation targets and the historical performance of risk-based and fixed income securities. The gains or losses generated as a result of the difference between expected and actual returns on plan assets will decrease or increase future net periodic pension and OPEB cost as the difference is recognized annually in the fourth quarter of each fiscal year or whenever a plan is determined to qualify for remeasurement. The expected return on plan assets for 2021 is 7.50%. During 2020, the Society of Actuaries published new mortality tables that include more current data than the RP-2014 tables as well as new improvement scales. An analysis of FirstEnergy pension and OPEB plan mortality data indicated the use of the Pri-2012 mortality table with projection scale MP-2020 was most appropriate. As such, the Pri-2012 mortality table with projection scale MP-2020 was utilized to determine the 2020 benefit cost and obligation as of December 31, 2020 for the FirstEnergy pension and OPEB plans. The impact of using the Pri-2012 mortality table with projection scale MP-2020 resulted in a decrease to the projected benefit obligation of approximately $74 million and $2 million for the pension and OPEB plans, respectively, and was included in the 2020 pension and OPEB mark-to-market adjustment. Effective in 2019, FirstEnergy changed the approach utilized to estimate the service cost and interest cost components of net periodic benefit cost for pension and OPEB plans. Historically, FirstEnergy estimated these components utilizing a single, weighted average discount rate derived from the yield curve used to measure the benefit obligation. FirstEnergy has elected to use a spot rate approach in the estimation of the components of benefit cost by applying specific spot rates along the full yield curve to the relevant projected cash flows, as this provides a better estimate of service and interest costs by improving the correlation between projected benefit cash flows to the corresponding spot yield curve rates. This election was considered a change in estimate and, accordingly, accounted for prospectively, and did not have a material impact on FirstEnergy's financial statements. 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. Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2020 2019 2020 2019 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 11,050 $ 9,462 $ 654 $ 608 Service cost 194 193 4 3 Interest cost 287 373 15 22 Plan participants’ contributions — — 4 4 Plan amendments 9 2 — — Special termination benefits — 14 — — Medicare retiree drug subsidy — — 1 1 Actuarial loss 1,011 1,535 41 64 Benefits paid (616) (529) (43) (48) Benefit obligation as of December 31 $ 11,935 $ 11,050 $ 676 $ 654 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 8,395 6,984 $ 458 408 Actual return on plan assets 1,165 1,419 60 73 Company contributions 24 521 23 21 Plan participants’ contributions — — 4 4 Benefits paid (616) (529) (43) (48) Fair value of plan assets as of December 31 $ 8,968 $ 8,395 $ 502 $ 458 Funded Status: Qualified plan $ (2,500) (2,203) $ — — Non-qualified plans (467) (452) — — Funded Status (Net liability as of December 31) $ (2,967) $ (2,655) $ (174) $ (196) Accumulated benefit obligation $ 11,376 $ 10,439 $ — $ — Amounts Recognized in AOCI: Prior service cost (credit) $ 12 $ 24 $ (39) $ (85) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 2.67 % 3.34 % 2.45 % 3.18 % Rate of compensation increase 4.10 % 4.10 % N/A N/A Cash balance weighted average interest crediting rate 2.57 % 2.57 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 6.0%-5.5% 6.0%-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2028 2028 Allocation of Plan Assets (as of December 31) Equity securities 23 % 29 % 55 % 54 % Fixed Income 35 % 36 % 28 % 30 % Hedge funds 7 % 9 % — % — % Insurance-linked securities 4 % 2 % — % — % Real estate funds 9 % 7 % — % — % Private equity funds 5 % 4 % — % — % Cash and short-term securities 17 % 13 % 17 % 16 % Total 100 % 100 % 100 % 100 % Components of Net Periodic Benefit Costs for the Years Ended December 31, Pension OPEB 2020 2019 2018 2020 2019 2018 (In millions) Service cost $ 194 $ 193 $ 224 $ 4 $ 3 $ 5 Interest cost 287 373 372 15 22 25 Expected return on plan assets (618) (540) (574) (33) (29) (31) Amortization of prior service costs (credits) (1) 12 7 7 (46) (36) (81) Special termination costs (2) — 14 31 — — 8 One-time termination benefits (3) 8 — — — — — Pension & OPEB mark-to-market 463 656 227 14 20 (82) Net periodic benefit costs (credits) $ 346 $ 703 $ 287 $ (46) $ (20) $ (156) (1) 2020 includes the acceleration of approximately $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. (2) 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. (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. Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1) Pension OPEB 2020 2019 2018 2020 2019 2018 Service cost weighted-average discount rate (2) 3.60%/3.24% 4.66 % 3.75 % 3.63%/3.29% 4.67 % 3.50 % Interest cost weighted-average discount rate (3) 3.27%/2.90% 4.37 % 3.75 % 2.71%/2.30% 3.89 % 3.50 % Expected long-term return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.10 % 4.10 % 4.20 % N/A N/A N/A (1) Excludes impact of pension and OPEB mark-to-market adjustment. (2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60% and 3.63% for pension and OPEB service cost, respectively. Discount rates were 3.24% and 3.29% for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020. (3) Weighted-average discount rates in effect from January 1, 2020, through February 26, 2020, were 3.27% and 2.71% for pension and OPEB interest cost, respectively. Discount rates were 2.90% and 2.30% for pension and OPEB interest cost, respectively, for the period February 27, 2020, through December 31, 2020. In selecting an assumed discount rate, FirstEnergy considers currently available rates of return on high-quality fixed income investments expected to be available during the period to maturity of the pension and OPEB obligations. The assumed rates of return on plan assets consider historical market returns and economic forecasts for the types of investments held by FirstEnergy’s pension trusts. The long-term rate of return is developed considering the portfolio’s asset allocation strategy. The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2020 and 2019. December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 1,493 $ — $ 1,493 17 % Equities 1,903 162 — 2,065 23 % Fixed income: Corporate bonds — 2,672 — 2,672 31 % Other (3) — 387 — 387 4 % Alternatives: Derivatives (13) — — (13) — % Total (1) $ 1,890 $ 4,714 $ — $ 6,604 75 % Private equity funds (2) 465 5 % Insurance-linked securities (2) 323 4 % Hedge funds (2) 645 7 % Real estate funds (2) 815 9 % Total Investments $ 8,852 100 % (1) Excludes $116 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. (3) Includes insurance annuities, bank loans and emerging markets debt. December 31, 2019 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 1,069 $ — $ 1,069 13 % Equities 1,532 828 — 2,360 29 % Fixed income: Corporate bonds — 2,064 — 2,064 25 % Other (3) — 880 — 880 11 % Alternatives: Derivatives (40) — — (40) — % Total (1) $ 1,492 $ 4,841 $ — $ 6,333 78 % Private equity funds (2) 342 4 % Insurance-linked securities (2) 186 2 % Hedge funds (3) 774 9 % Real estate funds (2) 584 7 % Total Investments $ 8,219 100 % (1) Excludes $176 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. (3) Includes insurance annuities, bank loans and emerging markets debt. As of December 31, 2020, and 2019, the OPEB trust investments measured at fair value were as follows: December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 84 $ — $ 84 17 % Equity investment: Domestic 283 — — 283 55 % Fixed income: Government bonds — 104 — 104 20 % Corporate bonds — 34 — 34 7 % Mortgage-backed securities (non-government) 7 — 7 1 % Total (1) $ 283 $ 229 $ — $ 512 100 % (1) Excludes $(10) million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2019 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 72 $ — $ 72 16 % Equity investment: Domestic 246 — — 246 54 % Fixed income: Government bonds — 100 — 100 22 % Corporate bonds — 34 — 34 7 % Mortgage-backed securities (non-government) — 5 — 5 1 % Total (1) $ 246 $ 211 $ — $ 457 100 % (1) Excludes $1 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. FirstEnergy follows a total return investment approach using a mix of equities, fixed income and other available investments while taking into account the pension plan liabilities to optimize the long-term return on plan assets for a prudent level of risk. Risk tolerance is established through careful consideration of plan liabilities, plan funded status and corporate financial condition. The investment portfolio contains a diversified blend of equity and fixed-income investments. Equity investments are diversified across U.S. and non-U.S. stocks, as well as growth, value, and small and large capitalization funds. Other assets such as real estate and private equity are used to enhance long-term returns while improving portfolio diversification. Derivatives may be used to gain market exposure in an efficient and timely manner; however, derivatives are not used to leverage the portfolio beyond the market value of the underlying investments. Investment risk is measured and monitored on a continuing basis through periodic investment portfolio reviews, annual liability measurements and periodic asset/liability studies. Investment markets experienced elevated market volatility during 2020 as a result of the U.S. general election and the COVID-19 pandemic. In order to reduce the effect of market volatility on the plan's funded status and to preserve capital gains experienced during the first half of 2020, approximately $1.4 billion of return-seeking assets were sold (including approximately $800 million of equity securities) during the third quarter of 2020. These assets are expected be reinvested in return seeking investments (including equity securities) during 2021, which will more consistently align the pension and OPEB trust portfolios to the company’s target asset allocations. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2020 and 2019 are shown in the following table: Target Asset Allocations 2020 2019 Equities 38 % 38 % Fixed income 30 % 30 % Hedge funds 8 % 8 % Real estate 10 % 10 % Alternative investments 8 % 8 % Cash 6 % 6 % 100 % 100 % Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2021 $ 579 $ 49 $ (1) 2022 583 47 (1) 2023 598 46 (1) 2024 601 45 (1) 2025 610 44 (1) Years 2026-2030 3,129 197 (2)

STOCK-BASED COMPENSATION PLANS

STOCK-BASED COMPENSATION PLANS	12 Months Ended
	Dec. 31, 2020
Share-based Payment Arrangement [Abstract]
STOCK-BASED COMPENSATION PLANS	STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2020, primarily in the form of restricted stock and performance-based restricted stock units. There are also awards currently outstanding issued through the ICP 2015 primarily in the form of restricted stock and performance-based restricted stock units. The ICP 2020 and ICP 2015 include shareholder authorization to each issue 10 million shares of common stock or their equivalent. As of December 31, 2020, approximately 13.7 million shares were available for future grants under the ICP 2020 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under ICP 2015. Shares not issued due to forfeitures or cancellations originally granted through the ICP 2015 may be added back to the ICP 2020. Shares granted under the ICP 2020 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from two to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled. Actual income tax benefits realized during the years ended December 31, 2020, 2019 and 2018, were $20 million, $24 million and $15 million, respectively. The income tax effects of awards are recognized in the income statement when the awards vest, are settled or are forfeited. Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2020, 2019 and 2018, are included in the following tables: For the Years Ended December 31, Stock-based Compensation Plan 2020 2019 2018 (In millions) Restricted Stock Units $ 22 $ 73 $ 102 Restricted Stock 1 1 1 401(k) Savings Plan 33 33 33 EDCP & DCPD (5) 9 7 Total $ 51 $ 116 $ 143 Stock-based compensation costs capitalized $ 26 $ 54 $ 60 There was no stock option expense for the years ended December 31, 2020, 2019 and 2018. Income tax benefits associated with stock-based compensation plan expense were $3 million, $10 million and $18 million for the years ended December 31, 2020, 2019 and 2018, respectively. Restricted Stock Units Beginning with the performance-based restricted stock units granted in 2015, two-thirds of each award will be paid in stock and one-third will be paid in cash. Restricted stock units payable in stock provide the participant the right to receive, at the end of the period of restriction, a number of shares of common stock equal to the number of stock units set forth in the agreement, subject to adjustment based on FirstEnergy's performance relative to financial and operational performance targets applicable to each award. The grant date fair value of the stock portion of the restricted stock unit award is measured based on the average of the high and low prices of FE common stock on the date of grant. Beginning with awards granted in 2018, restricted stock units include a performance metric consisting of a relative total shareholder return modifier utilizing the S&P 500 Utility Index as a comparator group. The estimated grant date fair value for these awards is calculated using the Monte Carlo simulation method . Restricted stock units payable in cash provide the participant the right to receive cash based on the number of stock units set forth in the agreement and value of the equivalent number of shares of FE common stock as of the vesting date. The cash portion of the restricted stock unit award is considered a liability award, which is remeasured each period based on FE's stock price and projected performance adjustments. The liability recorded for the portion of performance-based restricted stock units payable in cash in the future as of December 31, 2020, was $16 million. During 2020, approximately $27 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2020. The vesting period for the performance-based restricted stock unit awards granted in 2018, 2019 and 2020, were each 3 years. Dividend equivalents are received on the restricted stock units and are reinvested in additional restricted stock units and subject to the same performance conditions as the underlying award. Restricted stock unit activity for the year ended December 31, 2020, was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2020 2.6 $ 36.20 Granted in 2020 1.6 44.42 Forfeited in 2020 (0.6) 39.15 Vested in 2020 (1) (1.8) 44.40 Nonvested as of December 31, 2020 1.8 $ 40.25 (1) Excludes dividend equivalents of approximately 220 thousand shares earned during vesting period. The weighted-average fair value of awards granted in 2020, 2019 and 2018 was $44.42, $41.23 and $36.78 per share, respectively. For the years ended December 31, 2020, 2019, and 2018, the fair value of restricted stock units vested was $80 million, $91 million, and $62 million, respectively. As of December 31, 2020, there was approximately $23 million of total unrecognized compensation cost related to nonvested share-based compensation arrangements granted for restricted stock units, which is expected to be recognized over a period of approximately three years. Restricted Stock Certain employees receive awards of FE restricted stock (as opposed to "units" with the right to receive shares at the end of the restriction period) subject to restrictions that lapse over a defined period of time or upon achieving performance results. The fair value of restricted stock is measured based on the average of the high and low prices of FE common stock on the date of grant. Dividends are received on the restricted stock and are reinvested in additional shares of restricted stock, subject to the vesting conditions of the underlying award. Restricted stock activity for the year ended December 31, 2020, was not material. Stock Options Stock options have been granted to certain employees allowing them to purchase a specified number of common shares at a fixed exercise price over a defined period of time. Stock options generally expire ten years from the date of grant. There were no stock options granted in 2020. Stock option activity for the year ended December 31, 2020 was as follows: Stock Option Activity Number of Shares (in millions) Weighted Average Exercise Price (per share) Balance, January 1, 2020 (all options exercisable) 0.1 $ 37.75 Options exercised — — Options forfeited (0.1) 37.75 Balance, December 31, 2020 (all options exercisable) — $ — Approximately $23 million and $12 million of cash was received from the exercise of stock options in 2019 and 2018, respectively. 401(k) Savings Plan In 2020 and 2019, approximately 1 million shares of FE common stock, respectively, were issued and contributed to participants' accounts. EDCP Under the EDCP, certain employees can defer a portion of their compensation, including base salary, annual incentive awards and/or long-term incentive awards, into unfunded accounts. Annual incentive and long-term incentive awards may be deferred in FE stock accounts. Base salary and annual incentive awards may be deferred into a retirement cash account which earns interest. Dividends are calculated quarterly on stock units outstanding and are credited in the form of additional stock units. The form of payout as stock or cash vary depending upon the form of the award, the duration of the deferral and other factors. Certain types of deferrals such as dividend equivalent units, annual incentive awards, and performance share awards are required to be paid in cash. Until 2015, payouts of the stock accounts typically occurred three years from the date of deferral, although participants could have elected to defer their shares into a retirement stock account that would pay out in cash upon retirement. In 2015, FirstEnergy amended the EDCP to eliminate the right to receive deferred shares after three years, effective for deferrals made on or after November 1, 2015. Awards deferred into a retirement stock account will pay out in cash upon separation from service, death or disability. Interest accrues on the cash allocated to the retirement cash account and the balance will pay out in cash over a time period as elected by the participant. DCPD Under the DCPD, members of FE's Board of Directors can elect to defer all or a portion of their equity retainers to a deferred stock account and their cash retainers to deferred stock or deferred cash accounts. The net liability recognized for DCPD of approximately $7 million and $9 million as of December 31, 2020 and December 31, 2019, respectively, is included in the caption “Retirement benefits,” on the Consolidated Balance Sheets.

TAXES

TAXES	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
TAXES	TAXES FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FE that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. Effective as of their emergence from bankruptcy, February 27, 2020, the FES Debtors no longer are part of FirstEnergy's consolidated federal income tax group or the intercompany income tax allocation agreement. 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. On March 27, 2020, President Trump signed into law the CARES Act, an economic stimulus package in response to the COVID-19 pandemic containing 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 applied for refund of its remaining approximately $18 million refundable AMT credits. FirstEnergy does not expect to generate additional income tax refunds from the carryback of NOLs and expects interest to be fully deductible in the 2020 consolidated federal income tax return and going forward. 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 December 27, 2020, President Trump signed into law the Consolidated Appropriations Act, 2021, an additional stimulus package providing financial relief for individuals and small businesses. The Appropriations Act contains a variety of tax provisions, including full expensing of business meals in 2021 and 2022, extensions of various energy tax incentives (including the ITC), and expansion of the employee retention tax credit. FirstEnergy does not currently expect the Appropriations Act to have a material tax impact. 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. After reviewing the final regulations, FirstEnergy recorded a true-up to prior years’ reserve estimates during the third quarter of 2020, which did not have a material impact to FirstEnergy’s income statement. On January 6, 2021, the IRS released an additional set of final regulations under Section 163(j) primarily addressing partnership, real estate, and certain controlled foreign corporation issues, which do not materially impact FirstEnergy. For the Years Ended December 31, INCOME TAXES (1) 2020 2019 2018 (In millions) Currently payable (receivable)- Federal (2) $ (14) $ (16) $ (16) State (3) 21 24 17 7 8 1 Deferred, net- Federal (4) 171 150 252 State (5) (38) 60 243 133 210 495 Investment tax credit amortization (14) (5) (6) Total income taxes $ 126 $ 213 $ 490 (1) Income Taxes on Income from Continuing Operations. (2) Excludes $6 million of federal tax expense associated with discontinued operations for the year ended December 31, 2020. (3) Excludes $1 million of state tax expense associated with discontinued operations for the year ended December 31, 2018. (4) Excludes $66 million, $9 million and $1.3 billion of federal tax benefit associated with discontinued operations for the years ended December 31, 2020, 2019 and 2018, respectively. (5) Excludes $1 million, $4 million and $12 million of state tax expense associated with discontinued operations for the years ended December 31, 2020, 2019 and 2018, respectively. FirstEnergy tax rates are affected by 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. The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2020, 2019 and 2018: For the Years Ended December 31, 2020 2019 2018 (In millions) Income from Continuing Operations, before income taxes $ 1,129 $ 1,117 $ 1,512 Federal income tax expense at statutory rate (21%) $ 237 $ 235 $ 318 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 75 96 90 AFUDC equity and other flow-through (38) (36) (31) Amortization of investment tax credits (14) (5) (5) Remeasurement of deferred taxes — — 24 WV unitary group remeasurement — — 126 Excess deferred tax amortization due to the Tax Act (56) (74) (60) TMI-2 reversal of tax regulatory liabilities (40) — — Uncertain tax positions (1) (11) 2 Valuation allowances (49) 5 21 Other, net 12 3 5 Total income taxes $ 126 $ 213 $ 490 Effective income tax rate 11.2 % 19.1 % 32.4 % FirstEnergy's effective tax rate on continuing operations for 2020 and 2019 was 11.2% and 19.1%, 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, a $10 million benefit from accelerated amortization of certain investment tax credits in the second quarter of 2020, and a $40 million benefit related to reversals of certain tax regulatory liabilities resulting from the transfer of TMI-2. See Note 3, “Discontinued Operations,” for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations. Accumulated deferred income taxes as of December 31, 2020 and 2019, are as follows: As of December 31, 2020 2019 (In millions) Property basis differences $ 5,396 $ 5,037 Pension and OPEB (769) (698) TMI-2 nuclear decommissioning — 89 AROs (28) (226) Regulatory asset/liability 440 445 Deferred compensation (165) (154) Estimated worthless stock deduction — (1,007) Loss carryforwards and AMT credits (1,995) (836) Valuation reserve 496 441 All other (280) (242) Net deferred income tax liability $ 3,095 $ 2,849 FirstEnergy has recorded as deferred income tax assets the effect of Federal NOLs and tax credits that will more likely than not be realized through future operations and through the reversal of existing temporary differences. As of December 31, 2020, FirstEnergy's loss carryforwards primarily consisted of $6.8 billion ($1.4 billion, net of tax) of Federal NOL carryforwards that will begin to expire in 2031. The table below summarizes pre-tax NOL carryforwards and their respective anticipated expirations for state and local income tax purposes of approximately $12.4 billion ($540 million, net of tax) for FirstEnergy, of which approximately $3.8 billion ($155 million, net of tax) is expected to be utilized based on current estimates and assumptions. The ultimate utilization of these NOLs may be impacted by statutory limitations on the use of NOLs imposed by state and local tax jurisdictions, changes in statutory tax rates, and changes in business which, among other things, impact both future profitability and the manner in which future taxable income is apportioned to various state and local tax jurisdictions. Expiration Period State Local (In millions) 2021-2025 $ 2,253 $ 4,353 2026-2030 1,447 — 2031-2035 1,152 — 2036-2040 1,087 — Indefinite 2,091 — $ 8,030 $ 4,353 The following table summarizes the changes in valuation allowances on federal, state and local DTAs related to disallowed interest and certain employee remuneration, in addition to state and local NOLs discussed above for the years ended December 31, 2020, 2019 and 2018: (In millions) 2020 2019 2018 Beginning of year balance $ 441 $ 394 $ 312 Charged to income 55 47 82 Charged to other accounts — — — Write-offs — — — End of year balance $ 496 $ 441 $ 394 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute are utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. As of December 31, 2020, and 2019, FirstEnergy's total unrecognized income tax benefits were approximately $139 million and $164 million, respectively. The change in unrecognized income tax benefits from the prior year is primarily attributable to a decrease of approximately $21 million for reserves on the estimated worthless stock deduction (see Note 3, "Discontinued Operations," for further discussion), as well as decreases of $2 million for an effective settlement with certain state taxing authorities and $2 million due to the lapse in statute in certain state taxing jurisdictions. If ultimately recognized in future years, approximately $121 million of unrecognized income tax benefits would impact the effective tax rate. As of December 31, 2020, it is reasonably possible that approximately $57 million of unrecognized tax benefits may be resolved during 2021 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $55 million would affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2020, 2019 and 2018: (In millions) Balance, January 1, 2018 $ 80 Current year increases 125 Prior year decreases (45) Decrease for lapse in statute (2) Balance, December 31, 2018 $ 158 Current year increases 22 Prior year decreases (12) Decrease for lapse in statute (4) Balance, December 31, 2019 $ 164 Current year increases 7 Prior years decreases (28) Decrease for lapse in statute (2) Effectively settled with taxing authorities (2) Balance, December 31, 2020 $ 139 FirstEnergy recognizes interest expense or income and penalties related to uncertain tax positions in income taxes by applying the applicable statutory interest rate to the difference between the tax position recognized and the amount previously taken, or expected to be taken, on the tax return. FirstEnergy's recognition of net interest associated with unrecognized tax benefits in 2020, 2019 and 2018, was not material. For the years ended December 31, 2020 and 2019, the cumulative net interest payable recorded by FirstEnergy was not material. FirstEnergy has tax returns that are under review at the audit or appeals level by the IRS and state taxing authorities. Tax years 2018 and 2019 are currently under review by the IRS. FirstEnergy's tax returns for some state jurisdictions are open from 2009-2019. General Taxes General tax expense for the years ended December 31, 2020, 2019 and 2018, recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2020 2019 2018 (In millions) KWH excise $ 183 $ 191 $ 198 State gross receipts 182 185 192 Real and personal property 541 504 478 Social security and unemployment 112 100 103 Other 28 28 22 Total general taxes $ 1,046 $ 1,008 $ 993

LEASES

LEASES	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
LEASES	LEASES FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor. FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material. Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of December 31, 2020, the maximum potential loss for these lease agreements at the end of the lease term is approximately $16 million. Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows: For the Year Ended December 31, 2020 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 35 $ 8 $ 17 $ 60 Finance lease costs: Amortization of right-of-use assets 14 — 1 15 Interest on lease liabilities 2 3 — 5 Total finance lease cost 16 3 1 20 Total lease cost $ 51 $ 11 $ 18 $ 80 (1) Includes $17 million of short-term lease costs. For the Year Ended December 31, 2019 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 28 $ 9 $ 12 $ 49 Finance lease costs: Amortization of right-of-use assets 15 1 1 17 Interest on lease liabilities 3 3 — 6 Total finance lease cost 18 4 1 23 Total lease cost $ 46 $ 13 $ 13 $ 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: For the Years Ended, (In millions) December 31, 2020 December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 44 $ 29 Operating cash flows from finance leases 4 5 Finance cash flows from finance leases 15 25 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 67 $ 83 Finance leases — 3 Lease terms and discount rates were as follows: As of December 31, 2020 As of December 31, 2019 Weighted-average remaining lease terms (years) Operating leases 8.55 9.42 Finance leases 7.74 4.62 Weighted-average discount rate (1) Operating leases 4.21 % 4.51 % Finance leases 11.58 % 10.45 % (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. Supplemental balance sheet information related to leases was as follows: As of December 31, (In millions) Financial Statement Line Item 2020 2019 Assets Operating lease (1) Deferred charges and other assets $ 265 $ 231 Finance lease (2) Property, plant and equipment 57 73 Total leased assets $ 322 $ 304 Liabilities Current: Operating Other current liabilities $ 42 $ 32 Finance Currently payable long-term debt 14 15 Noncurrent: Operating Other noncurrent liabilities 263 241 Finance Long-term debt and other long-term obligations 31 45 Total leased liabilities $ 350 $ 333 (1) Operating lease assets are recorded net of accumulated amortization of $51 million and $23 million as of December 31, 2020 and 2019, respectively. (2) Finance lease assets are recorded net of accumulated amortization of $96 million and $90 million as of December 31, 2020 and 2019, respectively. Maturities of lease liabilities as of December 31, 2020, were as follows: (In millions) Operating Leases Finance Leases Total 2021 $ 50 $ 18 $ 68 2022 49 15 64 2023 46 8 54 2024 38 4 42 2025 36 4 40 Thereafter 147 12 159 Total lease payments (1) 366 61 427 Less imputed interest 61 16 77 Total net present value $ 305 $ 45 $ 350 (1) Operating lease payments for certain leases are offset by sublease receipts of $11 million over 12 years. As of December 31, 2020, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $14 million. These leases are expected to commence within the next 18 months with lease terms of 5 to 10 years.
LEASES	LEASES FirstEnergy primarily leases vehicles as well as building space, office equipment, and other property and equipment under cancellable and non-cancelable leases. FirstEnergy does not have any material leases in which it is the lessor. FirstEnergy adopted ASU 2016-02, “Leases (Topic 842)” on January 1, 2019, and elected a number of transitional practical expedients provided within the standard. These included a “package of three” expedients that must be taken together and allowed entities to: (1) not reassess whether existing contracts contain leases, (2) carryforward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases. In addition, FirstEnergy elected the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. Adoption of the standard on January 1, 2019, did not result in a material cumulative effect adjustment upon adoption. FirstEnergy did not evaluate land easements under the new guidance as they were not previously accounted for as leases. FirstEnergy also elected not to separate lease components from non-lease components as non-lease components were not material. Leases with an initial term of 12 months or less are recognized as lease expense on a straight-line basis over the lease term and not recorded on the balance sheet. Most leases include one or more options to renew, with renewal terms that can extend the lease term from 1 to 40 years, and certain leases include options to terminate. The exercise of lease renewal options is at FirstEnergy’s sole discretion. Renewal options are included within the lease liability if they are reasonably certain based on various factors relative to the contract. Certain leases also include options to purchase the leased property. The depreciable life of leased assets and leasehold improvements are limited by the expected lease term unless there is a transfer of title or purchase option reasonably certain of exercise. FirstEnergy’s lease agreements do not contain any material restrictive covenants. For vehicles leased under master lease agreements, the lessor is guaranteed a residual value up to a stated percentage of the equipment cost at the end of the lease term. As of December 31, 2020, the maximum potential loss for these lease agreements at the end of the lease term is approximately $16 million. Finance leases for assets used in regulated operations are recognized in FirstEnergy’s Consolidated Statements of Income such that amortization of the right-of-use asset and interest on lease liabilities equals the expense allowed for ratemaking purposes. Finance leases for regulated and non-regulated operations are accounted for as if the assets were owned and financed, with associated expense recognized in Interest expense and Provision for depreciation on FirstEnergy’s Consolidated Statements of Income, while all operating lease expenses are recognized in Other operating expense. The components of lease expense were as follows: For the Year Ended December 31, 2020 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 35 $ 8 $ 17 $ 60 Finance lease costs: Amortization of right-of-use assets 14 — 1 15 Interest on lease liabilities 2 3 — 5 Total finance lease cost 16 3 1 20 Total lease cost $ 51 $ 11 $ 18 $ 80 (1) Includes $17 million of short-term lease costs. For the Year Ended December 31, 2019 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 28 $ 9 $ 12 $ 49 Finance lease costs: Amortization of right-of-use assets 15 1 1 17 Interest on lease liabilities 3 3 — 6 Total finance lease cost 18 4 1 23 Total lease cost $ 46 $ 13 $ 13 $ 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: For the Years Ended, (In millions) December 31, 2020 December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 44 $ 29 Operating cash flows from finance leases 4 5 Finance cash flows from finance leases 15 25 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 67 $ 83 Finance leases — 3 Lease terms and discount rates were as follows: As of December 31, 2020 As of December 31, 2019 Weighted-average remaining lease terms (years) Operating leases 8.55 9.42 Finance leases 7.74 4.62 Weighted-average discount rate (1) Operating leases 4.21 % 4.51 % Finance leases 11.58 % 10.45 % (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. Supplemental balance sheet information related to leases was as follows: As of December 31, (In millions) Financial Statement Line Item 2020 2019 Assets Operating lease (1) Deferred charges and other assets $ 265 $ 231 Finance lease (2) Property, plant and equipment 57 73 Total leased assets $ 322 $ 304 Liabilities Current: Operating Other current liabilities $ 42 $ 32 Finance Currently payable long-term debt 14 15 Noncurrent: Operating Other noncurrent liabilities 263 241 Finance Long-term debt and other long-term obligations 31 45 Total leased liabilities $ 350 $ 333 (1) Operating lease assets are recorded net of accumulated amortization of $51 million and $23 million as of December 31, 2020 and 2019, respectively. (2) Finance lease assets are recorded net of accumulated amortization of $96 million and $90 million as of December 31, 2020 and 2019, respectively. Maturities of lease liabilities as of December 31, 2020, were as follows: (In millions) Operating Leases Finance Leases Total 2021 $ 50 $ 18 $ 68 2022 49 15 64 2023 46 8 54 2024 38 4 42 2025 36 4 40 Thereafter 147 12 159 Total lease payments (1) 366 61 427 Less imputed interest 61 16 77 Total net present value $ 305 $ 45 $ 350 (1) Operating lease payments for certain leases are offset by sublease receipts of $11 million over 12 years. As of December 31, 2020, additional operating leases agreements, primarily for vehicles, that have not yet commenced are $14 million. These leases are expected to commence within the next 18 months with lease terms of 5 to 10 years.

INTANGIBLE ASSETS

INTANGIBLE ASSETS	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS As of December 31, 2020, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheets include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2020 2021 2022 2023 2024 2025 Thereafter NUG contracts (1) $ 124 $ 51 $ 73 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 48 Coal contracts (2) 102 102 — 2 — — — — — — $ 226 $ 153 $ 73 $ 7 $ 5 $ 5 $ 5 $ 5 $ 5 $ 48 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings.

FAIR VALUE MEASUREMENTS

FAIR VALUE MEASUREMENTS	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS RECURRING FAIR VALUE MEASUREMENTS Authoritative accounting guidance establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. This hierarchy gives the highest priority to Level 1 measurements and the lowest priority to Level 3 measurements. The three levels of the fair value hierarchy and a description of the valuation techniques are as follows: Level 1 - Quoted prices for identical instruments in active market Level 2 - Quoted prices for similar instruments in active market - Quoted prices for identical or similar instruments in markets that are not active - Model-derived valuations for which all significant inputs are observable market data Models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 3 - Valuation inputs are unobservable and significant to the fair value measurement FirstEnergy produces a long-term power and capacity price forecast annually with periodic updates as market conditions change. When underlying prices are not observable, prices from the long-term price forecast are used to measure fair value. FTRs are financial instruments that entitle the holder to a stream of revenues (or charges) based on the hourly day-ahead congestion price differences across transmission paths. FTRs are acquired by FirstEnergy in the annual, monthly and long-term PJM auctions and are initially recorded using the auction clearing price less cost. After initial recognition, FTRs' carrying values are periodically adjusted to fair value using a mark-to-model methodology, which approximates market. The primary inputs into the model, which are generally less observable than objective sources, are the most recent PJM auction clearing prices and the FTRs' remaining hours. The model calculates the fair value by multiplying the most recent auction clearing price by the remaining FTR hours less the prorated FTR cost. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. NUG contracts represent PPAs with third-party non-utility generators that are transacted to satisfy certain obligations under PURPA. NUG contract carrying values are recorded at fair value and adjusted periodically using a mark-to-model methodology, which approximates market. The primary unobservable inputs into the model are regional power prices and generation MWH. Pricing for the NUG contracts is a combination of market prices for the current year and next two years based on observable data and internal models using historical trends and market data for the remaining years under contract. The internal models use forecasted energy purchase prices as an input when prices are not defined by the contract. Forecasted market prices are based on Intercontinental Exchange, Inc. quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. For investments reported at NAV where there is no readily determinable fair value, a practical expedient is available that allows the NAV to approximate fair value. Investments that use NAV as a practical expedient are excluded from the requirement to be categorized within the fair value hierarchy tables. Instead, these investments are reported outside of the fair value hierarchy tables to assist in the reconciliation of investment balances reported in the tables to the balance sheet. FirstEnergy has elected the NAV practical expedient for investments in private equity funds, insurance-linked securities, hedge funds (absolute return) and real estate funds held within the pension plan. See Note 5, "Pension And Other Post-Employment Benefits" for the pension financial assets accounted for at fair value by level within the fair value hierarchy. 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 December 31, 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. The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: December 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ — $ — $ — $ — $ 135 $ — $ 135 Derivative assets FTRs (1) — — 3 3 — — 4 4 Equity securities 2 — — 2 2 — — 2 U.S. state debt securities — 276 — 276 — 271 — 271 Other (2) 1,734 41 — 1,775 627 789 — 1,416 Total assets $ 1,736 $ 317 $ 3 $ 2,056 $ 629 $ 1,195 $ 4 $ 1,828 Liabilities Derivative liabilities FTRs (1) $ — $ — $ — $ — $ — $ — $ (1) $ (1) Derivative liabilities NUG contracts (1) — — — — — — (16) (16) Total liabilities $ — $ — $ — $ — $ — $ — $ (17) $ (17) Net assets (liabilities) (3) $ 1,736 $ 317 $ 3 $ 2,056 $ 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 $1 million and $(16) million as of December 31, 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 years ended December 31, 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 gain (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 gain (loss) — (3) (3) (3) — (3) Purchases — — — 7 (2) 5 Settlements — 19 19 (5) 3 (2) December 31, 2020 Balance $ — $ — $ — $ 3 $ — $ 3 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs contracts that are classified as Level 3 in the fair value hierarchy for the year ended December 31, 2020: Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 3 Model RTO auction clearing prices $0.40 to $2.20 $1.10 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 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. 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. With the receipt of all required regulatory approvals, the transaction was consummated, including the transfer of external trusts for the decommissioning and environmental remediation of TMI-2, on December 18, 2020. Please see Note 15, "Commitments, Guarantees and Contingencies," for further information. Nuclear Decommissioning and Nuclear Fuel Disposal Trusts JCP&L holds debt securities within the nuclear fuel disposal trust, which are classified as AFS securities, recognized at fair market value. The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2020 and December 31, 2019: December 31, 2020 (1) December 31, 2019 (2) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (3) (In millions) Debt securities $ 275 $ 7 $ (6) $ 276 $ 403 $ 9 $ (11) $ 401 (1) Excludes short-term cash investments of $9 million. (2) Excludes short-term cash investments of $751 million, of which $747 million is classified as held for sale. (3) Includes $135 million classified as held for sale as of December 31, 2019. 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 years ended December 31, 2020, 2019 and 2018, were as follows: For the Years Ended December 31, 2020 2019 (1) 2018 (1) (In millions) Sale Proceeds $ 186 $ 1,637 $ 800 Realized Gains 12 98 41 Realized Losses (8) (31) (48) Interest and Dividend Income 22 38 41 (1) Excludes amounts classified as discontinued operations. 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 $322 million a nd $299 million as of December 31, 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, unamortized fair value adjustments, premiums and discounts as of December 31, 2020 and 2019: As of December 31, 2020 2019 (In millions) Carrying Value (1) $ 22,377 $ 20,066 Fair Value 25,465 22,928 ( 1) The carrying value as of December 31, 2020, includes $3,425 million of debt issuances and $1,114 million of redemptions that occurred during 2020.

CAPITALIZATION

CAPITALIZATION	12 Months Ended
	Dec. 31, 2020
Capitalization, Long-term Debt and Equity [Abstract]
CAPITALIZATION	CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2020, FirstEnergy had an accumulated deficit of $2.9 billion. Dividends declared in 2020 and 2019 were $1.56 and $1.53 per share, respectively. Dividends of $0.39 per share and $0.38 per share were paid in the first, second, third and fourth quarters in 2020 and 2019, respectively. On December 15, 2020, the Board of Directors declared a quarterly dividend of $0.39 per share to be paid from OPIC in the first quarter of 2021. The amount and timing of all dividend declarations are subject to the discretion of the Board of Directors and its consideration of business conditions, results of operations, financial condition and other factors. In addition to paying dividends from retained earnings, OE, CEI, TE, Penn, JCP&L, ME and PN have authorization from FERC to pay cash dividends to FirstEnergy from paid-in capital accounts, as long as their FERC-defined equity-to-total-capitalization ratio remains above 35%. In addition, AGC has authorization from FERC to pay cash dividends to its parent from paid-in capital accounts, as long as its FERC-defined equity-to-total-capitalization ratio remains above 45%. The articles of incorporation, indentures, regulatory limitations and various other agreements relating to the long-term debt of certain FirstEnergy subsidiaries contain provisions that could further restrict the payment of dividends on their common stock. None of these provisions materially restricted FirstEnergy’s subsidiaries’ abilities to pay cash dividends to FE as of December 31, 2020. Common Stock Issuance FE issued approximately 2 million shares of common stock in 2020, 3 million shares of common stock in 2019 and 3.2 million shares of common stock in 2018 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. Additionally, on January 22, 2018, FE entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of common shares and $847 million of OPIC). Please see below for information on preferred stock converted into shares of common stock during 2018 and 2019. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2020, as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FE 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par As of December 31, 2020 and 2019, there were no preferred stock or preference stock outstanding. Preferred Stock Issuance In January of 2018, FE entered into a Preferred Stock Purchase Agreement for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). During 2018, 911,411 shares of preferred stock were converted into 33,238,910 shares of common stock at the option of the preferred stockholders. During 2019, the remaining 704,589 shares of preferred stock were converted into 25,696,168 shares of common stock at the option of the preferred stockholders. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2020 and 2019: As of December 31, 2020 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2020 2019 FMBs and secured notes - fixed rate 2021-2059 2.670% - 8.250% $ 4,802 $ 4,741 Unsecured notes - fixed rate 2022-2050 1.600% - 7.375% 17,575 14,575 Unsecured notes - variable rate — 750 Finance lease obligations 45 60 Unamortized debt discounts (34) (33) Unamortized debt issuance costs (118) (103) Unamortized fair value adjustments 7 8 Currently payable long-term debt (146) (380) Total long-term debt and other long-term obligations $ 22,131 $ 19,618 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 unsecured notes due 2035. Proceeds from the issuance of the 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 unsecured notes due 2032 and $125 million of 3.71% senior unsecured notes due 2035. Proceeds of the issuance of the 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. 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 notes were used to refinance existing short-term borrowings, to fund capital expenditures, and for general corporate purposes. See Note 8, "Leases," for additional information related to finance leases. Securitized Bonds Environmental Control Bonds The consolidated financial statements of FirstEnergy include environmental control bonds issued by two bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE. Proceeds from the bonds were used to construct environmental control facilities. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2020 and 2019, $300 million and $333 million of environmental control bonds were outstanding, respectively. Transition Bonds In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of December 31, 2020 and 2019, $9 million and $25 million of the transition bonds were outstanding, respectively. Phase-In Recovery Bonds In June 2013, the SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2020 and 2019, $245 million and $268 million of the phase-in recovery bonds were outstanding, respectively. Other Long-term Debt The Ohio Companies and Penn each have a first mortgage indenture under which they can issue FMBs secured by a direct first mortgage lien on substantially all of their property and franchises, other than specifically excepted property. Based on the amount of FMBs authenticated by the respective mortgage bond trustees as of December 31, 2020, the sinking fund requirement for all FMBs issued under the various mortgage indentures was zero. The following table presents scheduled debt repayments for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2020. PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year (In millions) 2021 $ 132 2022 $ 1,143 2023 $ 1,194 2024 $ 1,246 2025 $ 2,023 Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. As of December 31, 2020, MP has a $74 million PCRB classified as current portion of long-term debt, which the debt holders may exercise their right to tender in 2021. Debt Covenant Default Provisions FirstEnergy has various debt covenants under certain financing arrangements, including its revolving credit facilities and term loans. The most restrictive of the debt covenants relate to the nonpayment of interest and/or principal on such debt and the maintenance of certain financial ratios. The failure by FirstEnergy to comply with the covenants contained in its financing arrangements could result in an event of default, which may have an adverse effect on its financial condition. As of December 31, 2020, FirstEnergy remains in compliance with all debt covenant provisions.

SHORT-TERM BORROWINGS AND BANK

SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT	12 Months Ended
	Dec. 31, 2020
Debt Disclosure [Abstract]
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT	SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FirstEnergy had $2.2 billion and $1.0 billion of short-term borrowings as of December 31, 2020 and 2019, respectively. 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 sublimits 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 sublimits for each borrower including FE's transmission subsidiaries. On November 17, 2020, FE and the Utilities and FET and certain of its subsidiaries entered into amendments to the FE credit facility and the FET credit facility, respectively. The amendments provide for modifications and/or waivers of: (i) certain representations and warranties, and (ii) certain affirmative and negative covenants, contained therein, which allowed FirstEnergy to regain compliance with such provisions. In addition, among other things, the amendment to the FE credit facility reduces the sublimit applicable to FE to $1.5 billion, and the amendments increased certain tiers of pricing applicable to borrowings under the credit facilities. On November 23, 2020, FE and its regulated distribution subsidiaries, JCP&L, ME, Penn, TE and WP, borrowed $950 million in the aggregate under the FE Revolving Facility, bringing the outstanding principal balance under the FE Revolving Facility to $1.2 billion, with $1.3 billion of remaining availability under the FE Revolving Facility. On November 23, 2020, FET and its regulated transmission subsidiary, ATSI, borrowed $1 billion in the aggregate under the FET Revolving Facility, bringing the outstanding principal balance under the FET Revolving Facility to $1 billion, with no remaining availability under the FET Revolving Facility. FE, FET and certain of their respective subsidiaries increased their borrowings under the Revolving Facilities as a proactive measure to increase their respective cash positions and preserve financial flexibility. As of December 31, 2020, available liquidity under the FE revolving credit facility was $1,296 million (reflecting $4 million of LOCs issued under various terms) and there was no available liquidity under the FET revolving credit facility. 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. Subject to each borrower’s sublimit, $250 million of the FE credit facility and $100 million of the FET credit facility, 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 sublimit. 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 December 31, 2020, the borrowers were in compliance with the applicable debt-to-total-capitalization ratio covenants in each case as defined under the respective Facilities. 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 2020 was 0.89% per annum for the regulated companies’ money pool and 1.19% per annum for the unregulated companies’ money pool. Weighted Average Interest Rates

ASSET RETIREMENT OBLIGATIONS

ASSET RETIREMENT OBLIGATIONS	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, including reclamation of sludge disposal ponds, closure of coal ash disposal sites, underground and above-ground storage tanks and wastewater treatment lagoons. In addition, FirstEnergy has recognized conditional retirement obligations, primarily for asbestos remediation. 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. Please see Note 15, "Commitments, Guarantees and Contingencies," for further information. The following table summarizes the changes to the ARO balances during 2020 and 2019: ARO Reconciliation (In millions) Balance, January 1, 2019 $ 812 Liabilities settled (2) Accretion 46 Balance, December 31, 2019 (1) $ 856 Liabilities settled (2) (744) Accretion 47 Balance, December 31, 2020 $ 159 (1) Includes $691 million related to TMI-2 classified as held for sale for the year ended December 31, 2019. (2) Includes $726 million related to the closing of the asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions , LLC, concerning the transfer and dismantlement of TMI-2. See Note 15, "Commitments, Guarantees and Contingencies," for further information.

REGULATORY MATTERS

REGULATORY MATTERS	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in New Jersey by the NJBPU, in Ohio by the PUCO, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia, ATSI in Ohio, and the Transmission Companies in Pennsylvania are subject to certain regulations of the VSCC, PUCO and PPUC, respectively. 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. The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2020: Company Rates Effective Allowed Debt/Equity Allowed ROE CEI May 2009 51% / 49% 10.5% ME (1) January 2017 48.8% / 51.2% Settled (2) MP February 2015 54% / 46% Settled (2) JCP&L (3) January 2017 55% / 45% 9.6% OE January 2009 51% / 49% 10.5% PE (West Virginia) February 2015 54% / 46% Settled (2) PE (Maryland) March 2019 47% / 53% 9.65% PN (1) January 2017 47.4% / 52.6% Settled (2) Penn (1) January 2017 49.9% / 50.1% Settled (2) TE January 2009 51% / 49% 10.5% WP (1) January 2017 49.7% / 50.3% Settled (2) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. (3) On October 28, 2020, the NJBPU approved JCP&L's distribution rate case settlement with an allowed ROE of 9.6% and a 48.56% debt / 51.44% equity capital structure. Rates are effective for customers on November 1, 2021, but beginning January 1, 2021, JCP&L will offset the impact to customers' bills by amortizing an $86 million regulatory liability. 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 through an annually reconciled surcharge, with most 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 September 1, 2020, PE filed its proposed plan for the 2021-2023 EmPOWER Maryland program cycle. The new plan largely continues PE’s existing programs and is estimated to cost approximately $148 million over the three-year period. The MDPSC approved the plan on December 18, 2020. 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. On September 22, 2020, PE filed its depreciation study reflecting a depreciation expense of $36.2 million, which represented a slight increase, and as a result, is seeking difference in depreciation be deferred for future recovery in PE’s next base rate case. The MDPSC has set the matter for hearing and delegated it to a public utility law judge. On November 6, 2020, an order was issued scheduling evidentiary hearings in April 2021. On January 29, 2021, the Maryland Office of People's Counsel filed testimony recommending a reduction in depreciation expense of $10.8 million, and the staff of the MDPSC filed testimony recommending a reduction of $9.6 million. PE's rebuttal testimony is due on March 2, 2021. 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 expense, incurred from the date of the Governor’s order (or earlier if the utility could show that the expenses related to suspension of service terminations). 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. The MDPSC subsequently issued orders allowing Maryland electric and gas utilities to resume residential service terminations for non-payment on November 15, 2020, subject to various restrictions, and clarifying that utilities could resume charging late fees on October 1, 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. Oral Argument is scheduled for March 10, 2021. 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. As further discussed below, JCP&L will recover the IIP capital investments, which totaled $97 million, as part of its distribution base rate case. 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. The NJBPU issued orders suspending JCP&L’s proposed rates until November 19, 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 October 16, 2020, the parties submitted a stipulation of settlement to the administrative law judge, providing for, among other things, a $94 million annual base distribution revenues increase for JCP&L based on an ROE of 9.6%, which will become effective for customers on November 1, 2021. Until the rates become effective, and starting on January 1, 2021, JCP&L is permitted to amortize an existing regulatory liability totaling approximately $86 million to offset the base rate increase that otherwise would have occurred in this period. The parties also agreed that the actual net gain from the sale of JCP&L’s interest in the Yards Creek pumped-storage hydro generation facility in New Jersey (210 MWs), as further discussed below, shall be applied to reduce JCP&L’s existing regulatory asset for previously deferred storm costs. Lastly, the parties agreed that $95.1 million of Reliability Plus capital investment for projects through December 31, 2020 is included in rate base effective December 31, 2020, with a final prudence review of only those capital investment projects from July 1, 2020 through December 31, 2020 to occur in January 2021. On October 22, 2020, the administrative law judge entered an initial decision adopting the settlement. On October 28, 2020, the NJBPU approved the settlement and directed an upcoming management audit for JCP&L. On January 4, 2021, JCP&L submitted its review of storm costs as required under the stipulation of settlement. On January 15, 2021, JCP&L filed a written report for its Reliability Plus projects placed in service from July 1, 2020 through December 31, 2020, also as required under the stipulation of settlement. 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. Subject to terms and conditions of the agreement, the base purchase price is $155 million. On July 31, 2020, FERC approved the transfer of JCP&L’s interest in the hydroelectric operating license. On October 8, 2020, FERC issued an order authorizing the transfer of JCP&L’s ownership interest in the hydroelectric facilities. On October 28, 2020, the NJBPU approved the sale of Yards Creek. Completion of the transaction is subject to several closing conditions; there can be no assurance that all closing conditions will be satisfied or that the transaction will be consummated. JCP&L currently anticipates closing of the transaction to occur during the first quarter of 2021. Assets held for sale on FirstEnergy’s Consolidated Balance Sheets associated with the transaction consist of property, plant and equipment of $45 million, which is included in the regulated distribution segment. On August 27, 2020, JCP&L filed an AMI Program with the NJBPU, which proposes the deployment of approximately 1.2 million advanced meters over a three-year period beginning on January 1, 2023, at a total cost of approximately $418 million, including the pre-deployment phase. The 3-year deployment is part of the 20-year AMI Program that is expected to cost a total of approximately $732 million and proposes a cost recovery mechanism through a separate AMI tariff rider. On January 13, 2021, a procedural schedule was established, which includes evidentiary hearings the week of May 24, 2021. 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. On September 25, 2020, JCP&L filed its energy efficiency and peak demand reduction program. JCP&L’s program consists of 11 energy efficiency and peak demand reduction programs and subprograms to be run from July 1, 2021 through June 30, 2024. The program also seeks approval of cost recovery totaling approximately $230 million as well as lost revenues associated with the energy savings resulting from the programs. While a procedural order has been established in this matter, on January 20, 2021, JCP&L filed a letter requesting a suspension of the procedural schedule to allow for settlement discussions. The Clean Energy Act contemplates a final order from the NJBPU by May 2, 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. On August 21, 2020, the Governor of New Jersey issued a press release announcing that the New Jersey utilities agreed to extend their voluntary moratorium preventing shutoffs to both residential and commercial customers during the COVID-19 pandemic until October 15, 2020. On October 15, 2020, the Governor issued an Executive Order prohibiting utilities from terminating service to any residential gas, electric, public and private water customer, through March 15, 2021, requiring the reconnection of certain customers, and disallowing the charging of late payment charges or reconnection fees during the public health emergency. On October 28, 2020, the NJBPU issued an order expanding the scope of the proceeding to examine all pandemic issues, including recovery of the COVID-19 regulatory assets, by way of a generic proceeding. On November 30, 2020, JCP&L submitted comments. The recent credit rating actions taken on October 28, 2020, by S&P and Fitch triggered a requirement from various NJBPU orders that JCP&L file a mitigation plan, which was filed on November 5, 2020, to demonstrate that JCP&L has sufficient liquidity to meet its BGS obligations. On December 11, 2020, the NJBPU held a public hearing on the mitigation plan. Written comments on JCP&L’s mitigation plan were submitted on January 8, 2021. 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 were decoupled, through a mechanism that took effect on February 1, 2020 and under which the Ohio Companies billed customers until February 9, 2021, 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 revenue associated with energy efficiency and peak demand reduction programs, which is discussed further below; (3) a goal across FirstEnergy to reduce CO 2 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. 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 for OE and claiming a $42 million refund is due to OE customers. On December 1, 2020, the SCOH reversed the PUCO’s exclusion of the DMR revenues from the determination of the existence of significantly excessive earnings under ESP IV for OE for calendar year 2017, and remanded the case to the PUCO with instructions to conduct new proceedings which includes the DMR revenues in the analysis, determines the threshold against which the earned return is measured, and makes other necessary determinations. FirstEnergy is unable to predict the outcome of these proceedings but has not deemed a liability probable as of December 31, 2020. On July 23, 2019, Ohio enacted HB 6, which established support for nuclear energy supply in Ohio. In addition to the provisions supporting nuclear energy, HB 6 included provisions 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 a wind-down of statutorily required energy efficiency programs to commence on September 30, 2020, that the programs terminate on December 31, 2020, with the Ohio Companies' existing portfolio plans 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. Legislation has been introduced in the first quarter of 2021 to, among other things, repeal parts of HB 6, the legislation that established support for nuclear energy supply in Ohio, provided for a decoupling mechanism for Ohio electric utilities, and provided for the ending of current energy efficiency program mandates. As further discussed below, in connection with a partial settlement with the OAG and other parties, the Ohio Companies filed an application with the PUCO on February 1, 2021, to set the respective decoupling riders (Rider CSR) to zero. While the partial settlement with the OAG focused specifically on decoupling, the Ohio Companies will of their own accord not seek to recover lost distribution revenue from residential and commercial customers. FirstEnergy is committed to pursuing an open dialogue with stakeholders in an appropriate manner with respect to the numerous regulatory proceedings currently underway as further discussed herein. As a result of the partial settlement, and the decision to not seek lost distribution revenue, FirstEnergy recognized a $108 million pre-tax charge ($84 million after-tax) in the fourth quarter of 2020, and $77 million (pre-tax) of which is associated with forgoing collection of lost distribution revenue. FirstEnergy does not believe a refund for previously collected amounts under decoupling, which was approximately $18 million, is probable. Furthermore, as FirstEnergy would not have financially benefited from the Clean Air Fund included in HB 6, which is the mechanism to provide support to nuclear energy in Ohio, there is no expected additional impact to FirstEnergy due to any repeal of that provision of HB 6. 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 September 23, 2020, the PUCO approved the Ohio Companies’ transition plan, including approval of the resumption of service disconnections for non-payment, which the Ohio Companies began on October 5, 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. Furthermore, on January 21, 2021, Senate Bill 10 was introduced, which would repeal legislation passed in 2019 that permitted the Ohio Companies to file their SEET results on a consolidated basis instead of on an individual company basis. On September 4, 2020, the PUCO opened its quadrennial review of ESP IV, consolidated it with the Ohio Companies’ 2018 and 2019 SEET Applications, and set a procedural schedule for the consolidated matters. On October 29, 2020, the PUCO issued an entry extending the deadline for the Ohio Companies to file quadrennial review of ESP IV testimony to March 1, 2021, with the evidentiary hearings to commence no sooner than May 3, 2021. On January 12, 2021, the PUCO consolidated these matters with the determination of the existence of significantly excessive earnings under ESP IV for calendar year 2017, which the SCOH had remanded to the PUCO. On September 8, 2020, the OCC filed motions in the Ohio Companies’ corporate separation audit and DMR audit dockets, requesting the PUCO to open an investigation and management audit, hire an independent auditor, and require FirstEnergy to show it did not improperly use money collected from consumers or violate any utility regulatory laws, rules or orders in its activities regarding HB 6. The Ohio Companies’ filed a response in opposition to the OCC’s motions on September 23, 2020. On December 30, 2020, in response to the OCC's motion, the PUCO reopened the DMR audit docket, and directed PUCO staff to solicit a third-party auditor and conduct a full review of the DMR to ensure funds collected from ratepayers through the DMR were only used for the purposes established in ESP IV. Deadlines relating to the selection of the auditor and the issuance of the final audit report have not yet been set. On September 15, 2020, the PUCO opened a new proceeding to review the political and charitable spending by the Ohio Companies in support of HB 6 and the subsequent referendum effort, directing the Ohio Companies to show cause, demonstrating that the costs of any political or charitable spending in support of HB 6, or the subsequent referendum effort, were not included, directly or indirectly, in any rates or charges paid by ratepayers. The Ohio Companies filed a response on September 30, 2020, stating that any political and charitable spending in support of HB 6 or the subsequent referendum were not included in rates or charges paid for by its customers. Several parties requested that the PUCO broaden the scope of the review of political and charitable spending. In connection with an on-going audit of the Ohio Companies’ policies and procedures relating to the code of conduct rules between affiliates, on November 4, 2020, the PUCO initiated an additional corporate separation audit as a result of the FirstEnergy leadership transition announcement made on October 29, 2020, as further discussed below. The additional audit is to ensure compliance by the Ohio Companies and their affiliates with corporate separation laws and the Ohio Companies’ corporate separation plan. The additional audit is for the period from November 2016 through October 2020, with a final audit report to be filed in June 2021. On January 27, 2021, the PUCO selected an auditor. On November 24, 2020, the Environmental Law and Policy Center filed motions to vacate the PUCO’s orders in proceedings related to the Ohio Companies’ settlement that provides for the implementation of the first phase of grid modernization plans and for all tax savings associated with the Tax Act to flow back to customers, the Ohio Companies’ energy efficiency portfolio plans for the period from 2013 through 2016, and the Ohio Companies’ application for a two-year extension of the DMR, on the grounds that the former Chairman of the PUCO should have recused himself in these matters. On December 30, 2020, the PUCO denied the motions, and reinstated the requirement under ESP IV that the Ohio Companies file a base distribution rate case by May 31, 2024, the end of ESP IV, which the Ohio Companies had indicated they would not oppose. In the fourth quarter of 2020, motions were filed with the PUCO requesting that the PUCO amend the Ohio Companies’ riders for collecting charges required by HB 6, which the Ohio Companies are further required to remit to other Ohio electric distribution utilities or to the State Treasurer, to provide for refunds in the event HB 6 is repealed. The Ohio Companies contested the motions, which are pending before the PUCO. On December 7, 2020, the Citizens’ Utility Board of Ohio filed a complaint with the PUCO against the Ohio Companies. The complaint alleges that the Ohio Companies’ new charges resulting from HB 6, and any increased rates resulting from proceedings over which the former PUCO Chairman presided, are unjust and unreasonable, and that the Ohio Companies violated Ohio corporate separation laws by failing to operate separately from unregulated affiliates. The complaint requests, among other things, that any rates authorized by HB 6 or authorized by the PUCO in a proceeding over which the former Chairman presided be made refundable; that the Ohio Companies be required to file a new distribution rate case at the earliest possible date; and that the Ohio Companies’ corporate separation plans be modified to introduce institutional controls. The Ohio Companies are contesting the complaint. On December 9, 2020, the Ohio Manufacturers’ Association Energy Group filed an appeal to the SCOH challenging the PUCO’s generic order directing the form of rider all Ohio electric distribution utilities must charge to recover the costs of the HB 6 Clean Air Fund. The appeal contends that the PUCO erred in adopting the rate design for the riders, in establishing the riders during ongoing proceedings and investigations related to HB 6, and in not requiring electric distribution utilities to include refund language in the rider tariffs. On December 30, 2020, the PUCO vacated its generic order establishing the Clean Air Fund riders, as required by a preliminary injunction issued by the Court of Common Pleas of Franklin County, Ohio. On January 11, 2021, the SCOH granted a joint application of the Ohio Manufacturers' Association Energy Group and the PUCO and dismissed the appeal. See Note 15, "Commitments, Guarantees and Contingencies" below for additional details on the government inv

COMMITMENTS, GUARANTEES AND CON

COMMITMENTS, GUARANTEES AND CONTINGENCIES	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, GUARANTEES AND CONTINGENCIES	COMMITMENTS, GUARANTEES AND CONTINGENCIES GUARANTEES AND OTHER ASSURANCES FirstEnergy has various financial and performance guarantees and indemnifications which are issued in the normal course of business. These contracts include performance guarantees, stand-by letters of credit, debt guarantees, surety bonds and indemnifications. FirstEnergy enters into these arrangements to facilitate commercial transactions with third parties by enhancing the value of the transaction to the third party. As of December 31, 2020, outstanding guarantees and other assurances aggregated approximately $1.7 billion, consisting of parental guarantees on behalf of its consolidated subsidiaries' guarantees ($1.1 billion), other guarantees ($108 million) and other assurances ($490 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. As of December 31, 2020 $20 million of collateral has been posted by FE or its subsidiaries, of which, $19 million was posted as a result of the credit rating downgrades in the fourth quarter of 2020. 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 December 31, 2020: Potential Collateral Obligations Utilities FE Total (In millions) Contractual Obligations for Additional Collateral Upon Further Downgrade $ 37 $ — $ 37 Surety Bonds (Collateralized Amount) (1) 55 258 313 Total Exposure from Contractual Obligations $ 92 $ 258 $ 350 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with the respect to $39 million of surety obligations for which the collateral obligation is capped at 60% of the face amount, and 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 $108 million as of December 31, 2020. Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, and FE 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 SO 2 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 SO 2 emissions in two phases (2015 and 2017), ultimately capping SO 2 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 SO 2 emission allowances between power plants located in the same state and interstate trading of NOx and SO 2 emission allowances with some restrictions. The D.C. Circuit ordered the EPA on July 28, 2015, to reconsider the CSAPR caps on NOx and SO 2 emissions from power plants in 13 states, including 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 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 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 SO 2 , specifically retaining the 2010 primary (health-based) 1-hour standard of 75 PPB. As of December 31, 2020, FirstEnergy has no power plants operating in areas designated as non-attainment by the EPA. 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 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 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. On January 20, 2021, President Biden signed an executive order re-adopting the agreement on behalf of the U.S. 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 CO 2 emissions from existing fossil fuel fired EGUs and finalized separate regulations imposing CO 2 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. 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. On January 19, 2021, the D.C. Circuit remanded the ACE rule declaring that the EPA was “arbitrary and capricious” in its rule making, as such, the ACE rule is no longer in effect and all actions thus far taken by States to implement the federally mandated rule are now null and void. The D.C. Circuit decision is subject to legal challenge. 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 were to phase-in as permits are renewed on a five 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 the EPA alleging violations of the CWA at the Springdale and Mingo landfills 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 both facilities. 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. On November 30, 2020, AE Supply submitted a closure deadline extension request to the EPA seeking to extend the closure date until 2024 of McElroy's Run CCR impoundment facility, for which AE Supply continues to provide access to FG. 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 December 31, 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 $107 million have been accrued through December 31, 2020. Included in the total are accrued liabilities of approximately $67 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. 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 HB 6 and the now former Ohio House Speaker Larry Householder and other individuals and entities allegedly affiliated with Mr. Householder. • Owens v. FirstEnergy Corp. et al. and Frand v. FirstEnergy Corp. et al. (Federal District Court, S.D. Ohio); on July 28, 2020 and August 21, 2020, purported stockholders of FE filed putative class action lawsuits 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. These actions have been consolidated and a lead plaintiff has been appointed by the court. • 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. These actions have been consolidated. • Miller v. Anderson, et al. (Federal District Court, N.D. Ohio); Bloom, et al. v. Anderson, et al.; Employees Retirement System of the City of St. Louis v. Jones, et al.; Electrical Workers Pension Fund, Local 103, I.B.E.W. v. Anderson et al.; Massachusetts Laborers Pension Fund v. Anderson et al.; The City of Philadelphia Board of Pensions and Retirement v. Anderson et al.; Atherton v. Dowling et al; Behar v. Anderson, et al. (U.S. District Court, S.D. Ohio, all actions have been consolidated); beginning on August 7, 2020, purported stockholders of FE filed shareholder derivative actions alleging the board and officers breached their fiduciary duties and committed violations of Section 14(a) of the Securities Exchange Act of 1934. The cases in the Southern District of Ohio have been consolidated and co-lead plaintiffs have been appointed by the court. • Smith v. FirstEnergy Corp. et al., 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 27, 2020, July 31, 2020, and August 5, 2020, respectively, purported customers of FirstEnergy filed putative class action lawsuits against FE and FESC, as well as certain current and former FirstEnergy officers, alleging civil Racketeer Influenced and Corrupt Organizations Act violations and related state law claims. These actions have been consolidated. • State of Ohio ex rel. Dave Yost, Ohio Attorney General v. FirstEnergy Corp., et al. and City of Cincinnati and City of Columbus v. FirstEnergy Corp. (Common Pleas Court, Franklin County, OH); on September 23, 2020 and October 27, 2020, the OAG and the cities of Cincinnati and Columbus, respectively, filed complaints against several parties including FE, each alleging civil violations of the Ohio Corrupt Activity Act in connection with the passage of HB 6. The OAG sought a preliminary injunction to prevent each of the defendants, including FE, through the end of 2020, from: (i) contributing to any groups whose purpose is to keep or modify HB 6; (ii) making any public statements for or against any repeal or modification legislation concerning HB 6; (iii) lobbying, consulting, or advising on these matters; or (iv) contributing to any Ohio legislative candidates. The court denied the OAG’s request for preliminary injunctive relief on October 2, 2020. On January 13, 2021, the OAG filed a motion for a temporary restraining order and preliminary injunction against FirstEnergy seeking to enjoin FirstEnergy from collecting the Ohio Companies' decoupling rider. On January 31, 2021, FE reached a partial settlement with the OAG and the cities of Cincinnati and Columbus with respect to the temporary restraining order and preliminary injunction request and related issues. In connection with the partial settlement, the Ohio Companies filed an application on February 1, 2021, with the PUCO to set their respective decoupling riders (Rider CSR) to zero. On February 2, 2021, the PUCO approved the application of the Ohio Companies setting the rider to zero and no additional customer bills will include new decoupling rider charges after February 8, 2021. The cities of Dayton and Toledo have also been added as plaintiffs to the action. These actions have been consolidated. • 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, along with FES, alleging several causes of action, including negligence and/or gross negligence, breach of contract, unjust enrichment, and unfair or deceptive consumer acts or practices. On October 1, 2020, plaintiffs filed a First Amended Complaint, adding as a plaintiff a purported customer of FirstEnergy and alleging a civil violation of the Ohio Corrupt Activity Act and civil conspiracy against FE, FESC and FES. The plaintiffs in each of the above cases, seek, among other things, to recover an unspecified amount of damages (unless otherwise noted). In addition, on August 10, 2020, the SEC, through its Division of Enforcement, issued an order directing an investigation of possible securities laws violations by FE, and on September 1, 2020, issued subpoenas to FE and certain FE officers. Further, on January 26, 2021, staff of FERC's Division of Investigations issued a letter directing FirstEnergy to preserve and maintain all documents and information related to an ongoing audit being conducted by FERC's Division of Audits and Accounting, including activities related to lobbying and governmental affairs activities concerning HB 6. The outcome of any of these lawsuits, investigations and audit are 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. Internal Investigation Relating to United States v. Larry Householder, et al. As previously disclosed, a committee of independent members of the Board of Directors is directing an internal investigation related to ongoing government investigations. In connection with FirstEnergy’s internal investigation, such committee determined on October 29, 2020, to terminate FirstEnergy’s Chief Executive Officer, Charles E. Jones, together with two other executives: Dennis M. Chack, Senior Vice President of Product Development, Marketing, and Branding; and Michael J. Dowling, Senior Vice President of External Affairs. Each of these terminated executives violated certain FirstEnergy policies and its code of conduct. These executives were terminated as of October 29, 2020. Such former members of senior management did not maintain and promote a control environment with an appropriate tone of compliance in certain areas of FirstEnergy’s business, nor sufficiently promote, monitor or enforce adherence to certain FirstEnergy policies and its code of conduct. Furthermore, certain former members of senior management did not reasonably ensure that relevant information was communicated within our organization and not withheld from our independent directors, our Audit Committee, and our independent auditor. Among the matters considered with respect to the determination by the committee of independent members of the Board of Directors that certain former members of senior management violated certain FirstEnergy policies and its code of conduct related to a payment of approximately $4 million made in early 2019 in connection with the termination of a purported consulting agreement, as amended, which had been in place since 2013. The counterparty to such agreement was an entity associated with an individual who subsequently was appointed to a full-time role as an Ohio government official directly involved in regulating the Ohio Companies, including with respect to distribution rates. FirstEnergy believes that payments under the consulting agreement may have been for purposes other than those represented within the consulting agreement. Immediately following these terminations, the independent members of its Board appointed Mr. Steven E. Strah to the position of Acting Chief Executive Officer and Mr. Christopher D. Pappas, a current member of the Board, to the temporary position of Executive Director, each effective as of October 29, 2020. Mr. Donald T. Misheff will continue to serve as Non-Executive Chairman of the Board. Additionally, on November 8, 2020, Robert P. Reffner, Senior Vice President and Chief Legal Officer, and Ebony L. Yeboah-Amankwah, Vice President, General Counsel, and Chief Ethics Officer, were separated from FirstEnergy due to inaction and conduct that the Board determined was influenced by the improper tone at the top. The matter is a subject of the ongoing internal investigation as it relates to the government investigations. Nuclear Plant Matters 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 Energy Solutions , 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. On 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. On December 2, 2020, the NJBPU issued an order approving the transfer and sale under the conditions requested by Rate Counsel and agreed to by JCP&L. Also, on December 2, 2020, the NRC issued its order approving the license transfer as requested. With the receipt of all required regulatory approvals, the transaction was consummated on December 18, 2020. See Note 1, "Organization and Basis of Presentation," for additional discussion. 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 14, "Regulatory Matters."

TRANSACTIONS WITH AFFILIATED CO

TRANSACTIONS WITH AFFILIATED COMPANIES	12 Months Ended
	Dec. 31, 2020
Transactions With Affiliated Companies [Abstract]
TRANSACTIONS WITH AFFILIATED COMPANIES	TRANSACTIONS WITH AFFILIATED COMPANIES FE does not bill directly or allocate any of its costs to any subsidiary company. Costs are charged to FE's subsidiaries for services received from FESC. The majority of costs are directly billed or assigned at no more than cost. The remaining costs are for services that are provided on behalf of more than one company, or costs that cannot be precisely identified and are allocated using formulas developed by FESC. The current allocation or assignment formulas used and their bases include multiple factor formulas: each company’s proportionate amount of FirstEnergy’s aggregate direct payroll, number of employees, asset balances, revenues, number of customers, other factors and specific departmental charge ratios. Intercompany transactions are generally settled under commercial terms within thirty days. The Utilities and Transmission Companies are parties to an intercompany income tax allocation agreement with FE and its other subsidiaries, that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE are generally reallocated to the subsidiaries of FirstEnergy that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit (see Note 7, "Taxes").

SEGMENT INFORMATION

SEGMENT INFORMATION	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
SEGMENT INFORMATION	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 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. Included within the segment is $882 million of assets classified as held for sale as of December 31, 2019 associated with the asset purchase and sale agreements with TMI-2 Solutions to transfer TMI-2 to TMI-2 Solutions, LLC. With the receipt of all required regulatory approvals, the transaction was consummated on December 18, 2020. As a result, during the fourth quarter of 2020 FirstEnergy recognized an after tax-gain of approximately $33 million, primarily associated with the write-off of a tax related regulatory liability. See Note 15, "Commitments, Guarantees and Contingencies" for additional information. Also included within the segment is $45 million of assets classified as held for sale as of December 31, 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 14, "Regulatory Matters" for additional information. 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; although as explained in Note 14, "Regulatory Matters", effective January 1, 2021, subject to refund, MP's, PE's and WP's existing stated rates became forward-looking formula rates. JCP&L previously had stated transmission rates, however, effective January 1, 2020, JCP&L implemented forward-looking formula rates, subject to refund, pending further hearing and settlement proceedings. Both forward-looking formula and stated rates recover costs that FERC determines are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. 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 December 31, 2020, 67 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of Corporate/Other. As of December 31, 2020, Corporate/Other had approximately $8.2 billion of FE holding company debt. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below: Segment Financial Information For the Years Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) December 31, 2020 External revenues $ 9,168 $ 1,613 $ 9 $ — $ 10,790 Internal revenues 195 17 — (212) — Total revenues 9,363 1,630 9 (212) 10,790 Provision for depreciation 896 313 4 61 1,274 Amortization (deferral) of regulatory assets, net (64) 11 — — (53) Miscellaneous income (expense), net 332 30 83 (13) 432 Interest expense 501 219 358 (13) 1,065 Income taxes (benefits) 113 138 (125) — 126 Income (loss) from continuing operations 959 464 (420) — 1,003 Property additions $ 1,514 $ 1,067 $ 76 $ — $ 2,657 December 31, 2019 External revenues $ 9,511 $ 1,510 $ 14 $ — $ 11,035 Internal revenues 187 16 — (203) — Total revenues 9,698 1,526 14 (203) 11,035 Provision for depreciation 863 284 5 68 1,220 Amortization (deferral) of regulatory assets, net (89) 10 — — (79) Miscellaneous income (expense), net 174 15 80 (26) 243 Interest expense 495 192 372 (26) 1,033 Income taxes (benefits) 271 113 (171) — 213 Income (loss) from continuing operations 1,076 447 (619) — 904 Property additions $ 1,473 $ 1,090 $ 102 $ — $ 2,665 December 31, 2018 External revenues $ 9,900 $ 1,335 $ 26 $ — $ 11,261 Internal revenues 203 18 8 (229) — Total revenues 10,103 1,353 34 (229) 11,261 Provision for depreciation 812 252 3 69 1,136 Amortization (deferral) of regulatory assets, net (163) 13 — — (150) Miscellaneous income (expense), net 192 14 32 (33) 205 Interest expense 514 167 468 (33) 1,116 Income taxes 422 122 (54) — 490 Income (loss) from continuing operations 1,242 397 (617) — 1,022 Property additions $ 1,411 $ 1,104 $ 133 $ 27 $ 2,675 As of December 31, 2020 Total assets $ 30,855 $ 12,592 $ 1,017 $ — $ 44,464 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

ORGANIZATION AND BASIS OF PRE_2

ORGANIZATION AND BASIS OF PRESENTATION (Policies)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Accounting	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 preparation of financial statements in conformity with GAAP requires management to make periodic estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and disclosure of contingent assets and liabilities. Actual results could differ from these estimates. The reported results of operations are not necessarily indicative of results of operations for any future period. FE and its subsidiaries have evaluated events and transactions for potential recognition or disclosure through the date the financial statements were issued.
Consolidation	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. As further discussed below, 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.
Receivables	RECEIVABLES Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2020, 2019 and 2018 are as follows: (In millions) 2020 2019 2018 Customer Receivables Beginning of year balance $ 46 $ 50 $ 49 Charged to income (1) 174 81 77 Charged to other accounts (2) 46 47 60 Write-offs (102) (132) (136) End of year balance $ 164 $ 46 $ 50 Other Receivables Beginning of year balance $ 21 $ 2 $ 1 Charged to income 7 27 13 Charged to other accounts (2) 10 1 — Write-offs (12) (9) (12) End of year balance $ 26 $ 21 $ 2 Affiliated Companies Receivables (3) Beginning of year balance $ 1,063 $ 920 $ — Charged to income — 143 920 Charged to other accounts (2) — — — Write-offs (1,063) — — End of year balance $ — $ 1,063 $ 920 (1) Customer receivable amounts charged to income for the years ended December 31, 2020, 2019 and 2018 include approximately $103 million, $25 million, and $24 million respectively, deferred for future recovery. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (3) Amounts relate to the FES Debtors and are included in discontinued operations. Write-off of $1.1 billion in 2020 was recognized upon their emergence in February 2020. See Note 3, "Discontinued Operations" for additional information.
Accounting for the Effects of Regulation	ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities and the Transmission Companies since their rates are established by a third-party regulator with the authority to set rates that bind customers, are cost-based and can be charged to and collected from customers.
Earnings Per Share of Common Stock	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. During 2019 and 2018, 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.
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENTProperty, plant and equipment reflects original cost (net of any impairments recognized), including payroll and related costs such as taxes, employee benefits, administrative and general costs, and interest costs incurred to place the assets in service. The costs of normal maintenance, repairs and minor replacements are expensed as incurred. FirstEnergy recognizes liabilities for planned major maintenance projects as they are incurred.
Asset Retirement Obligations	Asset Retirement Obligations FE recognizes an ARO for the future remediation of environmental liabilities associated with all of its long-lived assets. The ARO liability represents an estimate of the fair value of FirstEnergy's current obligation related to nuclear decommissioning and the retirement or remediation of environmental liabilities of other assets. A fair value measurement inherently involves uncertainty in the amount and timing of settlement of the liability. FirstEnergy uses an expected cash flow approach to measure the fair value of the nuclear decommissioning and environmental remediation AROs, considering the expected timing of settlement of the ARO based on the expected economic useful life of associated asset and/or regulatory requirements. The fair value of an ARO is recognized in the period in which it is incurred. The associated asset retirement costs are capitalized as part of the carrying value of the long-lived asset and are depreciated over the life of the related asset. In certain circumstances, FirstEnergy has recovery of asset retirement costs and, as such, certain accretion and depreciation is offset against regulatory assets. Conditional retirement obligations associated with tangible long-lived assets are recognized at fair value in the period in which they are incurred if a reasonable estimate can be made, even though there may be uncertainty about timing or method of settlement. When settlement is conditional on a future event occurring, it is reflected in the measurement of the liability, not the timing of the liability recognition. AROs as of December 31, 2020, including the transfer of TMI-2, its NDT and related decommissioning liabilities to TMI-2 Solutions, LLC, a subsidiary of Energy Solutions
Goodwill	GOODWILL In a business combination, the excess of the purchase price over the estimated fair value of the assets acquired and liabilities assumed is recognized as goodwill. FirstEnergy evaluates goodwill for impairment annually on July 31 and more frequently if indicators of impairment arise. In evaluating goodwill for impairment, FirstEnergy assesses qualitative factors to determine whether it is more likely than not (that is, likelihood of more than 50%) that the fair value of a reporting unit is less than its carrying value (including goodwill). If FirstEnergy concludes that it is not more likely than not that the fair value of a reporting unit is less than its carrying value, then no further testing is required. However, if FirstEnergy concludes that it is more likely than not that the fair value of a reporting unit is less than its carrying value or bypasses the qualitative assessment, then the quantitative goodwill impairment test is performed to identify a potential goodwill impairment and measure the amount of impairment to be recognized, if any.
Inventory	INVENTORY Materials and supplies inventory includes fuel inventory and the distribution, transmission and generation plant materials, net of reserve for excess and obsolete inventory. Materials are generally charged to inventory at weighted average cost when purchased and expensed or capitalized, as appropriate, when used or installed. Fuel inventory is accounted for at weighted average cost when purchased and recorded to fuel expense when consumed.
Derivatives	DERIVATIVES FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy may use a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps.
Variable Interest Entities	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In June 2013, SPEs formed by the Ohio Companies issued approximately $445 million of pass-through trust certificates supported by phase-in recovery bonds to securitize the recovery of certain all electric customer heating discounts, fuel and purchased power regulatory assets. • JCP&L Securitization - JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. • MP and PE Environmental Funding Companies - Bankruptcy remote, special purpose limited liability companies that are indirect subsidiaries of MP and PE which issued environmental control bonds. See Note 11, “Capitalization,” for additional information on securitized bonds. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV's ownership interest is subject to the equity method of accounting. As of December 31, 2020, the carrying value of the equity method investment was $30 million. As discussed in Note 15, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's $120 million syndicated senior secured term loan facility due November 12, 2024, under which Global Holding's outstanding principal balance is $108 million as of December 31, 2020. Failure by Global Holding to meet the terms and conditions under its term loan facility could require FE to be obligated under the provisions of its guarantee, resulting in consolidation of Global Holding by FE. • PATH WV - PATH, a proposed transmission line from West Virginia through Virginia into Maryland which PJM cancelled in 2012, is a series limited liability company that is comprised of multiple series, each of which has separate rights, powers and duties regarding specified property and the series profits and losses associated with such property. A subsidiary of FE owns 100% of the Allegheny Series (PATH-Allegheny) and 50% of the West Virginia Series (PATH-WV), which is a joint venture with a subsidiary of AEP. FirstEnergy is not the primary beneficiary of PATH-WV, as it does not have control over the significant activities affecting the economics of PATH-WV. FirstEnergy's ownership interest in PATH-WV is subject to the equity method of accounting. As of December 31, 2020, the carrying value of the equity method investment was $18 million. • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains six long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest, or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities.
New Accounting Pronouncements	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 and subsequently updated): 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 December 31, 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
Income Taxes	FirstEnergy records income taxes in accordance with the liability method of accounting. Deferred income taxes reflect the net tax effect of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts recognized for tax purposes. Investment tax credits, which were deferred when utilized, are being amortized over the recovery period of the related property. Deferred income tax liabilities related to temporary tax and accounting basis differences and tax credit carryforward items are recognized at the statutory income tax rates in effect when the liabilities are expected to be paid. Deferred tax assets are recognized based on income tax rates expected to be in effect when they are settled. FE and its subsidiaries are party to an intercompany income tax allocation agreement that provides for the allocation of consolidated tax liabilities. Net tax benefits attributable to FE, excluding any tax benefits derived from interest expense associated with acquisition indebtedness from the merger with GPU, are reallocated to the subsidiaries of FE that have taxable income. That allocation is accounted for as a capital contribution to the company receiving the tax benefit. Effective as of their emergence from bankruptcy, February 27, 2020, the FES Debtors no longer are part of FirstEnergy's consolidated federal income tax group or the intercompany income tax allocation agreement. Upon emergence, FirstEnergy paid the FES Debtors
Pension and Other Postretirement Plans	PENSION AND OTHER POST-EMPLOYMENT BENEFITS FirstEnergy provides noncontributory qualified defined benefit pension plans that cover substantially all of its employees and non-qualified pension plans that cover certain employees. The plans provide defined benefits based on years of service and compensation levels. Under the cash-balance portion of the pension plan (for employees hired on or after January 1, 2014), FirstEnergy makes contributions to eligible employee retirement accounts based on a pay credit and an interest credit. In addition, FirstEnergy provides a minimum amount of noncontributory life insurance to retired employees in addition to optional contributory insurance. Health care benefits, which include certain employee contributions, deductibles and co-payments, are also available upon retirement to certain employees, their dependents and, under certain circumstances, their survivors. FirstEnergy recognizes the expected cost of providing pension and OPEB to employees and their beneficiaries and covered dependents from the time employees are hired until they become eligible to receive those benefits. FirstEnergy also has obligations to former or inactive employees after employment, but before retirement, for disability-related benefits. FirstEnergy recognizes a pension and OPEB mark-to-market adjustment for the change in the 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 a remeasurement. The remaining components of pension and OPEB expense, primarily service costs, interest on obligations, assumed return on assets and prior service costs, are recorded on a monthly basis. 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 first quarter 2020 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. In the fourth quarter 2020, FirstEnergy recognized a $54 million pension and OPEB mark-to-market adjustment, primarily reflecting a 29 bps decrease in the discount rate used to measure benefit obligations from February 27, 2020, partially offset by higher than expected return on assets. Of the $54 million, approximately $21 million was allocated to certain of the Transmission Companies that are expected to be recovered through formula transmission rates. The annual pension and OPEB mark-to-market adjustments for the years ended December 31, 2020, 2019, and 2018 were $477 million (including the $423 million in the first quarter of 2020 described above), $676 million, and $145 million, respectively. Of these amounts, approximately $2 million and $1 million are included in discontinued operations for the years ended December 31, 2019, and 2018, respectively. Furthermore, of these annual pension and OPEB mark-to-market amounts, approximately $40 million, $47 million and $8 million were allocated to certain of the Transmission Companies and expected to be recovered through formula transmission rates, respectively. FirstEnergy’s pension and OPEB funding policy is based on actuarial computations using the projected unit credit method. In January 2018, FirstEnergy satisfied its minimum required funding obligations to its qualified pension plan of $500 million and addressed anticipated required funding obligations through 2020 to its pension plan with an additional contribution of $750 million. On February 1, 2019, FirstEnergy made a $500 million voluntary cash contribution to the qualified pension plan. FirstEnergy expects no required contributions until 2022.
Share-based Compensation	Shares granted under the ICP 2020 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from two to ten years, with the majority of awards having a vesting period of three years. FirstEnergy also issues stock through its 401(k) Savings Plan, EDCP, and DCPD. Currently, FirstEnergy records the compensation costs for stock-based compensation awards that will be paid in stock over the vesting period based on the fair value on the grant date. FirstEnergy accounts for forfeitures as they occur. FirstEnergy adjusts the compensation costs for stock-based compensation awards that will be paid in cash based on changes in the fair value of the award as of each reporting date. FirstEnergy records the actual tax benefit realized from tax deductions when awards are exercised or settled
Fair Value Measurement	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.

ORGANIZATION AND BASIS OF PRE_3

ORGANIZATION AND BASIS OF PRESENTATION (Tables)	12 Months Ended
	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accounts receivable, allowance for credit loss	Activity in the allowance for uncollectible accounts on receivables for the years ended December 31, 2020, 2019 and 2018 are as follows: (In millions) 2020 2019 2018 Customer Receivables Beginning of year balance $ 46 $ 50 $ 49 Charged to income (1) 174 81 77 Charged to other accounts (2) 46 47 60 Write-offs (102) (132) (136) End of year balance $ 164 $ 46 $ 50 Other Receivables Beginning of year balance $ 21 $ 2 $ 1 Charged to income 7 27 13 Charged to other accounts (2) 10 1 — Write-offs (12) (9) (12) End of year balance $ 26 $ 21 $ 2 Affiliated Companies Receivables (3) Beginning of year balance $ 1,063 $ 920 $ — Charged to income — 143 920 Charged to other accounts (2) — — — Write-offs (1,063) — — End of year balance $ — $ 1,063 $ 920 (1) Customer receivable amounts charged to income for the years ended December 31, 2020, 2019 and 2018 include approximately $103 million, $25 million, and $24 million respectively, deferred for future recovery. (2) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (3) Amounts relate to the FES Debtors and are included in discontinued operations. Write-off of $1.1 billion in 2020 was recognized upon their emergence in February 2020. See Note 3, "Discontinued Operations" for additional information.
Receivables from customers	Billed and unbilled customer receivables as of December 31, 2020 and 2019, net of allowance for uncollectible accounts, are included below. Customer Receivables December 31, 2020 December 31, 2019 (In millions) Billed $ 636 $ 564 Unbilled 567 527 Total $ 1,203 $ 1,091
Regulatory assets on the Balance Sheets	The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2020 and December 31, 2019, and the changes during the year ended December 31, 2020: Net Regulatory Assets (Liabilities) by Source December 31, December 31, Change (In millions) Customer payables for future income taxes $ (2,369) $ (2,605) $ 236 Nuclear decommissioning and spent fuel disposal costs (102) (197) 95 Asset removal costs (721) (756) 35 Deferred transmission costs 316 298 18 Deferred generation costs 104 214 (110) Deferred distribution costs 136 155 (19) Contract valuations 41 51 (10) Storm-related costs 748 551 197 Uncollectible and COVID-19 related costs 97 3 94 Other 6 25 (19) Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (1,744) $ (2,261) $ 517 The following table provides information about the composition of net regulatory assets that do not earn a current return as of December 31, 2020 and 2019, of which approximately $195 million and $228 million, respectively, are currently being recovered through rates over varying periods, through 2068, depending on the nature of the deferral and the jurisdiction: Regulatory Assets by Source Not Earning a Current Return December 31, December 31, Change (in millions) Deferred transmission costs $ 29 $ 27 $ 2 Deferred generation costs 5 15 (10) Storm-related costs 654 471 183 COVID-19 related costs 66 — 66 Other 35 32 3 Regulatory Assets Not Earning a Current Return $ 789 $ 545 $ 244
Reconciliation of basic and diluted earnings per share	Year Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2020 2019 2018 (In millions, except per share amounts) EPS of Common Stock Income from continuing operations $ 1,003 $ 904 $ 1,022 Less: Preferred dividends — (3) (71) Less: Amortization of beneficial conversion feature — — (296) Less: Undistributed earnings allocated to preferred stockholders (1) N/A (1) — Income from continuing operations available to common stockholders 1,003 900 655 Discontinued operations, net of tax 76 8 326 Less: Undistributed earnings allocated to preferred stockholders (1) N/A — — Income from discontinued operations available to common stockholders 76 8 326 Income attributable to common stockholders, basic $ 1,079 $ 908 $ 981 Income allocated to preferred stockholders, preferred dilutive (2) N/A 4 N/A Income attributable to common stockholders, dilutive $ 1,079 $ 912 $ 981 Share Count information: Weighted average number of basic shares outstanding 542 535 492 Assumed exercise of dilutive stock options and awards 1 3 2 Assumed conversion of preferred stock — 4 — Weighted average number of diluted shares outstanding 543 542 494 Income attributable to common stockholders, per common share: Income from continuing operations, basic $ 1.85 $ 1.69 $ 1.33 Discontinued operations, basic 0.14 0.01 0.66 Income attributable to common stockholders, basic $ 1.99 $ 1.70 $ 1.99 Income from continuing operations, diluted $ 1.85 $ 1.67 $ 1.33 Discontinued operations, diluted 0.14 0.01 0.66 Income attributable to common stockholders, diluted $ 1.99 $ 1.68 $ 1.99 (1) Undistributed earnings were not allocated to participating securities for the year ended December 31, 2018, as income from continuing operations less dividends declared (common and preferred) and deemed dividends were a net loss. Undistributed earning allocated to participating securities for the years ended December 31, 2019 and 2020 were immaterial.
Property, plant and equipment balances	Property, plant and equipment balances by segment as of December 31, 2020 and 2019, were as follows: December 31, 2020 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 29,775 $ (8,800) $ 20,975 $ 841 $ 21,816 Regulated Transmission 12,912 (2,609) 10,303 671 10,974 Corporate/Other 1,039 (556) 483 66 549 Total $ 43,726 $ (11,965) $ 31,761 $ 1,578 $ 33,339 December 31, 2019 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 28,735 $ (8,540) $ 20,195 $ 744 $ 20,939 Regulated Transmission 12,023 (2,383) 9,640 526 10,166 Corporate/Other 1,009 (504) 505 40 545 Total $ 41,767 $ (11,427) $ 30,340 $ 1,310 $ 31,650 (1) Includes finance leases of $153 million and $163 million as of December 31, 2020 and 2019, respectively.
Summary of changes in goodwill	The following table presents goodwill by reporting unit as of December 31, 2020: (In millions) Regulated Distribution Regulated Transmission Consolidated Goodwill $ 5,004 $ 614 $ 5,618

REVENUE (Tables)

REVENUE (Tables)	12 Months Ended
	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2020: Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,259 $ — $ (88) $ 5,171 Retail generation 3,577 — (60) 3,517 Wholesale sales 251 — 9 260 Transmission (2) — 1,613 — 1,613 Other 140 — — 140 Total revenues from contracts with customers $ 9,227 $ 1,613 $ (139) $ 10,701 ARP (3) 43 — — 43 Other non-customer revenue 93 17 (64) 46 Total revenues $ 9,363 $ 1,630 $ (203) $ 10,790 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($2 million at Regulated Distribution and $7 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2020, is primarily related to shared savings revenue in Ohio. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2019: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,133 $ — $ (83) $ 5,050 Retail generation 3,727 — (57) 3,670 Wholesale sales (2) 411 — 12 423 Transmission (2) — 1,510 — 1,510 Other 150 — 2 152 Total revenues from contracts with customers $ 9,421 $ 1,510 $ (126) $ 10,805 ARP (3) 181 — — 181 Other non-customer revenue 96 16 (63) 49 Total revenues $ 9,698 $ 1,526 $ (189) $ 11,035 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($16 million at Regulated Distribution and $19 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2019, includes DMR revenue, lost distribution and shared savings revenue in Ohio. The following represents a disaggregation of revenue from contracts with customers for the year ended December 31, 2018: Revenues by Type of Service Regulated Distribution Regulated Transmission Corporate/Other and Reconciling Adjustments (1) Total (In millions) Distribution services (2) $ 5,159 $ — $ (104) $ 5,055 Retail generation 3,936 — (54) 3,882 Wholesale sales (2) 502 — 22 524 Transmission (2) — 1,335 — 1,335 Other 144 — 4 148 Total revenues from contracts with customers $ 9,741 $ 1,335 $ (132) $ 10,944 ARP (3) 254 — — 254 Other non-customer revenue 108 18 (63) 63 Total revenues $ 10,103 $ 1,353 $ (195) $ 11,261 (1) Includes eliminations and reconciling adjustments of inter-segment revenues. (2) Includes reductions to revenue related to amounts subject to refund resulting from the Tax Act ($131 million at Regulated Distribution and $16 million at Regulated Transmission). (3) ARP revenue for the year ended December 31, 2018, includes DMR revenue, lost distribution and shared savings revenue in Ohio. The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the years ended December 31, 2020, 2019 and 2018 by class: For the Years Ended December 31, Revenues by Customer Class 2020 2019 2018 (In millions) Residential $ 5,539 $ 5,412 $ 5,598 Commercial 2,140 2,252 2,350 Industrial 1,076 1,106 1,056 Other 81 90 91 Total $ 8,836 $ 8,860 $ 9,095 The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the years ended December 31, 2020, 2019 and 2018: For the Years Ended December 31, Transmission Owner 2020 2019 2018 (In millions) ATSI $ 804 $ 754 $ 664 TrAIL 247 242 237 MAIT 250 224 150 JCP&L 178 160 159 Other 134 130 125 Total Revenues $ 1,613 $ 1,510 $ 1,335

DISCONTINUED OPERATIONS (Tables

DISCONTINUED OPERATIONS (Tables)	12 Months Ended
	Dec. 31, 2020
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations	Summarized results of discontinued operations for the years ended December 31, 2020, 2019, and 2018 were as follows: For the Years Ended December 31, (In millions) 2020 2019 2018 (1) Revenues $ 7 $ 188 $ 989 Fuel (6) (140) (304) Purchased power — — (84) Other operating expenses (6) (63) (435) Provision for depreciation — — (96) General taxes — (14) (35) Pleasants economic interest (2) 5 27 — Other expense, net — (2) (83) Loss from discontinued operations, before tax — (4) (48) Income tax expense (benefit) — 47 61 Loss from discontinued operations, net of tax — (51) (109) Removal of investment in FES and FENOC — — 2,193 Assumption of benefit obligations retained at FE — — (820) Guarantees and credit support provided by FE — — (139) Reserve on receivables and allocated pension/OPEB mark-to-market — — (914) Settlement consideration and services credit (1) 7 (1,197) Accelerated net pension and OPEB prior service credits 18 — — Gain (loss) on Disposal of FES and FENOC, before tax 17 7 (877) Income tax benefit including worthless stock deduction (59) (52) (1,312) Gain on disposal of FES and FENOC, net of tax 76 59 435 Income from discontinued operations $ 76 $ 8 $ 326 (1) Discontinued operations include results of FES and FENOC through March 31, 2018, when deconsolidated from FirstEnergy's financial statements. (2) Reflects the estimated amounts owed from FG for its economic interests in Pleasants effective January 1, 2019. As discussed above, settlement of the economic interests occurred during the first quarter of 2020. FirstEnergy's Consolidated Statements of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items from discontinued operations for the years ended December 31, 2020, 2019 and 2018: For the Years Ended December 31, (In millions) 2020 2019 2018 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ 76 $ 8 $ 326 Gain on disposal, net of tax (76) (59) (435) Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs — — 110 Deferred income taxes and investment tax credits, net — 47 61 Unrealized (gain) loss on derivative transactions — — (10) CASH FLOWS FROM INVESTING ACTIVITIES: Property additions — — (27) Sales of investment securities held in trusts — — 109 Purchases of investment securities held in trusts — — (122)

ACCUMULATED OTHER COMPREHENSI_2

ACCUMULATED OTHER COMPREHENSIVE INCOME (Tables)	12 Months Ended
	Dec. 31, 2020
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI for the years ended December 31, 2020, 2019 and 2018, for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges (1) Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2018 $ (22) $ 67 $ 97 $ 142 Other comprehensive income before reclassifications — (97) (9) (106) Amounts reclassified from AOCI 8 (1) (74) (67) Deconsolidation of FES and FENOC 13 (8) — 5 Other comprehensive income (loss) 21 (106) (83) (168) Income tax (benefits) on other comprehensive income (loss) 10 (39) (38) (67) Other comprehensive income (loss), net of tax 11 (67) (45) (101) AOCI Balance, December 31, 2018 $ (11) $ — $ 52 $ 41 Other comprehensive income before reclassifications — — (2) (2) Amounts reclassified from AOCI 2 — (29) (27) Other comprehensive income (loss) 2 — (31) (29) Income tax (benefits) on other comprehensive income (loss) — — (8) (8) Other comprehensive income (loss), net of tax 2 — (23) (21) AOCI Balance, December 31, 2019 $ (9) $ — $ 29 $ 20 Amounts reclassified from AOCI 1 — (34) (33) Other comprehensive income (loss) 1 — (34) (33) Income tax (benefits) on other comprehensive income (loss) — — (8) (8) Other comprehensive income (loss), net of tax 1 — (26) (25) AOCI Balance, December 31, 2020 $ (8) $ — $ 3 $ (5) (1)
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2020, 2019 and 2018: Year Ended December 31, Affected Line Item in Consolidated Statements of Income Reclassifications from AOCI (1) 2020 2019 2018 (2) (In millions) Gains & losses on cash flow hedges Commodity contracts $ — $ — $ 1 Other operating expenses Long-term debt 1 2 7 Interest expense — — (2) Income taxes $ 1 $ 2 $ 6 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ — $ — $ (1) Discontinued operations Defined benefit pension and OPEB plans Prior-service costs $ (34) $ (29) $ (74) (3) 8 8 19 Income taxes $ (26) $ (21) $ (55) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Includes stranded tax amounts reclassified from AOCI in connection with the adoption of ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income ". (3) Prior-service costs are reported within Miscellaneous income, net within Other Income (Expense) on FirstEnergy’s Consolidated Statements of Income. Components are included in the computation of net periodic cost (credits), see Note 5, "Pension and Other Postemployment Benefits," for additional details.

PENSION AND OTHER POST-EMPLOY_2

PENSION AND OTHER POST-EMPLOYMENT BENEFITS (Tables)	12 Months Ended
	Dec. 31, 2020
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Obligations and Funded Status	Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2020 2019 2020 2019 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 11,050 $ 9,462 $ 654 $ 608 Service cost 194 193 4 3 Interest cost 287 373 15 22 Plan participants’ contributions — — 4 4 Plan amendments 9 2 — — Special termination benefits — 14 — — Medicare retiree drug subsidy — — 1 1 Actuarial loss 1,011 1,535 41 64 Benefits paid (616) (529) (43) (48) Benefit obligation as of December 31 $ 11,935 $ 11,050 $ 676 $ 654 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 8,395 6,984 $ 458 408 Actual return on plan assets 1,165 1,419 60 73 Company contributions 24 521 23 21 Plan participants’ contributions — — 4 4 Benefits paid (616) (529) (43) (48) Fair value of plan assets as of December 31 $ 8,968 $ 8,395 $ 502 $ 458 Funded Status: Qualified plan $ (2,500) (2,203) $ — — Non-qualified plans (467) (452) — — Funded Status (Net liability as of December 31) $ (2,967) $ (2,655) $ (174) $ (196) Accumulated benefit obligation $ 11,376 $ 10,439 $ — $ — Amounts Recognized in AOCI: Prior service cost (credit) $ 12 $ 24 $ (39) $ (85) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 2.67 % 3.34 % 2.45 % 3.18 % Rate of compensation increase 4.10 % 4.10 % N/A N/A Cash balance weighted average interest crediting rate 2.57 % 2.57 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) N/A N/A 6.0%-5.5% 6.0%-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) N/A N/A 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate N/A N/A 2028 2028 Allocation of Plan Assets (as of December 31) Equity securities 23 % 29 % 55 % 54 % Fixed Income 35 % 36 % 28 % 30 % Hedge funds 7 % 9 % — % — % Insurance-linked securities 4 % 2 % — % — % Real estate funds 9 % 7 % — % — % Private equity funds 5 % 4 % — % — % Cash and short-term securities 17 % 13 % 17 % 16 % Total 100 % 100 % 100 % 100 %
Components of Net Periodic Benefit Costs	Components of Net Periodic Benefit Costs for the Years Ended December 31, Pension OPEB 2020 2019 2018 2020 2019 2018 (In millions) Service cost $ 194 $ 193 $ 224 $ 4 $ 3 $ 5 Interest cost 287 373 372 15 22 25 Expected return on plan assets (618) (540) (574) (33) (29) (31) Amortization of prior service costs (credits) (1) 12 7 7 (46) (36) (81) Special termination costs (2) — 14 31 — — 8 One-time termination benefits (3) 8 — — — — — Pension & OPEB mark-to-market 463 656 227 14 20 (82) Net periodic benefit costs (credits) $ 346 $ 703 $ 287 $ (46) $ (20) $ (156) (1) 2020 includes the acceleration of approximately $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. (2) 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. (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.
Assumptions Used to Determine Net Periodic Benefit Cost	Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December (1) Pension OPEB 2020 2019 2018 2020 2019 2018 Service cost weighted-average discount rate (2) 3.60%/3.24% 4.66 % 3.75 % 3.63%/3.29% 4.67 % 3.50 % Interest cost weighted-average discount rate (3) 3.27%/2.90% 4.37 % 3.75 % 2.71%/2.30% 3.89 % 3.50 % Expected long-term return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.10 % 4.10 % 4.20 % N/A N/A N/A (1) Excludes impact of pension and OPEB mark-to-market adjustment. (2) Weighted-average discount rates effect from January 1, 2020, through February 26, 2020, were 3.60% and 3.63% for pension and OPEB service cost, respectively. Discount rates were 3.24% and 3.29% for pension and OPEB service cost, respectively, for the period February 27, 2020 through December 31, 2020.
Target asset allocations for pension and OPEB portfolio	FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2020 and 2019 are shown in the following table: Target Asset Allocations 2020 2019 Equities 38 % 38 % Fixed income 30 % 30 % Hedge funds 8 % 8 % Real estate 10 % 10 % Alternative investments 8 % 8 % Cash 6 % 6 % 100 % 100 %
Estimated Future Benefit Payments	Taking into account estimated employee future service, FirstEnergy expects to make the following benefit payments from plan assets and other payments, net of participant contributions: OPEB Pension Benefit Payments Subsidy Receipts (In millions) 2021 $ 579 $ 49 $ (1) 2022 583 47 (1) 2023 598 46 (1) 2024 601 45 (1) 2025 610 44 (1) Years 2026-2030 3,129 197 (2)
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	The following tables set forth pension financial assets that are accounted for at fair value by level within the fair value hierarchy. See Note 10, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2020 and 2019. December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 1,493 $ — $ 1,493 17 % Equities 1,903 162 — 2,065 23 % Fixed income: Corporate bonds — 2,672 — 2,672 31 % Other (3) — 387 — 387 4 % Alternatives: Derivatives (13) — — (13) — % Total (1) $ 1,890 $ 4,714 $ — $ 6,604 75 % Private equity funds (2) 465 5 % Insurance-linked securities (2) 323 4 % Hedge funds (2) 645 7 % Real estate funds (2) 815 9 % Total Investments $ 8,852 100 % (1) Excludes $116 million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. (3) Includes insurance annuities, bank loans and emerging markets debt. December 31, 2019 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 1,069 $ — $ 1,069 13 % Equities 1,532 828 — 2,360 29 % Fixed income: Corporate bonds — 2,064 — 2,064 25 % Other (3) — 880 — 880 11 % Alternatives: Derivatives (40) — — (40) — % Total (1) $ 1,492 $ 4,841 $ — $ 6,333 78 % Private equity funds (2) 342 4 % Insurance-linked securities (2) 186 2 % Hedge funds (3) 774 9 % Real estate funds (2) 584 7 % Total Investments $ 8,219 100 % (1) Excludes $176 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. (2) Net Asset Value used as a practical expedient to approximate fair value. (3) Includes insurance annuities, bank loans and emerging markets debt.
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	As of December 31, 2020, and 2019, the OPEB trust investments measured at fair value were as follows: December 31, 2020 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 84 $ — $ 84 17 % Equity investment: Domestic 283 — — 283 55 % Fixed income: Government bonds — 104 — 104 20 % Corporate bonds — 34 — 34 7 % Mortgage-backed securities (non-government) 7 — 7 1 % Total (1) $ 283 $ 229 $ — $ 512 100 % (1) Excludes $(10) million as of December 31, 2020, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2019 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 72 $ — $ 72 16 % Equity investment: Domestic 246 — — 246 54 % Fixed income: Government bonds — 100 — 100 22 % Corporate bonds — 34 — 34 7 % Mortgage-backed securities (non-government) — 5 — 5 1 % Total (1) $ 246 $ 211 $ — $ 457 100 % (1) Excludes $1 million as of December 31, 2019, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

STOCK-BASED COMPENSATION PLANS

STOCK-BASED COMPENSATION PLANS (Tables)	12 Months Ended
	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Stock-based Compensation Expense	Stock-based compensation costs and the amount of stock-based compensation costs capitalized related to FirstEnergy plans for the years ended December 31, 2020, 2019 and 2018, are included in the following tables: For the Years Ended December 31, Stock-based Compensation Plan 2020 2019 2018 (In millions) Restricted Stock Units $ 22 $ 73 $ 102 Restricted Stock 1 1 1 401(k) Savings Plan 33 33 33 EDCP & DCPD (5) 9 7 Total $ 51 $ 116 $ 143 Stock-based compensation costs capitalized $ 26 $ 54 $ 60
Schedule of Nonvested Restricted Stock Units Activity	Restricted stock unit activity for the year ended December 31, 2020, was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2020 2.6 $ 36.20 Granted in 2020 1.6 44.42 Forfeited in 2020 (0.6) 39.15 Vested in 2020 (1) (1.8) 44.40 Nonvested as of December 31, 2020 1.8 $ 40.25 (1)
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Schedule of Stock Option Activity	There were no stock options granted in 2020. Stock option activity for the year ended December 31, 2020 was as follows: Stock Option Activity Number of Shares (in millions) Weighted Average Exercise Price (per share) Balance, January 1, 2020 (all options exercisable) 0.1 $ 37.75 Options exercised — — Options forfeited (0.1) 37.75 Balance, December 31, 2020 (all options exercisable) — $ —

TAXES (Tables)

TAXES (Tables)	12 Months Ended
	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Provision for income taxes (benefits)	For the Years Ended December 31, INCOME TAXES (1) 2020 2019 2018 (In millions) Currently payable (receivable)- Federal (2) $ (14) $ (16) $ (16) State (3) 21 24 17 7 8 1 Deferred, net- Federal (4) 171 150 252 State (5) (38) 60 243 133 210 495 Investment tax credit amortization (14) (5) (6) Total income taxes $ 126 $ 213 $ 490 (1) Income Taxes on Income from Continuing Operations. (2) Excludes $6 million of federal tax expense associated with discontinued operations for the year ended December 31, 2020. (3) Excludes $1 million of state tax expense associated with discontinued operations for the year ended December 31, 2018. (4) Excludes $66 million, $9 million and $1.3 billion of federal tax benefit associated with discontinued operations for the years ended December 31, 2020, 2019 and 2018, respectively. (5) Excludes $1 million, $4 million and $12 million of state tax expense associated with discontinued operations for the years ended December 31, 2020, 2019 and 2018, respectively.
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes	The following tables provide a reconciliation of federal income tax expense (benefit) at the federal statutory rate to the total income taxes (benefits) for the years ended December 31, 2020, 2019 and 2018: For the Years Ended December 31, 2020 2019 2018 (In millions) Income from Continuing Operations, before income taxes $ 1,129 $ 1,117 $ 1,512 Federal income tax expense at statutory rate (21%) $ 237 $ 235 $ 318 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 75 96 90 AFUDC equity and other flow-through (38) (36) (31) Amortization of investment tax credits (14) (5) (5) Remeasurement of deferred taxes — — 24 WV unitary group remeasurement — — 126 Excess deferred tax amortization due to the Tax Act (56) (74) (60) TMI-2 reversal of tax regulatory liabilities (40) — — Uncertain tax positions (1) (11) 2 Valuation allowances (49) 5 21 Other, net 12 3 5 Total income taxes $ 126 $ 213 $ 490 Effective income tax rate 11.2 % 19.1 % 32.4 %
Accumulated deferred income taxes	Accumulated deferred income taxes as of December 31, 2020 and 2019, are as follows: As of December 31, 2020 2019 (In millions) Property basis differences $ 5,396 $ 5,037 Pension and OPEB (769) (698) TMI-2 nuclear decommissioning — 89 AROs (28) (226) Regulatory asset/liability 440 445 Deferred compensation (165) (154) Estimated worthless stock deduction — (1,007) Loss carryforwards and AMT credits (1,995) (836) Valuation reserve 496 441 All other (280) (242) Net deferred income tax liability $ 3,095 $ 2,849
Pre-tax net operating loss expiration period	Expiration Period State Local (In millions) 2021-2025 $ 2,253 $ 4,353 2026-2030 1,447 — 2031-2035 1,152 — 2036-2040 1,087 — Indefinite 2,091 — $ 8,030 $ 4,353
Valuation allowance roll forward	The following table summarizes the changes in valuation allowances on federal, state and local DTAs related to disallowed interest and certain employee remuneration, in addition to state and local NOLs discussed above for the years ended December 31, 2020, 2019 and 2018: (In millions) 2020 2019 2018 Beginning of year balance $ 441 $ 394 $ 312 Charged to income 55 47 82 Charged to other accounts — — — Write-offs — — — End of year balance $ 496 $ 441 $ 394
Changes in unrecognized tax benefits	The following table summarizes the changes in unrecognized tax positions for the years ended December 31, 2020, 2019 and 2018: (In millions) Balance, January 1, 2018 $ 80 Current year increases 125 Prior year decreases (45) Decrease for lapse in statute (2) Balance, December 31, 2018 $ 158 Current year increases 22 Prior year decreases (12) Decrease for lapse in statute (4) Balance, December 31, 2019 $ 164 Current year increases 7 Prior years decreases (28) Decrease for lapse in statute (2) Effectively settled with taxing authorities (2) Balance, December 31, 2020 $ 139
Details of general taxes	General tax expense for the years ended December 31, 2020, 2019 and 2018, recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2020 2019 2018 (In millions) KWH excise $ 183 $ 191 $ 198 State gross receipts 182 185 192 Real and personal property 541 504 478 Social security and unemployment 112 100 103 Other 28 28 22 Total general taxes $ 1,046 $ 1,008 $ 993

LEASES (Tables)

LEASES (Tables)	12 Months Ended
	Dec. 31, 2020
Leases [Abstract]
Components of Lease Expense	The components of lease expense were as follows: For the Year Ended December 31, 2020 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 35 $ 8 $ 17 $ 60 Finance lease costs: Amortization of right-of-use assets 14 — 1 15 Interest on lease liabilities 2 3 — 5 Total finance lease cost 16 3 1 20 Total lease cost $ 51 $ 11 $ 18 $ 80 (1) Includes $17 million of short-term lease costs. For the Year Ended December 31, 2019 (In millions) Vehicles Buildings Other Total Operating lease costs (1) $ 28 $ 9 $ 12 $ 49 Finance lease costs: Amortization of right-of-use assets 15 1 1 17 Interest on lease liabilities 3 3 — 6 Total finance lease cost 18 4 1 23 Total lease cost $ 46 $ 13 $ 13 $ 72 (1) Includes $13 million of short-term lease costs. Supplemental cash flow information related to leases was as follows: For the Years Ended, (In millions) December 31, 2020 December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 44 $ 29 Operating cash flows from finance leases 4 5 Finance cash flows from finance leases 15 25 Right-of-use assets obtained in exchange for lease obligations: Operating leases $ 67 $ 83 Finance leases — 3 Maturities of lease liabilities as of December 31, 2020, were as follows: (In millions) Operating Leases Finance Leases Total 2021 $ 50 $ 18 $ 68 2022 49 15 64 2023 46 8 54 2024 38 4 42 2025 36 4 40 Thereafter 147 12 159 Total lease payments (1) 366 61 427 Less imputed interest 61 16 77 Total net present value $ 305 $ 45 $ 350 (1) Operating lease payments for certain leases are offset by sublease receipts of $11 million over 12 years.
Assets and Liabilities, Lessee	Lease terms and discount rates were as follows: As of December 31, 2020 As of December 31, 2019 Weighted-average remaining lease terms (years) Operating leases 8.55 9.42 Finance leases 7.74 4.62 Weighted-average discount rate (1) Operating leases 4.21 % 4.51 % Finance leases 11.58 % 10.45 % (1) When an implicit rate is not readily determinable, an incremental borrowing rate is utilized, determining the present value of lease payments. The rate is determined based on expected term and information available at the commencement date. Supplemental balance sheet information related to leases was as follows: As of December 31, (In millions) Financial Statement Line Item 2020 2019 Assets Operating lease (1) Deferred charges and other assets $ 265 $ 231 Finance lease (2) Property, plant and equipment 57 73 Total leased assets $ 322 $ 304 Liabilities Current: Operating Other current liabilities $ 42 $ 32 Finance Currently payable long-term debt 14 15 Noncurrent: Operating Other noncurrent liabilities 263 241 Finance Long-term debt and other long-term obligations 31 45 Total leased liabilities $ 350 $ 333 (1) Operating lease assets are recorded net of accumulated amortization of $51 million and $23 million as of December 31, 2020 and 2019, respectively.
Maturity of Operating Lease Liabilities	Maturities of lease liabilities as of December 31, 2020, were as follows: (In millions) Operating Leases Finance Leases Total 2021 $ 50 $ 18 $ 68 2022 49 15 64 2023 46 8 54 2024 38 4 42 2025 36 4 40 Thereafter 147 12 159 Total lease payments (1) 366 61 427 Less imputed interest 61 16 77 Total net present value $ 305 $ 45 $ 350 (1) Operating lease payments for certain leases are offset by sublease receipts of $11 million over 12 years.
Maturity of Finance Lease Liabilities	Maturities of lease liabilities as of December 31, 2020, were as follows: (In millions) Operating Leases Finance Leases Total 2021 $ 50 $ 18 $ 68 2022 49 15 64 2023 46 8 54 2024 38 4 42 2025 36 4 40 Thereafter 147 12 159 Total lease payments (1) 366 61 427 Less imputed interest 61 16 77 Total net present value $ 305 $ 45 $ 350 (1) Operating lease payments for certain leases are offset by sublease receipts of $11 million over 12 years.

INTANGIBLE ASSETS (Tables)

INTANGIBLE ASSETS (Tables)	12 Months Ended
	Dec. 31, 2020
Goodwill and Intangible Assets Disclosure [Abstract]
Future Amortization	As of December 31, 2020, intangible assets classified in Other Deferred Charges on FirstEnergy’s Consolidated Balance Sheets include the following: Intangible Assets Amortization Expense Actual Estimated (In millions) Gross Accumulated Amortization Net 2020 2021 2022 2023 2024 2025 Thereafter NUG contracts (1) $ 124 $ 51 $ 73 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 48 Coal contracts (2) 102 102 — 2 — — — — — — $ 226 $ 153 $ 73 $ 7 $ 5 $ 5 $ 5 $ 5 $ 5 $ 48 (1) NUG contracts are subject to regulatory accounting and their amortization does not impact earnings. (2) The coal contracts were recorded with a regulatory offset and their amortization does not impact earnings.

FAIR VALUE MEASUREMENTS (Tables

FAIR VALUE MEASUREMENTS (Tables)	12 Months Ended
	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Assets and liabilities measured on recurring basis	The following tables set forth the recurring assets and liabilities that are accounted for at fair value by level within the fair value hierarchy: December 31, 2020 December 31, 2019 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ — $ — $ — $ — $ 135 $ — $ 135 Derivative assets FTRs (1) — — 3 3 — — 4 4 Equity securities 2 — — 2 2 — — 2 U.S. state debt securities — 276 — 276 — 271 — 271 Other (2) 1,734 41 — 1,775 627 789 — 1,416 Total assets $ 1,736 $ 317 $ 3 $ 2,056 $ 629 $ 1,195 $ 4 $ 1,828 Liabilities Derivative liabilities FTRs (1) $ — $ — $ — $ — $ — $ — $ (1) $ (1) Derivative liabilities NUG contracts (1) — — — — — — (16) (16) Total liabilities $ — $ — $ — $ — $ — $ — $ (17) $ (17) Net assets (liabilities) (3) $ 1,736 $ 317 $ 3 $ 2,056 $ 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 $1 million and $(16) million as of December 31, 2020, and December 31, 2019, respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the years ended December 31, 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 gain (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 gain (loss) — (3) (3) (3) — (3) Purchases — — — 7 (2) 5 Settlements — 19 19 (5) 3 (2) December 31, 2020 Balance $ — $ — $ — $ 3 $ — $ 3 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs contracts that are classified as Level 3 in the fair value hierarchy for the year ended December 31, 2020: Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 3 Model RTO auction clearing prices $0.40 to $2.20 $1.10 Dollars/MWH
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities	The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2020 and December 31, 2019: December 31, 2020 (1) December 31, 2019 (2) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (3) (In millions) Debt securities $ 275 $ 7 $ (6) $ 276 $ 403 $ 9 $ (11) $ 401 (1) Excludes short-term cash investments of $9 million. (2) Excludes short-term cash investments of $751 million, of which $747 million is classified as held for sale. (3) Includes $135 million classified as held for sale as of December 31, 2019.
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the years ended December 31, 2020, 2019 and 2018, were as follows: For the Years Ended December 31, 2020 2019 (1) 2018 (1) (In millions) Sale Proceeds $ 186 $ 1,637 $ 800 Realized Gains 12 98 41 Realized Losses (8) (31) (48) Interest and Dividend Income 22 38 41 (1) Excludes amounts classified as discontinued operations.
Fair value and related carrying amounts of long-term debt and other long-term obligations	The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes finance lease obligations and net unamortized debt issuance costs, unamortized fair value adjustments, premiums and discounts as of December 31, 2020 and 2019: As of December 31, 2020 2019 (In millions) Carrying Value (1) $ 22,377 $ 20,066 Fair Value 25,465 22,928 ( 1) The carrying value as of December 31, 2020, includes $3,425 million of debt issuances and $1,114 million of redemptions that occurred during 2020.

CAPITALIZATION (Tables)

CAPITALIZATION (Tables)	12 Months Ended
	Dec. 31, 2020
Capitalization, Long-term Debt and Equity [Abstract]
Preferred stock and preference stock authorizations	FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2020, as follows: Preferred Stock Preference Stock Shares Authorized Par Value Shares Authorized Par Value FE 5,000,000 $ 100 OE 6,000,000 $ 100 8,000,000 no par OE 8,000,000 $ 25 Penn 1,200,000 $ 100 CEI 4,000,000 no par 3,000,000 no par TE 3,000,000 $ 100 5,000,000 $ 25 TE 12,000,000 $ 25 JCP&L 15,600,000 no par ME 10,000,000 no par PN 11,435,000 no par MP 940,000 $ 100 PE 10,000,000 $ 0.01 WP 32,000,000 no par
Outstanding consolidated long-term debt and other long-term obligations	The following tables present outstanding long-term debt and finance lease obligations for FirstEnergy as of December 31, 2020 and 2019: As of December 31, 2020 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2020 2019 FMBs and secured notes - fixed rate 2021-2059 2.670% - 8.250% $ 4,802 $ 4,741 Unsecured notes - fixed rate 2022-2050 1.600% - 7.375% 17,575 14,575 Unsecured notes - variable rate — 750 Finance lease obligations 45 60 Unamortized debt discounts (34) (33) Unamortized debt issuance costs (118) (103) Unamortized fair value adjustments 7 8 Currently payable long-term debt (146) (380) Total long-term debt and other long-term obligations $ 22,131 $ 19,618
Sinking fund requirements for FMBs and maturing long-term debt (excluding capital leases and variable rate PCRBs) for the next five years	The following table presents scheduled debt repayments for outstanding long-term debt, excluding finance leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2020. PCRBs that are scheduled to be tendered for mandatory purchase prior to maturity are reflected in the applicable year in which such PCRBs are scheduled to be tendered. Year (In millions) 2021 $ 132 2022 $ 1,143 2023 $ 1,194 2024 $ 1,246 2025 $ 2,023

ASSET RETIREMENT OBLIGATIONS (T

ASSET RETIREMENT OBLIGATIONS (Tables)	12 Months Ended
	Dec. 31, 2020
Asset Retirement Obligation [Abstract]
Changes to the asset retirement obligations	The following table summarizes the changes to the ARO balances during 2020 and 2019: ARO Reconciliation (In millions) Balance, January 1, 2019 $ 812 Liabilities settled (2) Accretion 46 Balance, December 31, 2019 (1) $ 856 Liabilities settled (2) (744) Accretion 47 Balance, December 31, 2020 $ 159 (1) Includes $691 million related to TMI-2 classified as held for sale for the year ended December 31, 2019. (2) Includes $726 million related to the closing of the asset purchase and sale agreement with TMI-2 Solutions, LLC, a subsidiary of Energy Solutions , LLC, concerning the transfer and dismantlement of TMI-2. See Note 15, "Commitments, Guarantees and Contingencies," for further information.

REGULATORY MATTERS (Tables)

REGULATORY MATTERS (Tables)	12 Months Ended
	Dec. 31, 2020
Regulated Operations [Abstract]
Distribution Rate Orders	The following table summarizes the key terms of base distribution rate orders in effect for the Utilities as of December 31, 2020: Company Rates Effective Allowed Debt/Equity Allowed ROE CEI May 2009 51% / 49% 10.5% ME (1) January 2017 48.8% / 51.2% Settled (2) MP February 2015 54% / 46% Settled (2) JCP&L (3) January 2017 55% / 45% 9.6% OE January 2009 51% / 49% 10.5% PE (West Virginia) February 2015 54% / 46% Settled (2) PE (Maryland) March 2019 47% / 53% 9.65% PN (1) January 2017 47.4% / 52.6% Settled (2) Penn (1) January 2017 49.9% / 50.1% Settled (2) TE January 2009 51% / 49% 10.5% WP (1) January 2017 49.7% / 50.3% Settled (2) (1) Reflects filed debt/equity as final settlement/orders do not specifically include capital structure. (2) Commission-approved settlement agreements did not disclose ROE rates. (3) On October 28, 2020, the NJBPU approved JCP&L's distribution rate case settlement with an allowed ROE of 9.6% and a 48.56% debt / 51.44% equity capital structure. Rates are effective for customers on November 1, 2021, but beginning January 1, 2021, JCP&L will offset the impact to customers' bills by amortizing an $86 million regulatory liability. The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities as of December 31, 2020: Company Rates Effective Capital Structure Allowed ROE ATSI January 1, 2015 Actual (13-month average) 10.38% JCP&L January 2020 (1) Actual (13-month average) (1) 10.80% (1) MP March 21, 2018 (2)(4) Settled (2)(3) Settled (2)(3) PE March 21, 2018 (2)(4) Settled (2)(3) Settled (2)(3) WP March 21, 2018 (2)(4) Settled (2)(3) Settled (2)(3) MAIT July 1, 2017 Lower of Actual (13-month average) or 60% 10.3% TrAIL July 1, 2008 Actual (year-end) 12.7% (TrAIL the Line & Black Oak SVC) (1) As filed in docket ER20-227, effective on January 1, 2020, which has been accepted by FERC, subject to refund, pending further hearing and settlement procedures. The settlement agreement that was filed on February 2, 2021, seeking approval by FERC sets JCP&L's Allowed ROE at 10.2%. (2) Effective on January 1, 2021, MP, PE, and WP have implemented a forward-looking formula rate, which has been accepted by FERC, subject to refund, pending further hearing and settlement procedures. (3) FERC-approved settlement agreements did not specify. (4) See FERC Actions on Tax Act below.

COMMITMENTS, GUARANTEES AND C_2

COMMITMENTS, GUARANTEES AND CONTINGENCIES (Tables)	12 Months Ended
	Dec. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Schedule of Guarantor Obligations	The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2020: Potential Collateral Obligations Utilities FE Total (In millions) Contractual Obligations for Additional Collateral Upon Further Downgrade $ 37 $ — $ 37 Surety Bonds (Collateralized Amount) (1) 55 258 313 Total Exposure from Contractual Obligations $ 92 $ 258 $ 350 (1) Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations, which is ordinarily 100% of the face amount of the surety bond except with the respect to $39 million of surety obligations for which the collateral obligation is capped at 60% of the face amount, and typical obligations require 30 days to cure.

SEGMENT INFORMATION (Tables)

SEGMENT INFORMATION (Tables)	12 Months Ended
	Dec. 31, 2020
Segment Reporting [Abstract]
Segment Financial Information	Segment Financial Information For the Years Ended Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) December 31, 2020 External revenues $ 9,168 $ 1,613 $ 9 $ — $ 10,790 Internal revenues 195 17 — (212) — Total revenues 9,363 1,630 9 (212) 10,790 Provision for depreciation 896 313 4 61 1,274 Amortization (deferral) of regulatory assets, net (64) 11 — — (53) Miscellaneous income (expense), net 332 30 83 (13) 432 Interest expense 501 219 358 (13) 1,065 Income taxes (benefits) 113 138 (125) — 126 Income (loss) from continuing operations 959 464 (420) — 1,003 Property additions $ 1,514 $ 1,067 $ 76 $ — $ 2,657 December 31, 2019 External revenues $ 9,511 $ 1,510 $ 14 $ — $ 11,035 Internal revenues 187 16 — (203) — Total revenues 9,698 1,526 14 (203) 11,035 Provision for depreciation 863 284 5 68 1,220 Amortization (deferral) of regulatory assets, net (89) 10 — — (79) Miscellaneous income (expense), net 174 15 80 (26) 243 Interest expense 495 192 372 (26) 1,033 Income taxes (benefits) 271 113 (171) — 213 Income (loss) from continuing operations 1,076 447 (619) — 904 Property additions $ 1,473 $ 1,090 $ 102 $ — $ 2,665 December 31, 2018 External revenues $ 9,900 $ 1,335 $ 26 $ — $ 11,261 Internal revenues 203 18 8 (229) — Total revenues 10,103 1,353 34 (229) 11,261 Provision for depreciation 812 252 3 69 1,136 Amortization (deferral) of regulatory assets, net (163) 13 — — (150) Miscellaneous income (expense), net 192 14 32 (33) 205 Interest expense 514 167 468 (33) 1,116 Income taxes 422 122 (54) — 490 Income (loss) from continuing operations 1,242 397 (617) — 1,022 Property additions $ 1,411 $ 1,104 $ 133 $ 27 $ 2,675 As of December 31, 2020 Total assets $ 30,855 $ 12,592 $ 1,017 $ — $ 44,464 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

ORGANIZATION AND BASIS OF PRE_4

ORGANIZATION AND BASIS OF PRESENTATION - Accounts Receivable (Details) - USD ($) $ in Millions	Feb. 27, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Deferred for recovery		$ 103	$ 25	$ 24
Customer Receivables
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance		46	50	49
Charged to income		174	81	77
Charged to other accounts		46	47	60
Write-offs		(102)	(132)	(136)
Ending balance		164	46	50
Other Receivables
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance		21	2	1
Charged to income		7	27	13
Charged to other accounts		10	1	0
Write-offs		(12)	(9)	(12)
Ending balance		26	21	2
Affiliated companies
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance		1,063	920	0
Charged to income		0	143	920
Charged to other accounts		0	0	0
Write-offs		(1,063)	0	0
Ending balance		$ 0	$ 1,063	$ 920
Affiliated companies | FES
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Write-offs	$ (1,100)

ORGANIZATION AND BASIS OF PRE_5

ORGANIZATION AND BASIS OF PRESENTATION - Narrative (Details) customer in Millions	12 Months Ended
	Dec. 31, 2020USD ($)mi²entitycustomertransmission_centeragreementcompanyMWshares	Dec. 31, 2019USD ($)shares	Dec. 31, 2018USD ($)MWshares	Jun. 30, 2013USD ($)
Regulatory Assets [Line Items]
Concentration of risk of accounts receivable	$ 0	$ 0
Increase (decrease) in allowance for credit loss,	121,000,000
Regulatory assets based on prior precedent or anticipated recovery based on rate making premises with specific order	117,000,000	111,000,000
Regulatory assets being sought for recovery in a formula rate amendment	$ 79,000,000	$ 73,000,000
Annual composite depreciation rate	2.70%	2.70%	2.60%
Capitalized financing costs	$ 49,000,000	$ 45,000,000	$ 46,000,000
Interest costs capitalized	28,000,000	26,000,000	19,000,000
Property, plant and equipment	$ 33,294,000,000	31,650,000,000
Number of contracts that may contain variable interest | entity	1
Purchased power	$ 2,701,000,000	2,927,000,000	$ 3,109,000,000
Number of regional transmission centers | transmission_center	2
Regulatory assets currently being recovered through deferred returns	$ 195,000,000	228,000,000
Power Purchase Agreements
Regulatory Assets [Line Items]
Ownership interest	0.00%
Number of long term power purchase agreements maintained by parent company with Non utility generation entities | agreement	6
Global Holding
Regulatory Assets [Line Items]
Equity method investments	$ 30,000,000
Path-WV | Variable Interest Entity, Not Primary Beneficiary
Regulatory Assets [Line Items]
Equity method investments	$ 18,000,000
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series	100.00%
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series	50.00%
Phase In Recovery Bonds
Regulatory Assets [Line Items]
Long-term debt and other long-term obligations	$ 245,000,000	268,000,000
Line of Credit | Term Loan Facility Due March 2020 | Global Holding
Regulatory Assets [Line Items]
Face amount of loan	120,000,000
Line of Credit | Revolving Credit Facility
Regulatory Assets [Line Items]
Maximum amount borrowed under revolving credit facility	$ 3,500,000,000
Ohio Funding Companies | Phase In Recovery Bonds
Regulatory Assets [Line Items]
Face amount of loan				$ 445,000,000
FEV | Signal Peak | Global Holding
Regulatory Assets [Line Items]
Ownership interest	33.33%
Global Holding | Senior Loans | Senior Secured Term Loan
Regulatory Assets [Line Items]
Long-term debt and other long-term obligations	$ 108,000,000
Other FE subsidiaries | Power Purchase Agreements
Regulatory Assets [Line Items]
Purchased power	$ 113,000,000	$ 116,000,000
Bath County, Virginia
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW	3,003
Bath County, Virginia | AGC
Regulatory Assets [Line Items]
Proportionate ownership share	16.25%
Plant generation capacity (in MW's) | MW	487
Property, plant and equipment	$ 157,000,000
Bath County, Virginia | Virginia Electric and Power Company
Regulatory Assets [Line Items]
Proportionate ownership share	60.00%
Utilities and FET
Regulatory Assets [Line Items]
Property, plant and equipment, net	$ 2,100,000,000
Plant generation capacity (in MW's) | MW	3,790
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
Service Area | mi²	65,000
Utilities and FET | Yard's Creek Energy, LLC Hydro Generation Facility
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW	210
Regulated Transmission
Regulatory Assets [Line Items]
Service Area | mi²	24,500
Pleasants Power Station | AE Supply | Purchase Agreement with Subsidiary of LS Power
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW			1,300
Disposal Group, Held-for-sale | TMI-2 | Utilities and FET
Regulatory Assets [Line Items]
Assets held-for-sale	$ 882,000,000
Stock Options
Regulatory Assets [Line Items]
Antidilutive securities excluded from computation of EPS (in shares) | shares	80,000	0	1,000,000
Future Recovery of Incremental Costs
Regulatory Assets [Line Items]
Increase (decrease) in allowance for credit loss,	$ 90,000,000

ORGANIZATION AND BASIS OF PRE_6

ORGANIZATION AND BASIS OF PRESENTATION - Receivables from Customers (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Receivables from customers
Customers	$ 1,203	$ 1,091
Billed
Receivables from customers
Customers	636	564
Unbilled
Receivables from customers
Customers	$ 567	$ 527

ORGANIZATION AND BASIS OF PRE_7

ORGANIZATION AND BASIS OF PRESENTATION - Regulatory Assets on the Balance Sheet (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Regulatory assets on the Balance Sheets
Regulatory Liability	$ (1,826)	$ (2,360)
Regulatory Assets	82	99
Net Regulatory Liabilities included on the Consolidated Balance Sheets	(1,744)	(2,261)
Change	517
Regulatory Assets by Source Not Earning a Current Return	789	545
Change	244
Customer payables for future income taxes
Regulatory assets on the Balance Sheets
Regulatory Liability	(2,369)	(2,605)
Change	236
Nuclear decommissioning and spent fuel disposal costs
Regulatory assets on the Balance Sheets
Regulatory Liability	(102)	(197)
Change	95
Asset removal costs
Regulatory assets on the Balance Sheets
Regulatory Liability	(721)	(756)
Change	35
Deferred transmission costs
Regulatory assets on the Balance Sheets
Regulatory Assets	316	298
Change	18
Regulatory Assets by Source Not Earning a Current Return	29	27
Change	2
Deferred generation costs
Regulatory assets on the Balance Sheets
Regulatory Assets	104	214
Change	(110)
Regulatory Assets by Source Not Earning a Current Return	5	15
Change	(10)
Deferred distribution costs
Regulatory assets on the Balance Sheets
Regulatory Assets	136	155
Change	(19)
Contract valuations
Regulatory assets on the Balance Sheets
Regulatory Assets	41	51
Change	(10)
Storm-related costs
Regulatory assets on the Balance Sheets
Regulatory Assets	748	551
Change	197
Regulatory Assets by Source Not Earning a Current Return	654	471
Change	183
Uncollectible and COVID-19 related costs
Regulatory assets on the Balance Sheets
Regulatory Assets	97	3
Change	94
Regulatory Assets by Source Not Earning a Current Return	66	0
Change	66
Other
Regulatory assets on the Balance Sheets
Regulatory Assets	6	25
Change	(19)
Regulatory Assets by Source Not Earning a Current Return	35	$ 32
Change	$ 3

ORGANIZATION AND BASIS OF PRE_8

ORGANIZATION AND BASIS OF PRESENTATION - Reconciliation of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
EPS of Common Stock
Income from continuing operations		$ 1,003	$ 904	$ 1,022
Less: Preferred dividends		0	(3)	(71)
Less: Amortization of beneficial conversion feature		0	0	(296)
Less: Undistributed earnings allocated to preferred shareholders			(1)	0
Income from continuing operations available to common stockholders		1,003	900	655
Discontinued operations, net of tax	[1]	76	8	326
Less: Undistributed earnings allocated to preferred shareholders			0	0
Income from discontinued operations available to common stockholders		76	8	326
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS		1,079	908	981
Income allocated to preferred shareholders, preferred dilutive			4
Income attributable to common stockholders, dilutive		$ 1,079	$ 912	$ 981
Share Count information:
Weighted average number of basic shares outstanding (in shares)		542	535	492
Assumed exercise of dilutive stock options and awards (in shares)		1	3	2
Assumed conversion of preferred stock (in shares)		0	4	0
Weighted average number of diluted shares outstanding (in shares)		543	542	494
Income attributable to common stockholders, per common share:
Income from continuing operations, basic (in dollars per share)		$ 1.85	$ 1.69	$ 1.33
Discontinued operations, basic (in dollars per share)		0.14	0.01	0.66
Basic - Net Income Attributable to Common Stockholders (in dollars per share)		1.99	1.70	1.99
Income from continuing operations, diluted (in dollars per share)		1.85	1.67	1.33
Discontinued operations, diluted (in dollars per share)		0.14	0.01	0.66
Diluted - Net Income Attributable to Common Stockholders (in dollars per share)		$ 1.99	$ 1.68	$ 1.99
Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of EPS (in shares)		26
[1]	Net of income tax benefit of $59 million, $5 million, and $1.3 billion in 2020, 2019 and 2018, respectively.

ORGANIZATION AND BASIS OF PRE_9

ORGANIZATION AND BASIS OF PRESENTATION - Property, Plant and Equipment Balances (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment
In Service	$ 43,726	$ 41,767
Accum. Depr.	(11,965)	(11,427)
Net Plant	31,761	30,340
CWIP	1,578	1,310
Total	33,339	31,650
Capital leased assets	153	163
Utilities and FET
Property, Plant and Equipment
In Service	29,775	28,735
Accum. Depr.	(8,800)	(8,540)
Net Plant	20,975	20,195
CWIP	841	744
Total	21,816	20,939
Regulated Transmission
Property, Plant and Equipment
In Service	12,912	12,023
Accum. Depr.	(2,609)	(2,383)
Net Plant	10,303	9,640
CWIP	671	526
Total	10,974	10,166
Corporate/Other
Property, Plant and Equipment
In Service	1,039	1,009
Accum. Depr.	(556)	(504)
Net Plant	483	505
CWIP	66	40
Total	$ 549	$ 545

ORGANIZATION AND BASIS OF PR_10

ORGANIZATION AND BASIS OF PRESENTATION - Summary of Changes in Goodwill (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
Goodwill	$ 5,618	$ 5,618
Utilities and FET
Goodwill [Line Items]
Goodwill	5,004
Regulated Transmission
Goodwill [Line Items]
Goodwill	$ 614

REVENUE (Details)

REVENUE (Details) $ in Millions		12 Months Ended
		Dec. 31, 2020USD ($)companyMW	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		$ 10,701	$ 10,805	$ 10,944
ARP		43	181	254
Other non-customer revenue		46	49	63
Total revenues	[1]	$ 10,790	11,035	11,261
Utility customer payment period		30 days
Other Non-Customer Revenue
Disaggregation of Revenue [Line Items]
Late payment charges		$ 31	37	39
Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		5,171	5,050	5,055
Total revenues		8,688	8,720	8,937
Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		3,517	3,670	3,882
Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		260	423	524
Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		1,613	1,510	1,335
Total revenues		1,613	1,510	1,335
Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		140	152	148
Total revenues		489	805	989
Derivative Revenue | Other Non-Customer Revenue
Disaggregation of Revenue [Line Items]
Total revenues		$ 14	8	18
Utilities and FET
Disaggregation of Revenue [Line Items]
Number of existing utility operating companies | company		10
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW		3,790
Utilities and FET | Yard's Creek Energy, LLC Hydro Generation Facility
Disaggregation of Revenue [Line Items]
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW		210
Utilities and FET | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues		$ 8,836	8,860	9,095
Utilities and FET | Retail generation | Residential
Disaggregation of Revenue [Line Items]
Total revenues		5,539	5,412	5,598
Utilities and FET | Retail generation | Commercial
Disaggregation of Revenue [Line Items]
Total revenues		2,140	2,252	2,350
Utilities and FET | Retail generation | Industrial
Disaggregation of Revenue [Line Items]
Total revenues		1,076	1,106	1,056
Utilities and FET | Retail generation | Other
Disaggregation of Revenue [Line Items]
Total revenues		81	90	91
Regulated Transmission
Disaggregation of Revenue [Line Items]
Total revenues		1,613	1,510	1,335
Regulated Transmission | Other
Disaggregation of Revenue [Line Items]
Total revenues		134	130	125
Regulated Transmission | ATSI
Disaggregation of Revenue [Line Items]
Total revenues		804	754	664
Regulated Transmission | TrAIL
Disaggregation of Revenue [Line Items]
Total revenues		247	242	237
Regulated Transmission | MAIT
Disaggregation of Revenue [Line Items]
Total revenues		250	224	150
Regulated Transmission | JCP&L
Disaggregation of Revenue [Line Items]
Total revenues		178	160	159
Operating Segments | Utilities and FET
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		9,227	9,421	9,741
ARP		43	181	254
Other non-customer revenue		93	96	108
Total revenues		9,363	9,698	10,103
Reduction in revenue		2	16	131
Operating Segments | Utilities and FET | Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		5,259	5,133	5,159
Operating Segments | Utilities and FET | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		3,577	3,727	3,936
Operating Segments | Utilities and FET | Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		251	411	502
Operating Segments | Utilities and FET | Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0
Operating Segments | Utilities and FET | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		140	150	144
Operating Segments | Regulated Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		1,613	1,510	1,335
ARP		0	0	0
Other non-customer revenue		17	16	18
Total revenues		1,630	1,526	1,353
Reduction in revenue		7	19	16
Operating Segments | Regulated Transmission | Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0
Operating Segments | Regulated Transmission | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0
Operating Segments | Regulated Transmission | Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0
Operating Segments | Regulated Transmission | Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		1,613	1,510	1,335
Operating Segments | Regulated Transmission | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0
Corporate/Other and Reconciling Adjustments
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		(139)	(126)	(132)
ARP		0	0	0
Other non-customer revenue		(64)	(63)	(63)
Total revenues		(203)	(189)	(195)
Corporate/Other and Reconciling Adjustments | Distribution services
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		(88)	(83)	(104)
Corporate/Other and Reconciling Adjustments | Retail generation
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		(60)	(57)	(54)
Corporate/Other and Reconciling Adjustments | Wholesale sales
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		9	12	22
Corporate/Other and Reconciling Adjustments | Transmission
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		0	0	0
Corporate/Other and Reconciling Adjustments | Other
Disaggregation of Revenue [Line Items]
Total revenues from contracts with customers		$ 0	$ 2	$ 4
[1]	Includes excise and gross receipts tax collections of $362 million, $373 million and $386 million in 2020, 2019 and 2018, respectively.

DISCONTINUED OPERATIONS - Narra

DISCONTINUED OPERATIONS - Narrative (Details) $ in Millions	Feb. 27, 2020USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2020USD ($)	Sep. 30, 2020USD ($)	Mar. 31, 2020USD ($)	Feb. 20, 2020USD ($)	Dec. 31, 2018MW
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Worthless stock deduction	$ 4,900
Unrecognized tax benefits from worthless stock deduction	316
Worthless stock deduction, net of tax	1,100
Unrecognized tax benefits from worthless stock deduction, net of tax	72
Adjustments related to intercompany tax sharing			$ 12	$ 6
Disposal Group, Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from asset sales					$ 65
State and Local
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Worthless stock deduction, net of tax	80
AE Supply | Purchase Agreement with Subsidiary of LS Power | Pleasants Power Station
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant generation capacity (in MW's) | MW							1,300
IT Access Agreement | Affiliated companies | FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount paid to settle claims	$ 125					$ 125
FES Key Creditor Groups | Affiliated companies | FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amount paid to settle claims						$ 853
Debtor Reorganization Items, Discharge of Claims and Liabilities		$ 853

DISCONTINUED OPERATIONS - Summa

DISCONTINUED OPERATIONS - Summarized Results of Discontinued Operations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax expense (benefit)		$ (59)	$ (5)	$ (1,300)
Income from discontinued operations	[1]	76	8	326
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues		7	188	989
Fuel		(6)	(140)	(304)
Purchased power		0	0	(84)
Other operating expenses		(6)	(63)	(435)
Provision for depreciation		0	0	(96)
General taxes		0	(14)	(35)
Pleasants economic interest		5	27	0
Other expense, net		0	(2)	(83)
Loss from discontinued operations, before tax		0	(4)	(48)
Income tax expense (benefit)		0	47	61
Loss from discontinued operations, net of tax		0	(51)	(109)
Removal of investment in FES and FENOC		0	0	2,193
Assumption of benefit obligations retained at FE		0	0	(820)
Guarantees and credit support provided by FE		0	0	(139)
Reserve on receivables and allocated pension/OPEB mark-to-market		0	0	(914)
Settlement consideration and services credit		(1)	7	(1,197)
Accelerated net pension and OPEB prior service credits		18	0	0
Gain (loss) on Disposal of FES and FENOC, before tax		17	7	(877)
Income tax benefit including worthless stock deduction		(59)	(52)	(1,312)
Gain on disposal of FES and FENOC, net of tax		76	59	435
Income from discontinued operations		$ 76	$ 8	$ 326
[1]	Net of income tax benefit of $59 million, $5 million, and $1.3 billion in 2020, 2019 and 2018, respectively.

DISCONTINUED OPERATIONS - Major

DISCONTINUED OPERATIONS - Major Classes of Cash Flow Items from Discontinued Operations (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations	[1]	$ 76	$ 8	$ 326
Gain on disposal, net of tax		(76)	(59)	(435)
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs		1,199	1,217	1,384
Deferred income taxes and investment tax credits, net		113	252	485
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		(2,657)	(2,665)	(2,675)
Sales of investment securities held in trusts		186	1,637	909
Purchases of investment securities held in trusts		(208)	(1,675)	(963)
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations		76	8	326
Gain on disposal, net of tax		(76)	(59)	(435)
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs		0	0	110
Deferred income taxes and investment tax credits, net		0	47	61
Unrealized (gain) loss on derivative transactions		0	0	(10)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions		0	0	(27)
Sales of investment securities held in trusts		0	0	109
Purchases of investment securities held in trusts		$ 0	$ 0	$ (122)
[1]	Net of income tax benefit of $59 million, $5 million, and $1.3 billion in 2020, 2019 and 2018, respectively.

ACCUMULATED OTHER COMPREHENSI_3

ACCUMULATED OTHER COMPREHENSIVE INCOME- Components of AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	$ 6,975	$ 6,814	$ 3,925
Other comprehensive income before reclassifications		(2)	(106)
Amounts reclassified from AOCI	(33)	(27)	(67)
Deconsolidation of FES and FENOC			5
Other comprehensive loss	(33)	(29)	(168)
Income tax benefits on other comprehensive loss	(8)	(8)	(67)
Other comprehensive loss, net of tax	(25)	(21)	(101)
Ending Balance	7,237	6,975	6,814
Accumulated Other Comprehensive Income
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	20	41	142
Other comprehensive loss, net of tax	(25)	(21)	(101)
Ending Balance	(5)	20	41
Gains & Losses on Cash Flow Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	(9)	(11)	(22)
Other comprehensive income before reclassifications		0	0
Amounts reclassified from AOCI	1	2	8
Deconsolidation of FES and FENOC			13
Other comprehensive loss	1	2	21
Income tax benefits on other comprehensive loss	0	0	10
Other comprehensive loss, net of tax	1	2	11
Ending Balance	(8)	(9)	(11)
Unrealized Gains on AFS Securities
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	0	0	67
Other comprehensive income before reclassifications		0	(97)
Amounts reclassified from AOCI	0	0	(1)
Deconsolidation of FES and FENOC			(8)
Other comprehensive loss	0	0	(106)
Income tax benefits on other comprehensive loss	0	0	(39)
Other comprehensive loss, net of tax	0	0	(67)
Ending Balance	0	0	0
Defined Benefit Pension & OPEB Plans
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	29	52	97
Other comprehensive income before reclassifications		(2)	(9)
Amounts reclassified from AOCI	(34)	(29)	(74)
Deconsolidation of FES and FENOC			0
Other comprehensive loss	(34)	(31)	(83)
Income tax benefits on other comprehensive loss	(8)	(8)	(38)
Other comprehensive loss, net of tax	(26)	(23)	(45)
Ending Balance	$ 3	$ 29	$ 52

ACCUMULATED OTHER COMPREHENSI_4

ACCUMULATED OTHER COMPREHENSIVE INCOME - Reclassifications (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ (3,291)	$ (2,952)	$ (3,133)
Interest expense	(1,065)	(1,033)	(1,116)
Income taxes	(126)	(213)	(490)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	1,079	908	981
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes	0	0	(2)
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	1	2	6
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	0	0	1
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	1	2	7
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Discontinued operations	0	0	(1)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs	(34)	(29)	(74)
Income taxes	8	8	19
NET INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ (26)	$ (21)	$ (55)

PENSION AND OTHER POST-EMPLOY_3

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Narrative (Details) - USD ($) $ in Millions	Feb. 01, 2019	Jan. 31, 2018	Dec. 31, 2020	Sep. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Mark-to-market adjustment, net of capitalized amounts			$ 54		$ 423		$ 477	$ 676	$ 145
Increase in discount rate			0.29%				0.38%
Company contributions	$ 500
Future contributions made in current year		$ 750
Return seeking assets sold during period				$ 800			$ 1,400
Transmission companies
Defined Benefit Plan Disclosure [Line Items]
Mark-to-market adjustment, net of capitalized amounts			$ 21
Discontinued Operations
Defined Benefit Plan Disclosure [Line Items]
Mark-to-market adjustment, net of capitalized amounts								2	1
Pensions and OPEB
Defined Benefit Plan Disclosure [Line Items]
Actual return on plan assets							$ 1,225	$ 1,492	$ 371
Actual return on plan assets (percent)							14.70%	20.20%	(4.00%)
Expected return on plan assets							$ 651	$ 569	$ 605
Pension
Defined Benefit Plan Disclosure [Line Items]
Company contributions							24	521
Actual return on plan assets							$ 1,165	$ 1,419
Expected long-term return on plan assets							7.50%	7.50%	7.50%
Expected return on plan assets							$ 618	$ 540	$ 574
Increase in benefit obligation due to RP2014 mortality table							74
Pension | Forecast
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets						7.50%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Company contributions							23	21
Actual return on plan assets							$ 60	$ 73
Expected long-term return on plan assets							7.50%	7.50%	7.50%
Expected return on plan assets							$ 33	$ 29	$ 31
Increase in benefit obligation due to RP2014 mortality table							2
OPEB | Transmission companies
Defined Benefit Plan Disclosure [Line Items]
Mark-to-market adjustment, net of capitalized amounts							$ 40	$ 47	$ 8
Minimum
Defined Benefit Plan Disclosure [Line Items]
Company contributions		$ 500

PENSION AND OTHER POST-EMPLOY_4

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Obligations and Funded Status (Details) - USD ($) $ in Millions	Feb. 01, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Change in fair value of plan assets:
Company contributions	$ 500
Pension
Change in benefit obligation:
Benefit obligation as of January 1		$ 11,050	$ 9,462
Service cost		194	193	$ 224
Interest cost		287	373	372
Plan participants’ contributions		0	0
Plan amendments		9	2
Special termination benefits		0	14
Medicare retiree drug subsidy		0	0
Actuarial loss		1,011	1,535
Benefits paid		(616)	(529)
Benefit obligation as of December 31		11,935	11,050	9,462
Change in fair value of plan assets:
Fair value of plan assets as of January 1		8,395	6,984
Actual return on plan assets		1,165	1,419
Company contributions		24	521
Plan participants’ contributions		0	0
Benefits paid		(616)	(529)
Fair value of plan assets as of December 31		8,968	8,395	6,984
Funded Status:
Funded Status (Net liability as of December 31)		(2,967)	(2,655)
Accumulated benefit obligation		11,376	10,439
Amounts Recognized in AOCI:
Prior service cost (credit)		$ 12	$ 24
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		2.67%	3.34%
Rate of compensation increase		4.10%	4.10%
Cash balance weighted average interest crediting rate		2.57%	2.57%
Allocation of Plan Assets (as of December 31)
Asset Allocation		100.00%	100.00%
Pension | Equity securities
Allocation of Plan Assets (as of December 31)
Asset Allocation		23.00%	29.00%
Pension | Fixed Income
Allocation of Plan Assets (as of December 31)
Asset Allocation		35.00%	36.00%
Pension | Hedge funds
Allocation of Plan Assets (as of December 31)
Asset Allocation		7.00%	9.00%
Pension | Insurance-linked securities
Allocation of Plan Assets (as of December 31)
Asset Allocation		4.00%	2.00%
Pension | Real estate funds
Allocation of Plan Assets (as of December 31)
Asset Allocation		9.00%	7.00%
Pension | Derivatives
Allocation of Plan Assets (as of December 31)
Asset Allocation		0.00%	0.00%
Pension | Private equity funds
Allocation of Plan Assets (as of December 31)
Asset Allocation		5.00%	4.00%
Pension | Cash and short-term securities
Allocation of Plan Assets (as of December 31)
Asset Allocation		17.00%	13.00%
Pension | Qualified plan
Funded Status:
Funded Status (Net liability as of December 31)		$ (2,500)	$ (2,203)
Pension | Non-qualified plans
Funded Status:
Funded Status (Net liability as of December 31)		(467)	(452)
OPEB
Change in benefit obligation:
Benefit obligation as of January 1		654	608
Service cost		4	3	5
Interest cost		15	22	25
Plan participants’ contributions		4	4
Plan amendments		0	0
Special termination benefits		0	0
Medicare retiree drug subsidy		1	1
Actuarial loss		41	64
Benefits paid		(43)	(48)
Benefit obligation as of December 31		676	654	608
Change in fair value of plan assets:
Fair value of plan assets as of January 1		458	408
Actual return on plan assets		60	73
Company contributions		23	21
Plan participants’ contributions		4	4
Benefits paid		(43)	(48)
Fair value of plan assets as of December 31		502	458	$ 408
Funded Status:
Funded Status (Net liability as of December 31)		(174)	(196)
Accumulated benefit obligation		0	0
Amounts Recognized in AOCI:
Prior service cost (credit)		$ (39)	$ (85)
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate		2.45%	3.18%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)		4.50%	4.50%
Allocation of Plan Assets (as of December 31)
Asset Allocation		100.00%	100.00%
OPEB | Equity securities
Allocation of Plan Assets (as of December 31)
Asset Allocation		55.00%	54.00%
OPEB | Fixed Income
Allocation of Plan Assets (as of December 31)
Asset Allocation		28.00%	30.00%
OPEB | Hedge funds
Allocation of Plan Assets (as of December 31)
Asset Allocation		0.00%	0.00%
OPEB | Insurance-linked securities
Allocation of Plan Assets (as of December 31)
Asset Allocation		0.00%	0.00%
OPEB | Real estate funds
Allocation of Plan Assets (as of December 31)
Asset Allocation		0.00%	0.00%
OPEB | Private equity funds
Allocation of Plan Assets (as of December 31)
Asset Allocation		0.00%	0.00%
OPEB | Cash and short-term securities
Allocation of Plan Assets (as of December 31)
Asset Allocation		17.00%	16.00%
OPEB | Pre Medicare
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Health care cost trend rate assumed (pre/post-Medicare)		6.00%	6.00%
OPEB | Post Medicare
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Health care cost trend rate assumed (pre/post-Medicare)		5.50%	5.50%
OPEB | Qualified plan
Funded Status:
Funded Status (Net liability as of December 31)		$ 0	$ 0
OPEB | Non-qualified plans
Funded Status:
Funded Status (Net liability as of December 31)		$ 0	$ 0

PENSION AND OTHER POST-EMPLOY_5

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Components of Net Periodic Benefit Costs (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		$ 194	$ 193	$ 224
Interest cost		287	373	372
Expected return on plan assets		(618)	(540)	(574)
Amortization of prior service costs (credits)		12	7	7
Special termination costs		0	14	31
One-time termination benefits		8	0	0
Pension & OPEB mark-to-market		463	656	227
Net periodic benefit costs (credits)		346	703	287
Net accelerated credits	$ 18
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost		4	3	5
Interest cost		15	22	25
Expected return on plan assets		(33)	(29)	(31)
Amortization of prior service costs (credits)		(46)	(36)	(81)
Special termination costs		0	0	8
One-time termination benefits		0	0	0
Pension & OPEB mark-to-market		14	20	(82)
Net periodic benefit costs (credits)		$ (46)	$ (20)	$ (156)

PENSION AND OTHER POST-EMPLOY_6

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Assumptions Used to Determine Net Periodic Benefit Cost (Details)	2 Months Ended	10 Months Ended	12 Months Ended
	Feb. 26, 2020	Dec. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets			7.50%	7.50%	7.50%
Rate of compensation increase			4.10%	4.10%	4.20%
Pension | Service Cost
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate	3.60%	3.24%		4.66%	3.75%
Pension | Interest Cost
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate	3.27%	2.90%		4.37%	3.75%
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term return on plan assets			7.50%	7.50%	7.50%
OPEB | Service Cost
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate	3.63%	3.29%		4.67%	3.50%
OPEB | Interest Cost
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate	2.71%	2.30%		3.89%	3.50%

PENSION AND OTHER POST-EMPLOY_7

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Pension Investments Measured at Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 8,852	$ 8,219
Asset Allocation	100.00%	100.00%
Excluded from total investments	$ 116	$ 176
Pension | Investments Excluding in Investments at NAV
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 6,604	$ 6,333
Asset Allocation	75.00%	78.00%
Pension | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,493	$ 1,069
Asset Allocation	17.00%	13.00%
Pension | Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 2,065	$ 2,360
Asset Allocation	23.00%	29.00%
Pension | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 2,672	$ 2,064
Asset Allocation	31.00%	25.00%
Pension | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 387	$ 880
Asset Allocation	4.00%	11.00%
Pension | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ (13)	$ (40)
Asset Allocation	0.00%	0.00%
Pension | Private equity funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 465	$ 342
Asset Allocation	5.00%	4.00%
Pension | Insurance-linked securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 323	$ 186
Asset Allocation	4.00%	2.00%
Pension | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 645	$ 774
Asset Allocation	7.00%	9.00%
Pension | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 815	$ 584
Asset Allocation	9.00%	7.00%
Pension | Level 1 | Investments Excluding in Investments at NAV
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,890	$ 1,492
Pension | Level 1 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 1 | Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1,903	1,532
Pension | Level 1 | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 1 | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 1 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	(13)	(40)
Pension | Level 2 | Investments Excluding in Investments at NAV
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	4,714	4,841
Pension | Level 2 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1,493	1,069
Pension | Level 2 | Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	162	828
Pension | Level 2 | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	2,672	2,064
Pension | Level 2 | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	387	880
Pension | Level 2 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 3 | Investments Excluding in Investments at NAV
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 3 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 3 | Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 3 | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 3 | Other
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Pension | Level 3 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 512	$ 457
Asset Allocation	100.00%	100.00%
Excluded from total investments	$ (10)	$ 1
OPEB | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 84	$ 72
Asset Allocation	17.00%	16.00%
OPEB | Equity securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Asset Allocation	55.00%	54.00%
OPEB | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 283	$ 246
Asset Allocation	55.00%	54.00%
OPEB | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 104	$ 100
Asset Allocation	20.00%	22.00%
OPEB | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 34	$ 34
Asset Allocation	7.00%	7.00%
OPEB | Private equity funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Asset Allocation	0.00%	0.00%
OPEB | Insurance-linked securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Asset Allocation	0.00%	0.00%
OPEB | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Asset Allocation	0.00%	0.00%
OPEB | Real estate funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Asset Allocation	0.00%	0.00%
OPEB | Mortgage-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 7	$ 5
Asset Allocation	1.00%	1.00%
OPEB | Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 283	$ 246
OPEB | Level 1 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 1 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	283	246
OPEB | Level 1 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 1 | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 1 | Mortgage-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value		0
OPEB | Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	229	211
OPEB | Level 2 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	84	72
OPEB | Level 2 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 2 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	104	100
OPEB | Level 2 | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	34	34
OPEB | Level 2 | Mortgage-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	7	5
OPEB | Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 3 | Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 3 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 3 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 3 | Corporate debt securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
OPEB | Level 3 | Mortgage-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 0	$ 0

PENSION AND OTHER POST-EMPLOY_8

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Target Asset Allocations for Pension and OPEB Portfolio (Details)	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	100.00%	100.00%
Equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	38.00%	38.00%
Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	30.00%	30.00%
Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	8.00%	8.00%
Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	10.00%	10.00%
Alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	8.00%	8.00%
Cash
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	6.00%	6.00%

PENSION AND OTHER POST-EMPLOY_9

PENSION AND OTHER POST-EMPLOYMENT BENEFITS - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2020USD ($)
Pension
Estimated Future Benefit Payments
2021	$ 579
2022	583
2023	598
2024	601
2025	610
Years 2026-2030	3,129
OPEB
Estimated Future Benefit Payments
2021	49
2022	47
2023	46
2024	45
2025	44
Years 2026-2030	197
Subsidy Receipts
2021	(1)
2022	(1)
2023	(1)
2024	(1)
2025	(1)
Years 2026-2030	$ (2)

STOCK-BASED COMPENSATION PLAN_2

STOCK-BASED COMPENSATION PLANS - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Realized tax benefits	$ 20,000,000	$ 24,000,000	$ 15,000,000
Share-based compensation expense	0	0	0
Tax benefit associated with stock-based compensation expense	3,000,000	10,000,000	18,000,000
Cash portion of RSU paid	27,000,000
Fair value of restricted stock units vested	$ 80,000,000	91,000,000	62,000,000
Stock option expiration period	10 years
Stock options granted in period (shares)	0
Cash received from stock options exercised		23,000,000	$ 12,000,000
EDCP
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Deferral period (years)	3 years
DCPD
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Net liability recognized	$ 7,000,000	$ 9,000,000
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized cost, period for recognition	3 years
Granted (in dollars per share)	$ 44.42	$ 41.23	$ 36,780,000
Unrecognized cost	$ 23,000,000
Performance-based Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Award paid in stock (percent)	66.67%
Award paid in cash (percent)	33.33%
Liability recognized	$ 16,000,000
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	2 years
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	10 years
ICP 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum limit of total stock awards (in shares)	10,000,000
Stock-based compensation award number of shares available for future	13,700,000
ICP 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum limit of total stock awards (in shares)	10,000,000
Stock-based compensation award number of shares available for future	0
401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance	1,000,000	1,000,000

STOCK-BASED COMPENSATION PLAN_3

STOCK-BASED COMPENSATION PLANS - Schedule of Stock-Based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	$ 51	$ 116	$ 143
Stock-based compensation costs capitalized	26	54	60
Incentive Plans | Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	22	73	102
Incentive Plans | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	1	1	1
401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	33	33	33
EDCP & DCPD
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	$ (5)	$ 9	$ 7

STOCK-BASED COMPENSATION PLAN_4

STOCK-BASED COMPENSATION PLANS - Schedule of Nonvested Restricted Stock Units Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Weighted-Average Grant Date Fair Value (per share)
Dividend shares earned during period, number of shares	220
Restricted Stock Units
Shares (in millions)
Nonvested, beginning balance (shares)	2,600,000
Granted (shares)	1,600,000
Forfeited (shares)	(600,000)
Vested (shares)	(1,800,000)
Nonvested, ending balance (shares)	1,800,000	2,600,000
Weighted-Average Grant Date Fair Value (per share)
Beginning balance (in dollars per share)	$ 36.20
Granted (in dollars per share)	44.42	$ 41.23	$ 36,780,000
Forfeited (in dollars per share)	39.15
Vested (in dollars per share)	44.40
Ending balance (in dollars per share)	$ 40.25	$ 36.20

STOCK-BASED COMPENSATION PLAN_5

STOCK-BASED COMPENSATION PLANS - Schedule of Stock Option Activity (Details) shares in Millions	12 Months Ended
	Dec. 31, 2020$ / sharesshares
Number of Shares (in millions)
Beginning option balance (shares) | shares	0.1
Options exercised (in shares) | shares	0
Options forfeited (in shares) | shares	(0.1)
Ending option balance (shares) | shares	0
Weighted Average Exercise Price (per share)
Beginning balance (in dollars per share) | $ / shares	$ 37.75
Options exercised (in dollars per share) | $ / shares	0
Options forfeited (in dollars per share) | $ / shares	37.75
Ending balance (in dollars per share) | $ / shares	$ 0

TAXES - Narrative (Details)

TAXES - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 27, 2020	Feb. 20, 2020	Dec. 31, 2017
Income Taxes (Textuals) [Abstract]
CARES Act interest deductibility refund amount		$ 18
Effective income tax rate (percent)		11.20%	19.10%	32.40%
Valuation allowances		$ (49)	$ 5	$ 21
Effective income tax rate reconciliation, tax credit, investment, amount	$ 10	14	5	5
Operating loss carryforwards, subject to expiration		6,800
Operating loss carryforwards, subject to expiration, net of tax		1,400
Operating loss carryforwards, not subject to expiration		12,400
Operating loss carryforwards, not subject to expiration, net of tax		540
Pre-tax net operating loss carryforwards expected to utilized		3,800
Operating loss carryforwards expected to utilized, net of tax		155
Unrecognized tax benefits		139	164	158			$ 80
Decrease resulting from change in worthless stock deduction		21
Decrease resulting from nondeductible interest		2
Decrease for lapse in statute		2	$ 4	$ 2
Unrecognized tax benefits that would impact future tax rates		121
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year		57
Unrecognized tax benefits that would impact effective tax rate		55
FES
Income Taxes (Textuals) [Abstract]
Valuation allowances		$ 52
IT Access Agreement | Affiliates | FES
Income Taxes (Textuals) [Abstract]
Amount paid to settle claims					$ 125	$ 125

TAXES - Provision for Income Ta

TAXES - Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Currently payable (receivable)-
Federal	$ (14)	$ (16)	$ (16)
State	21	24	17
Currently payable (receivable) Total	7	8	1
Deferred, net-
Federal	171	150	252
State	(38)	60	243
Deferred Tax Total	133	210	495
Investment tax credit amortization	(14)	(5)	(6)
Total income taxes	126	213	490
Federal
Deferred, net-
Income tax expense (benefit), continuing operations, discontinued operations	6
State and Local
Deferred, net-
Income tax expense (benefit), continuing operations, discontinued operations			1
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | Federal
Deferred, net-
Federal	66	9	1,300
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | State and Local
Deferred, net-
Federal	$ 1	$ 4	$ 12

TAXES - Reconciliation of Feder

TAXES - Reconciliation of Federal Income Tax Expense (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Reconciliation of federal income tax expense at the federal statutory rate to the total provision for income taxes
Income from Continuing Operations, before income taxes		$ 1,129	$ 1,117	$ 1,512
Federal income tax expense at statutory rate (21%)		237	235	318
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit		75	96	90
AFUDC equity and other flow-through		(38)	(36)	(31)
Amortization of investment tax credits	$ (10)	(14)	(5)	(5)
Remeasurement of deferred taxes		0	0	24
WV unitary group remeasurement		0	0	126
Excess deferred tax amortization due to the Tax Act		(56)	(74)	(60)
TMI-2 reversal of tax regulatory liabilities		40	0	0
Uncertain tax positions		(1)	(11)	2
Valuation allowances		(49)	5	21
Other, net		12	3	5
Total income taxes		$ 126	$ 213	$ 490
Effective income tax rate (percent)		11.20%	19.10%	32.40%

TAXES - Accumulated Deferred In

TAXES - Accumulated Deferred Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accumulated deferred income taxes
Property basis differences	$ 5,396	$ 5,037
Pension and OPEB	(769)	(698)
TMI-2 nuclear decommissioning	0	89
AROs	(28)	(226)
Regulatory asset/liability	440	445
Deferred compensation	(165)	(154)
Estimated worthless stock deduction	0	(1,007)
Loss carryforwards and AMT credits	(1,995)	(836)
Valuation reserve	496	441	$ 394	$ 312
All other	(280)	(242)
Net deferred income tax liability	$ 3,095	$ 2,849

TAXES - Pre-tax Net Operating L

TAXES - Pre-tax Net Operating Loss Expiration Period (Details) $ in Millions	Dec. 31, 2020USD ($)
State
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	$ 8,030
State | 2021-2025
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,253
State | 2026-2030
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,447
State | 2031-2035
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,152
State | 2036-2040
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,087
State | Indefinite
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	2,091
Local
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	4,353
Local | 2021-2025
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	4,353
Local | 2026-2030
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local | 2031-2035
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local | 2036-2040
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local | Indefinite
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	$ 0

TAXES - Changes in Unrecognized

TAXES - Changes in Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Changes in unrecognized tax benefits
Beginning balance	$ 164	$ 158	$ 80
Current year increases	7	22	125
Prior year decreases	(28)	(12)	(45)
Decrease for lapse in statute	(2)	(4)	(2)
Effectively settled with taxing authorities	(2)
Ending balance	$ 139	$ 164	$ 158

TAXES - Details of General Taxe

TAXES - Details of General Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
General Taxes
KWH excise	$ 183	$ 191	$ 198
State gross receipts	182	185	192
Real and personal property	541	504	478
Social security and unemployment	112	100	103
Other	28	28	22
Total general taxes	$ 1,046	$ 1,008	$ 993

TAXES (Details)

TAXES (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Loss Carry Forward Valuation Reserve
Beginning of year balance	$ 441	$ 394	$ 312
Charged to income	55	47	82
Charged to other accounts	0	0	0
Write-offs	0	0	0
End of year balance	$ 496	$ 441	$ 394

LEASES -Narrative (Details)

LEASES -Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Lessor, Lease, Description [Line Items]
Maximum potential loss of lease agreement	$ 16
Amount of leases not yet commenced	$ 14
Expected commencement period	18 months
Minimum
Lessor, Lease, Description [Line Items]
Renewal term of lease yet to be commenced	1 year
Operating lease renewal term	5 years
Maximum
Lessor, Lease, Description [Line Items]
Renewal term of lease yet to be commenced	40 years
Operating lease renewal term	10 years

LEASES - Components of Lease Ex

LEASES - Components of Lease Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Lessee, Lease, Description [Line Items]
Operating lease costs	$ 60	$ 49
Amortization of right-of-use assets	15	17
Interest on lease liabilities	5	6
Total finance lease cost	20	23
Total lease cost	80	72
Short-term lease costs	17	13
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	44	29
Operating cash flows from finance leases	4	5
Finance cash flows from finance leases	15	25
Right-of-use assets obtained in exchange for lease obligations:
Operating leases	67	83
Finance leases	0	3
Vehicles
Lessee, Lease, Description [Line Items]
Operating lease costs	35	28
Amortization of right-of-use assets	14	15
Interest on lease liabilities	2	3
Total finance lease cost	16	18
Total lease cost	51	46
Buildings
Lessee, Lease, Description [Line Items]
Operating lease costs	8	9
Amortization of right-of-use assets	0	1
Interest on lease liabilities	3	3
Total finance lease cost	3	4
Total lease cost	11	13
Other
Lessee, Lease, Description [Line Items]
Operating lease costs	17	12
Amortization of right-of-use assets	1	1
Interest on lease liabilities	0	0
Total finance lease cost	1	1
Total lease cost	$ 18	$ 13

LEASES - Assets and Liabilities

LEASES - Assets and Liabilities, Lessee (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Weighted-average remaining lease terms (years)
Operating leases	8 years 6 months 18 days	9 years 5 months 1 day
Finance leases	7 years 8 months 26 days	4 years 7 months 13 days
Weighted-average discount rate
Operating leases	4.21%	4.51%
Finance leases	11.58%	10.45%
Assets
Operating lease	$ 265	$ 231
Finance lease	57	73
Total leased assets	322	304
Current:
Operating	42	32
Finance	14	15
Noncurrent:
Operating	263	241
Finance	31	45
Total leased liabilities	350	333
Operating lease assets, accumulated amortization	51	23
Financing lease, accumulated amortization	$ 96	$ 90
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	us-gaap:OtherAssets	us-gaap:OtherAssets
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesNoncurrent	us-gaap:OtherLiabilitiesNoncurrent
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	us-gaap:OtherLiabilitiesCurrent	us-gaap:OtherLiabilitiesCurrent

LEASES - Maturity of Operating

LEASES - Maturity of Operating and Finance Lease Liabilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Operating Leases
2021	$ 50
2022	49
2023	46
2024	38
2025	36
Thereafter	147
Total lease payments	366
Less imputed interest	61
Total net present value	305
Finance Leases
2021	18
2022	15
2023	8
2024	4
2025	4
Thereafter	12
Total lease payments	61
Less imputed interest	16
Total net present value	45
Total
2021	68
2022	64
2023	54
2024	42
2025	40
Thereafter	159
Total lease payments	427
Less imputed interest	77
Total net present value	350
Sublease income	$ 11
Sublease income term	12 years

INTANGIBLE ASSETS (Details)

INTANGIBLE ASSETS (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)
Intangible Assets
Gross	$ 226
Accumulated Amortization	153
Net	73
Amortization Expense
Actual, 2020	7
Estimated, 2021	5
Estimated, 2022	5
Estimated, 2023	5
Estimated, 2024	5
Estimated, 2025	5
Estimated, Thereafter	48
NUG contracts
Intangible Assets
Gross	124
Accumulated Amortization	51
Net	73
Amortization Expense
Actual, 2020	5
Estimated, 2021	5
Estimated, 2022	5
Estimated, 2023	5
Estimated, 2024	5
Estimated, 2025	5
Estimated, Thereafter	48
Coal contracts
Intangible Assets
Gross	102
Accumulated Amortization	102
Net	0
Amortization Expense
Actual, 2020	2
Estimated, 2021	0
Estimated, 2022	0
Estimated, 2023	0
Estimated, 2024	0
Estimated, 2025	0
Estimated, Thereafter	$ 0

FAIR VALUE MEASUREMENTS - Narra

FAIR VALUE MEASUREMENTS - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments not required to be disclosed	$ 322	$ 299
NUG contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Period of future observable data to determine contract price	2 years

FAIR VALUE MEASUREMENTS - Recur

FAIR VALUE MEASUREMENTS - Recurring Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Liabilities
Investment excludes receivables, payables and accrued income	$ 1	$ (16)
Recurring
Assets
Fair value, assets	2,056	1,828
Liabilities
Fair value, liabilities	0	(17)
Net assets (liabilities)	2,056	1,811
Recurring | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	(1)
Recurring | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	(16)
Recurring | Corporate debt securities
Assets
Fair value, assets	0	135
Recurring | FTRs | Derivative Assets
Assets
Fair value, assets	3	4
Recurring | Equity securities
Assets
Fair value, assets	2	2
Recurring | U.S. state debt securities
Assets
Fair value, assets	276	271
Recurring | Other
Assets
Fair value, assets	1,775	1,416
Recurring | Level 1
Assets
Fair value, assets	1,736	629
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	1,736	629
Recurring | Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Recurring | Level 1 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Recurring | Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Recurring | Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Recurring | Level 1 | Equity securities
Assets
Fair value, assets	2	2
Recurring | Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Recurring | Level 1 | Other
Assets
Fair value, assets	1,734	627
Recurring | Level 2
Assets
Fair value, assets	317	1,195
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	317	1,195
Recurring | Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Recurring | Level 2 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Recurring | Level 2 | Corporate debt securities
Assets
Fair value, assets	0	135
Recurring | Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Recurring | Level 2 | Equity securities
Assets
Fair value, assets	0	0
Recurring | Level 2 | U.S. state debt securities
Assets
Fair value, assets	276	271
Recurring | Level 2 | Other
Assets
Fair value, assets	41	789
Recurring | Level 3
Assets
Fair value, assets	3	4
Liabilities
Fair value, liabilities	0	(17)
Net assets (liabilities)	3	(13)
Recurring | Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	(1)
Recurring | Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	(16)
Recurring | Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Recurring | Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	3	4
Recurring | Level 3 | Equity securities
Assets
Fair value, assets	0	0
Recurring | Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Recurring | Level 3 | Other
Assets
Fair value, assets	$ 0	$ 0

FAIR VALUE MEASUREMENTS - Level

FAIR VALUE MEASUREMENTS - Level 3 Rollforward (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
NUG contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	$ 0	$ 0
Beginning Balance, Derivative Liabilities	(16)	(44)
Beginning Balance, Net	(16)	(44)
Unrealized gain (loss), Derivative Assets	0	0
Unrealized gain (loss), Derivative Liabilities	(3)	(11)
Unrealized gain (loss), Net	(3)	(11)
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	0	0
Settlements, Derivative Liabilities	19	39
Settlements, Net	19	39
Ending Balance, Derivative Assets	0	0
Ending Balance, Derivative Liabilities	0	(16)
Ending Balance, Net	0	(16)
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	4	10
Beginning Balance, Derivative Liabilities	(1)	(1)
Beginning Balance, Net	3	9
Unrealized gain (loss), Derivative Assets	(3)	(1)
Unrealized gain (loss), Derivative Liabilities	0	0
Unrealized gain (loss), Net	(3)	(1)
Purchases, Derivative Assets	7	6
Purchases, Derivative Liabilities	(2)	(4)
Purchases, Net	5	2
Settlements, Derivative Assets	(5)	(11)
Settlements, Derivative Liabilities	3	4
Settlements, Net	(2)	(7)
Ending Balance, Derivative Assets	3	4
Ending Balance, Derivative Liabilities	0	(1)
Ending Balance, Net	$ 3	$ 3

FAIR VALUE MEASUREMENTS - Lev_2

FAIR VALUE MEASUREMENTS - Level 3 Quantitative Information (Details) - Level 3 $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)$ / MWh	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 3	$ 3	$ 9
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	0	$ (16)	$ (44)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 3
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | $ / MWh	400,000
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | $ / MWh	2,200,000
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH) | $ / MWh	1,100,000

FAIR VALUE MEASUREMENTS - Inves

FAIR VALUE MEASUREMENTS - Investments Held in Trusts (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Debt Securities, Available-for-sale [Abstract]
Short-term cash investments	$ 9	$ 751
Short-term investments held-for-sale		747
Debt securities held-for-sale		135
Debt Securities
Debt Securities, Available-for-sale [Abstract]
Cost Basis	275	403
Unrealized Gains	7	9
Unrealized Losses	(6)	(11)
Fair Value	$ 276	$ 401

FAIR VALUE MEASUREMENTS - Proce

FAIR VALUE MEASUREMENTS - Proceeds from the Sale of Investments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Sale Proceeds	$ 186	$ 1,637	$ 800
Realized Gains	12	98	41
Realized Losses	(8)	(31)	(48)
Interest and Dividend Income	$ 22	$ 38	$ 41

FAIR VALUE MEASUREMENTS - Carry

FAIR VALUE MEASUREMENTS - Carrying Amounts of Long-term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair value and related carrying amounts of long-term debt and other long-term obligations
Debt issuances	$ 3,425	$ 2,300	$ 1,474
Debt redemptions	1,114	789	$ 2,608
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	22,377	20,066
Debt issuances	3,425
Debt redemptions	1,114
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 25,465	$ 22,928

CAPITALIZATION - Narrative (Det

CAPITALIZATION - Narrative (Details)	Dec. 15, 2020$ / shares	Apr. 20, 2020USD ($)	Feb. 20, 2020USD ($)series	Dec. 31, 2020USD ($)$ / sharesshares	Sep. 30, 2020$ / shares	Jun. 30, 2020$ / shares	Mar. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)$ / sharesshares	Sep. 30, 2019$ / shares	Jun. 30, 2019$ / shares	Mar. 31, 2019$ / shares	Dec. 31, 2020USD ($)subsidiary$ / sharesshares	Dec. 31, 2019USD ($)$ / sharesshares	Dec. 31, 2018USD ($)$ / sharesshares	Jul. 20, 2020USD ($)	Jun. 29, 2020USD ($)	Jun. 08, 2020USD ($)series	Feb. 27, 2020USD ($)	Jan. 31, 2018USD ($)$ / sharesshares	Jan. 22, 2018USD ($)$ / sharesshares	Jun. 30, 2013USD ($)
Debt Instrument [Line Items]
Retained earnings (accumulated deficit)				$ (2,888,000,000)				$ (3,967,000,000)				$ (2,888,000,000)	$ (3,967,000,000)
Dividends declared (in dollars per share) | $ / shares	$ 0.39											$ 1.56	$ 1.53	$ 1.82
Common stock dividends per share paid, in dollars per share | $ / shares				$ 0.39	$ 0.39	$ 0.39	$ 0.39	$ 0.38	$ 0.38	$ 0.38	$ 0.38
FERC-defined equity to total capitalization ratio												35.00%
Common stock, par value (in dollars per share) | $ / shares				$ 0.10				$ 0.10				$ 0.10	$ 0.10
Amount of private placement																				$ 850,000,000
Preferred shares, outstanding (in shares) | shares				0				0				0	0
Preference shares outstanding (in shares) | shares				0				0				0	0
Transition bond outstanding				$ 9,000,000				$ 25,000,000				$ 9,000,000	$ 25,000,000
Preferred stock, par value (in dollars per share) | $ / shares				$ 100								$ 100
Repayments of debt												$ 1,114,000,000	789,000,000	$ 2,608,000,000
Number of subsidiaries that issued environmental control bonds | subsidiary												2
Environmental control bonds outstanding				$ 300,000,000				333,000,000				$ 300,000,000	$ 333,000,000
2021				132,000,000								132,000,000
Principal default amount specified in debt covenants												$ 100,000,000
Common Stock Purchase Agreement
Debt Instrument [Line Items]
Amount of shares issued | shares																				30,120,482
Common stock, par value (in dollars per share) | $ / shares																				$ 0.10
Registered Shareholders, Directors and Employees of Subsidiaries
Debt Instrument [Line Items]
Stock Investment Plan and certain share-based benefit plans (in shares) | shares												2,000,000	3,000,000	3,200,000
Series A Convertible Preferred Stock
Debt Instrument [Line Items]
Preferred stock shares issued (in shares) | shares																			1,616,000
Preferred stock, par value (in dollars per share) | $ / shares																			$ 100
Amount of preferred stock investment																			$ 1,620,000,000
Phase In Recovery Bonds
Debt Instrument [Line Items]
Long-term debt and other long-term obligations				245,000,000				$ 268,000,000				$ 245,000,000	$ 268,000,000
Senior Notes | $750 Million Senior Unsecured Notes
Debt Instrument [Line Items]
Face amount of loan																	$ 750,000,000
Number of debt series | series																	2
Senior Notes | 1.60% Senior A Notes Due 2026
Debt Instrument [Line Items]
Face amount of loan																	$ 300,000,000
Interest rate (percent)																	1.60%
Senior Notes | 2.250% Senior B Notes Due 2030
Debt Instrument [Line Items]
Face amount of loan																	$ 450,000,000
Interest rate (percent)																	2.25%
Senior Notes | $1.75 Billion Senior Notes
Debt Instrument [Line Items]
Face amount of loan			$ 1,750,000,000
Number of debt series | series			3
Senior Notes | 2.050% Series A Senior Notes Due 2025
Debt Instrument [Line Items]
Face amount of loan			$ 300,000,000
Interest rate (percent)			2.05%
Senior Notes | 2.650% Series B Senior Notes Due 2030
Debt Instrument [Line Items]
Face amount of loan			$ 600,000,000
Interest rate (percent)			2.65%
Senior Notes | 3.400% Series C Senior Notes Due 2050
Debt Instrument [Line Items]
Face amount of loan			$ 850,000,000
Interest rate (percent)			3.40%
Term Loan | $750M Term Loan
Debt Instrument [Line Items]
Repayments of debt			$ 750,000,000
Debt term			2 years
Term Loan | $1B Term Loan
Debt Instrument [Line Items]
Face amount of loan			$ 1,000,000,000
Repayments of debt			$ 250,000,000
Debt term			364 days
Common Stock
Debt Instrument [Line Items]
Stock Investment Plan and certain share-based benefit plans (in shares) | shares												2,000,000	3,000,000	4,000,000
Amount of private placement																				$ 3,000,000
Number of shares issued | shares													25,696,168	33,238,910
Preferred Stock
Debt Instrument [Line Items]
Number of shares converted | shares													704,589	911,411
Preferred Stock | Series A Convertible Preferred Stock
Debt Instrument [Line Items]
Amount of preferred stock investment																			162,000,000
OPIC
Debt Instrument [Line Items]
Amount of private placement																				$ 847,000,000
OPIC | Series A Convertible Preferred Stock
Debt Instrument [Line Items]
Amount of preferred stock investment																			$ 1,460,000,000
PN | Senior Notes
Debt Instrument [Line Items]
Face amount of loan		$ 125,000,000
PN | Senior Notes | 3.61% Senior Unsecured Notes Due 2032
Debt Instrument [Line Items]
Interest rate (percent)		3.61%
PN | Senior Notes | 3.71% Senior Notes Due 2035
Debt Instrument [Line Items]
Interest rate (percent)		3.71%
Repayments of debt		$ 125,000,000
PN | Senior Notes | 5.20% Senior Notes Due 2020
Debt Instrument [Line Items]
Face amount of loan		$ 250,000,000
Interest rate (percent)		5.20%
MP | PCRB
Debt Instrument [Line Items]
2021				$ 74,000,000								$ 74,000,000
MAIT | Senior Notes | 3.60 Percent Senior Notes Due 2032
Debt Instrument [Line Items]
Face amount of loan							$ 125,000,000
Interest rate (percent)							3.60%
MAIT | Senior Notes | 3.70% Senior Notes Due 2035
Debt Instrument [Line Items]
Face amount of loan							$ 125,000,000
Interest rate (percent)							3.70%
PE | FMBs | 2.67% First Mortgage Bond Due 2032
Debt Instrument [Line Items]
Face amount of loan																$ 75,000,000
Interest rate (percent)																2.67%
PE | FMBs | 3.43% First Mortgage Bonds Due 2051
Debt Instrument [Line Items]
Face amount of loan																$ 100,000,000
Interest rate (percent)																3.43%
CEI | Senior Notes | 2.77% Senior Notes Due 2034
Debt Instrument [Line Items]
Face amount of loan															$ 150,000,000
Interest rate (percent)															2.77%
CEI | Senior Notes | 3.23% Senior Notes Due 2040
Debt Instrument [Line Items]
Face amount of loan															$ 100,000,000
Interest rate (percent)															3.23%
FES | FES Key Creditor Groups | Affiliates
Debt Instrument [Line Items]
Amount paid to settle claims			$ 853,000,000
FES | IT Access Agreement | Affiliates
Debt Instrument [Line Items]
Amount paid to settle claims			$ 125,000,000															$ 125,000,000
Ohio Funding Companies
Debt Instrument [Line Items]
Aggregate annual servicing fees receivable for phase-in recovery bonds												$ 445,000
Ohio Funding Companies | Phase In Recovery Bonds
Debt Instrument [Line Items]
Face amount of loan																					$ 445,000,000
AGC
Debt Instrument [Line Items]
FERC-defined equity to total capitalization ratio												45.00%

CAPITALIZATION - Preferred and

CAPITALIZATION - Preferred and Preference Stock (Details) - $ / shares	Dec. 31, 2020	Jan. 31, 2018
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	5,000,000
Par Value (in dollars per share)	$ 100
Penn
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	1,200,000
Par Value (in dollars per share)	$ 100
CEI
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	4,000,000
JCP&L
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	15,600,000
ME
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	10,000,000
PN
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	11,435,000
PE
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	10,000,000
Par Value (in dollars per share)	$ 0.01
WP
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	32,000,000
Preferred Stock With Par Value $100 | OE
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	6,000,000
Par Value (in dollars per share)	$ 100
Preferred Stock With Par Value $100 | TE
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	3,000,000
Par Value (in dollars per share)	$ 100
Preferred Stock With Par Value $100 | MP
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	940,000
Par Value (in dollars per share)	$ 100
Preferred Stock With Par Value $25 | OE
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	8,000,000
Par Value (in dollars per share)	$ 25
Preferred Stock With Par Value $25 | TE
Preferred stock and preference stock authorizations
Shares Authorized (in shares)	12,000,000
Par Value (in dollars per share)	$ 25
Preference Stock | OE
Preferred stock and preference stock authorizations
Preference Shares Authorized (in shares)	8,000,000
Preference Stock | CEI
Preferred stock and preference stock authorizations
Preference Shares Authorized (in shares)	3,000,000
Preference Stock | TE
Preferred stock and preference stock authorizations
Preference Shares Authorized (in shares)	5,000,000
Preference Stock Par Value (in dollars per share)	$ 25
Series A Convertible Preferred Stock
Preferred stock and preference stock authorizations
Par Value (in dollars per share)		$ 100

CAPITALIZATION - Long-term Debt

CAPITALIZATION - Long-term Debt and Other Long-term Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Schedule of Capitalization [Line Items]
Finance lease obligations	$ 45	$ 60
Unamortized debt discounts	(34)	(33)
Unamortized debt issuance costs	(118)	(103)
Unamortized fair value adjustments	7	8
Currently payable long-term debt	(146)	(380)
Total long-term debt and other long-term obligations	22,131	19,618
FMBs and secured notes - fixed rate
Schedule of Capitalization [Line Items]
FMBs and secured notes - fixed rate	$ 4,802	4,741
FMBs and secured notes - fixed rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	2.67%
FMBs and secured notes - fixed rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	8.25%
Unsecured notes - fixed rate
Schedule of Capitalization [Line Items]
Unsecured debt	$ 17,575	14,575
Unsecured notes - fixed rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	1.60%
Unsecured notes - fixed rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	7.375%
Unsecured notes - variable rate
Schedule of Capitalization [Line Items]
Unsecured debt	$ 0	$ 750

CAPITALIZATION - Sinking Fund R

CAPITALIZATION - Sinking Fund Requirements (Details) $ in Millions	Dec. 31, 2020USD ($)
Capitalization, Long-term Debt and Equity [Abstract]
2021	$ 132
2022	1,143
2023	1,194
2024	1,246
2025	$ 2,023

SHORT-TERM BORROWINGS AND BAN_2

SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT - Narrative (Details)	Nov. 23, 2020USD ($)	Dec. 31, 2020USD ($)agreement	Nov. 17, 2020USD ($)	Dec. 31, 2019USD ($)
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Short-term borrowings		$ 2,200,000,000		$ 1,000,000,000
Average interest rate for borrowings		1.86%		2.88%
Maximum | Affiliates
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility		364 days
FET | Minimum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Consolidated debt to total capitalization ratio (percent)		65.00%
FET | Maximum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Consolidated debt to total capitalization ratio (percent)		75.00%
Revolving Credit Facility | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Number of agreements | agreement		2
Maximum amount borrowed under revolving credit facility		$ 3,500,000,000
Revolving Credit Facility | Parent, the Utilities, FET and Certain Subsidiaries | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility		5 years
Revolving Credit Facility | FET | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Line of credit facility, remaining borrowing capacity	$ 0
Revolving Credit Facility | FE and the regulated distribution subsidiaries | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Proceeds from lines of credit	950,000,000
Line of Credit | Letter of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility		1 year
Line of Credit | Letter of Credit | FET
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		$ 100,000,000
Money Pool | Maximum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility		364 days
Money Pool | Regulated Companies
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Average interest rate for borrowings		0.89%
Money Pool | Unregulated Companies
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Average interest rate for borrowings		1.19%
Available for Issuance of Letters of Credit | Minimum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Cross-default provision for other indebtedness		$ 100,000,000
FE | Revolving Credit Facility | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		2,500,000,000	$ 1,500,000,000
Outstanding borrowings	1,200,000,000
Line of credit facility, remaining borrowing capacity	1,300,000,000
FE | Line of Credit | Letter of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		250,000,000
FET Sub-limits | Revolving Credit Facility | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		$ 1,000,000,000
Proceeds from lines of credit	1,000,000,000
Outstanding borrowings	$ 1,000,000,000

ASSET RETIREMENT OBLIGATIONS -

ASSET RETIREMENT OBLIGATIONS - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018MW
Changes to the asset retirement obligations
Beginning Balance	$ 856	$ 812
Liabilities settled	(744)	(2)
Accretion	47	46
Ending Balance	159	856
Noncurrent liabilities - held for sale (Note 15)	0	691
TMI-2
Changes to the asset retirement obligations
Noncurrent liabilities - held for sale (Note 15)		$ 691
Decrease in asset retirement obligation	$ 726
Pleasants Power Station | Purchase Agreement with Subsidiary of LS Power | AE Supply
Asset Retirement Obligations [Line Items]
Plant generation capacity (in MW's) | MW			1,300

REGULATORY MATTERS - Distributi

REGULATORY MATTERS - Distribution Rate Orders (Details) - USD ($) $ in Millions	Nov. 01, 2020	Oct. 16, 2020	Dec. 31, 2020
CEI
Public Utilities, General Disclosures [Line Items]
Allowed Debt			51.00%
Allowed Equity			49.00%
Approved ROE			10.50%
ME
Public Utilities, General Disclosures [Line Items]
Allowed Debt			48.80%
Allowed Equity			51.20%
MP
Public Utilities, General Disclosures [Line Items]
Allowed Debt			54.00%
Allowed Equity			46.00%
JCP&L
Public Utilities, General Disclosures [Line Items]
Allowed Debt	48.56%		55.00%
Allowed Equity	51.44%		45.00%
Approved ROE	9.60%		9.60%
JCP&L | New Jersey | NJBPU
Public Utilities, General Disclosures [Line Items]
Settled decrease in regulatory liability		$ 86
OE
Public Utilities, General Disclosures [Line Items]
Allowed Debt			51.00%
Allowed Equity			49.00%
Approved ROE			10.50%
Penn
Public Utilities, General Disclosures [Line Items]
Allowed Debt			49.90%
Allowed Equity			50.10%
Penn | West Virginia
Public Utilities, General Disclosures [Line Items]
Allowed Debt			54.00%
Allowed Equity			46.00%
Penn | Maryland
Public Utilities, General Disclosures [Line Items]
Allowed Debt			47.00%
Allowed Equity			53.00%
Approved ROE			9.65%
PN
Public Utilities, General Disclosures [Line Items]
Allowed Debt			47.40%
Allowed Equity			52.60%
TE
Public Utilities, General Disclosures [Line Items]
Allowed Debt			51.00%
Allowed Equity			49.00%
Approved ROE			10.50%
WP
Public Utilities, General Disclosures [Line Items]
Allowed Debt			49.70%
Allowed Equity			50.30%

REGULATORY MATTERS - Maryland a

REGULATORY MATTERS - Maryland and New Jersey (Details) meter in Millions, $ in Millions

Jan. 29, 2021USD ($)

Dec. 18, 2020USD ($)

Nov. 01, 2020USD ($)

Oct. 16, 2020USD ($)

Sep. 25, 2020USD ($)

Sep. 22, 2020USD ($)

Aug. 27, 2020USD ($)meter

Jun. 02, 2020USD ($)

Apr. 06, 2020USD ($)MW

Feb. 18, 2020USD ($)

Mar. 23, 2019USD ($)

Mar. 22, 2019program

Dec. 17, 2018USD ($)

Oct. 22, 2018USD ($)

Aug. 24, 2018USD ($)program

Jan. 19, 2018USD ($)

Jul. 16, 2015

Dec. 31, 2020USD ($)MW

Dec. 31, 2020USD ($)MW

Utilities and FET

Regulatory Matters [Line Items]

Plant generation capacity (in MW's) | MW

3,790

3,790

Yard's Creek Energy, LLC Hydro Generation Facility | Utilities and FET

Regulatory Matters [Line Items]

Plant generation capacity (in MW's) | MW

210

210

Ownership interest acquired

50.00%

PE | MDPSC

Regulatory Matters [Line Items]

Cost of charging equipment rebates

$ 12

Charging equipment rebates amortization period

5 years

PE | Maryland

Regulatory Matters [Line Items]

Incremental energy savings goal per year (percent)

0.20%

Incremental energy savings goal thereafter (percent)

2.00%

PE | Maryland | MDPSC

Regulatory Matters [Line Items]

Requested increase (decrease) in revenues

$ 6.2

Requested rate increase (decrease)

$ (19.7)

Number of enhanced service reliability programs | program

4,000,000

Revised requested rate increase

$ 17.6

Number of approved ESR programs | program

3

ESR program term

4 years

Period to file new depreciation study

18 months

ESER Program rate case renewal period

4 years

Revised rate increase

$ 7.3

JCP&L | New Jersey

Regulatory Matters [Line Items]

Requested rate increase (decrease) (percent)

7.80%

JCP&L | New Jersey | Yard's Creek Energy, LLC Hydro Generation Facility

Regulatory Matters [Line Items]

Plant generation capacity (in MW's) | MW

210

Consideration transferred

$ 155

JCP&L | New Jersey | Yard's Creek Energy, LLC Hydro Generation Facility | Utilities and FET

Regulatory Matters [Line Items]

Assets acquired

$ 45

$ 45

JCP&L | New Jersey | NJBPU

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ (185)

$ (186.9)

Settled amount of increase in revenue

$ 94

Requested ROE

9.60%

Settled decrease in regulatory liability

$ 86

JCP&L | New Jersey | NJBPU | Yard's Creek Energy, LLC Hydro Generation Facility

Regulatory Matters [Line Items]

Ownership interest acquired

50.00%

JCP&L Reliability Plus | JCP&L | New Jersey | NJBPU

Regulatory Matters [Line Items]

Requested increase (decrease) in revenues

$ 95.1

$ 97

2021-2023 EmPOWER Program Cycle | PE | Maryland

Regulatory Matters [Line Items]

Recovery period for expenditures for cost recovery program

3 years

Expenditures for cost recovery program

$ 148

2018-2020 EmPOWER Program Cycle | PE | Maryland

Regulatory Matters [Line Items]

Recovery period for expenditures for cost recovery program

3 years

Expenditures for cost recovery program

$ 116

Amortization period for expenditures for cost recovery program

5 years

Advanced metering infrastructure | JCP&L | New Jersey | Utilities and FET

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ (732)

Advanced metering infrastructure | JCP&L | New Jersey | NJBPU | Utilities and FET

Regulatory Matters [Line Items]

Expected cost of the program

$ 418

Meter deployment program period

20 years

Deployment period

3 years

Number of meters to be deployed | meter

1.2

Energy Efficiency and Peak Demand Reduction | JCP&L | New Jersey | NJBPU | Utilities and FET

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ (230)

Depreciation Study | PE | Maryland

Regulatory Matters [Line Items]

Depreciation study findings

$ 36.2

Depreciation Study | PE | Maryland | MDPSC | Subsequent Event

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 9.6

Depreciation Study | PE | Maryland | Maryland Office of People's Counsel | Subsequent Event

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 10.8

REGULATORY MATTERS - Ohio (Deta

REGULATORY MATTERS - Ohio (Details) - USD ($) $ in Millions	Nov. 24, 2020	Jul. 17, 2019	Jul. 15, 2019	Oct. 12, 2016	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018	Feb. 01, 2021	Feb. 01, 2020	Jan. 31, 2020
Regulatory Matters [Line Items]
Proposed reduction in power plants carbon pollution (percent)					90.00%
Ohio | PUCO
Regulatory Matters [Line Items]
Proposed reduction in power plants carbon pollution (percent)				90.00%
Ohio | PUCO | DCR Rider
Regulatory Matters [Line Items]
Revenue cap for Rider for years 3-6				$ 20
Revenue cap for Rider for years 6-8				15
Ohio | PUCO | DMR
Regulatory Matters [Line Items]
Annual revenue cap for rider							$ 132.5
Cost recovery period							3 years
Approved annual revenue cap for rider						$ 168	$ 168
Requested extension period	2 years
Ohio | PUCO | DPM Plan
Regulatory Matters [Line Items]
Approved amount of rate increase		$ 516
Grid modernization plan period		3 years
Ohio | PUCO | Energy Conservation, Economic Development and Job Retention
Regulatory Matters [Line Items]
Contribution amount				$ 51
Ohio Companies | PUCO | Rider CSR
Regulatory Matters [Line Items]
Regulatory asset balance									$ 0	$ 113
Ohio Companies | Ohio | PUCO | Ohio Consumers Counsel DMR Refund
Regulatory Matters [Line Items]
Amount of damages sought			$ 42
Ohio Companies | Ohio | PUCO | Rider CSR
Regulatory Matters [Line Items]
Pre-tax impairment of regulatory asset					$ 108
Impairment of regulatory asset, net					84
Lost distribution revenue					$ 77
Ohio Companies | Ohio | PUCO | Rider CSR | Subsequent Event
Regulatory Matters [Line Items]
Regulatory asset balance								$ 0

REGULATORY MATTERS - Pennsylvan

REGULATORY MATTERS - Pennsylvania and West Virginia (Details) $ in Millions	Dec. 30, 2020USD ($)MW	Aug. 28, 2020USD ($)	Jan. 17, 2020	Aug. 30, 2019USD ($)	Jun. 01, 2019proposalMW	Mar. 31, 2016USD ($)	Jun. 18, 2020
Pennsylvania | PPUC | Penn | ENEC Phase IV
Regulatory Matters [Line Items]
Approved demand reduction targets							2.00%
Approved energy consumption reduction targets							2.70%
Pennsylvania | PPUC | WP | ENEC Phase IV
Regulatory Matters [Line Items]
Approved demand reduction targets							2.50%
Approved energy consumption reduction targets							2.40%
Pennsylvania | PPUC | Pennsylvania Companies | DSP
Regulatory Matters [Line Items]
Number of RFP's | proposal					2
Project term					2 years
New hourly priced default service threshold (in MW's) | MW					0.1
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 3 Month Period
Regulatory Matters [Line Items]
Energy contract term					3 months
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 12 Month Period
Regulatory Matters [Line Items]
Energy contract term					12 months
Pennsylvania | PPUC | Pennsylvania Companies | DSP | 24 Month Period
Regulatory Matters [Line Items]
Energy contract term					24 months
Pennsylvania | PPUC | Pennsylvania Companies | EE&C
Regulatory Matters [Line Items]
Approved amount of rate increase						$ 390
Pennsylvania | PPUC | Pennsylvania Companies | New LTIP's
Regulatory Matters [Line Items]
Requested rate increase (decrease)				$ 572
Cost recovery period				5 years
Pennsylvania | PPUC | Pennsylvania Companies | Wavier of Distribution System Improvement Charge Cap
Regulatory Matters [Line Items]
Requested rate increase (decrease) (percent)				11.81%
Proposed settled recoverability cap			7.50%
Approved ROE				5.00%
Pennsylvania | PPUC | PN | ENEC Phase IV
Regulatory Matters [Line Items]
Approved demand reduction targets							3.30%
Approved energy consumption reduction targets							3.00%
Pennsylvania | PPUC | ME | ENEC Phase IV
Regulatory Matters [Line Items]
Approved demand reduction targets							2.90%
Approved energy consumption reduction targets							3.10%
West Virginia | WVPSC | MP and PE | ENEC
Regulatory Matters [Line Items]
Requested rate increase (decrease)		$ (55)
Requested rate increase (decrease) (percent)		(4.00%)
Recovery of deferred, incremental uncollectible and other related costs		$ 10.5
Requested annual rate reduction	$ 2.6
West Virginia | WVPSC | MP and PE | Modernization and Improvement Program For Coal-Fired Boilers
Regulatory Matters [Line Items]
Requested rate increase (decrease)		$ 5
West Virginia | WVPSC | MP and PE | Integrated Resource Plan
Regulatory Matters [Line Items]
Integrated resource plan project period	15 years
Requested solar generation source | MW	50

REGULATORY MATTERS - Reliabilit

REGULATORY MATTERS - Reliability and FERC Matters (Details) - USD ($) $ in Millions	Feb. 02, 2021	Nov. 01, 2020	Dec. 31, 2020	Dec. 31, 2019
ATSI | FERC
Regulatory Matters [Line Items]
Regulatory asset balance			$ 79	$ 73
ATSI | Regulated Transmission
Regulatory Matters [Line Items]
Approved ROE			10.38%
MAIT | Regulated Transmission
Regulatory Matters [Line Items]
Allowed Debt			60.00%
Approved ROE			10.30%
TrAIL | Regulated Transmission | TrAIL the Line and Black Oak SVC
Regulatory Matters [Line Items]
Approved ROE			12.70%
TrAIL | Regulated Transmission | All Other Projects
Regulatory Matters [Line Items]
Approved ROE			11.70%
JCP&L
Regulatory Matters [Line Items]
Allowed Debt		48.56%	55.00%
Approved ROE		9.60%	9.60%
JCP&L | Regulated Transmission
Regulatory Matters [Line Items]
Approved ROE			10.80%
JCP&L | Regulated Transmission | Subsequent Event
Regulatory Matters [Line Items]
Approved ROE	10.20%

COMMITMENTS, GUARANTEES AND C_3

COMMITMENTS, GUARANTEES AND CONTINGENCIES - Schedule of Guarantor Obligations (Details) $ in Millions	Dec. 31, 2020USD ($)
Guarantor Obligations [Line Items]
Potential additional collateral obligations	$ 350
Utilities and FET
Guarantor Obligations [Line Items]
Potential additional collateral obligations	92
FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	258
Upon Further Downgrade
Guarantor Obligations [Line Items]
Potential additional collateral obligations	37
Upon Further Downgrade | Utilities and FET
Guarantor Obligations [Line Items]
Potential additional collateral obligations	37
Upon Further Downgrade | FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	0
Surety Bond
Guarantor Obligations [Line Items]
Potential additional collateral obligations	313
Surety Bond | Utilities and FET
Guarantor Obligations [Line Items]
Potential additional collateral obligations	55
Surety Bond | FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	$ 258

COMMITMENTS, GUARANTEES AND C_4

COMMITMENTS, GUARANTEES AND CONTINGENCIES - Nuclear Insurance, Commitments and Collateral (Details)	3 Months Ended
	Dec. 31, 2020USD ($)
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	$ 1,700,000,000
Company posted collateral related to net liability positions	20,000,000
Collateral posted due to credit rating downgrade	19,000,000
Subsidiaries' Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	1,100,000,000
Other Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	108,000,000
Other Assurances
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	490,000,000
Global Holding | Senior Secured Term Loan | Senior Loans
Loss Contingencies [Line Items]
Long-term debt and other long-term obligations	$ 108,000,000
Global Holding | Signal Peak, Global Rail and Affiliates | Senior Secured Term Loan | Senior Loans
Loss Contingencies [Line Items]
Investment ownership percentage	69.99%
FEV | Signal Peak | Senior Secured Term Loan | Senior Loans | Global Holding
Loss Contingencies [Line Items]
Investment ownership percentage	33.33%
WMB Marketing Ventures, LLC | Signal Peak | Senior Secured Term Loan | Senior Loans | Global Holding
Loss Contingencies [Line Items]
Investment ownership percentage	33.33%
Term Loan Facility Due March 2020 | Line of Credit | Global Holding
Loss Contingencies [Line Items]
Face amount of loan	$ 120,000,000

COMMITMENTS, GUARANTEES AND C_5

COMMITMENTS, GUARANTEES AND CONTINGENCIES - Clean Air Act and Climate Change (Details) T in Millions	12 Months Ended
	Dec. 31, 2020phaseT	Nov. 12, 2014
Loss Contingencies [Line Items]
Proposed reduction in power plants carbon pollution (percent)	90.00%
National Ambient Air Quality Standards
Loss Contingencies [Line Items]
Capping of SO2 Emissions Under CSAPR	2.4
Capping of NOx emissions under CSAPR	1.2
National Ambient Air Quality Standards | CSAPR
Loss Contingencies [Line Items]
Number of phases under the EPA’s CAIR for reductions of Sulfur Dioxide and Mono-Nitrogen Oxides | phase	2
Minimum | Climate Change
Loss Contingencies [Line Items]
Reduction in emissions (percent)		26.00%
Maximum | Climate Change
Loss Contingencies [Line Items]
Reduction in emissions (percent)		28.00%

COMMITMENTS, GUARANTEES AND C_6

COMMITMENTS, GUARANTEES AND CONTINGENCIES - Clean Water Act, Regulation of Waste Disposal and Other Legal Proceedings (Details) $ in Millions	12 Months Ended
	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Oct. 29, 2020director	Feb. 01, 2020USD ($)	Jan. 31, 2020USD ($)	Nov. 04, 2019USD ($)
Loss Contingencies [Line Items]
Number of additional executives terminated | director			2
Amount of violation of code of conduct payment		$ 4
PUCO | Ohio Companies | Rider CSR
Loss Contingencies [Line Items]
Regulatory asset balance				$ 0	$ 113
Clean Water Act
Loss Contingencies [Line Items]
Renewal cycle of waste water discharge permit	5 years
Clean Water Act | EPA
Loss Contingencies [Line Items]
Proposed penalty						$ 900
Regulation of Waste Disposal
Loss Contingencies [Line Items]
Accrual for environmental loss contingencies	$ 107
Environmental liabilities former gas facilities	$ 67

SEGMENT INFORMATION - Narrative

SEGMENT INFORMATION - Narrative (Details) mi² in Thousands, customer in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2020USD ($)mi²companyMW	Dec. 31, 2020USD ($)mi²customercompanyMW
Utilities and FET
Segment Reporting Information [Line Items]
Number of existing utility operating companies | company	10	10
Number of customers served by utility operating companies | customer		6
Number of square miles in service area | mi²	65	65
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW	3,790	3,790
Utilities and FET | Disposal Group, Held-for-sale | TMI-2
Segment Reporting Information [Line Items]
Assets held-for-sale	$ 882	$ 882
Utilities and FET | Disposal Group, Held-for-sale | Yard Creek Generating Facility
Segment Reporting Information [Line Items]
Assets held-for-sale	45	$ 45
Utilities and FET | Disposal Group, Disposed of by Sale | TMI-2
Segment Reporting Information [Line Items]
Gain on disposal of discontinued operation, net of tax	$ 33
Utilities and FET | Yard's Creek Energy, LLC Hydro Generation Facility
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW	210	210
Ownership interest acquired		50.00%
Other/Corporate | OVEC
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW	67	67
FE | Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations	$ 8,200	$ 8,200

SEGMENT INFORMATION (Details)

SEGMENT INFORMATION (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Segment Financial Information
Total revenues	[1]	$ 10,790	$ 11,035	$ 11,261
Provision for depreciation		1,274	1,220	1,136
Deferral of regulatory assets, net		(53)	(79)	(150)
Miscellaneous income, net		432	243	205
Interest expense		1,065	1,033	1,116
Income taxes (benefits)		126	213	490
Income (loss) from continuing operations		1,003	904	1,022
Property additions		2,657	2,665	2,675
Total assets		44,464	42,301
Total goodwill		5,618	5,618
External revenues
Segment Financial Information
Total revenues		10,790	11,035	11,261
Internal revenues
Segment Financial Information
Total revenues		0	0	0
Utilities and FET
Segment Financial Information
Total goodwill		5,004
Regulated Transmission
Segment Financial Information
Total revenues		1,613	1,510	1,335
Operating Segments | Utilities and FET
Segment Financial Information
Total revenues		9,363	9,698	10,103
Provision for depreciation		896	863	812
Deferral of regulatory assets, net		(64)	(89)	(163)
Miscellaneous income, net		332	174	192
Interest expense		501	495	514
Income taxes (benefits)		113	271	422
Income (loss) from continuing operations		959	1,076	1,242
Property additions		1,514	1,473	1,411
Total assets		30,855	29,642
Total goodwill		5,004	5,004
Operating Segments | Utilities and FET | External revenues
Segment Financial Information
Total revenues		9,168	9,511	9,900
Operating Segments | Utilities and FET | Internal revenues
Segment Financial Information
Total revenues		195	187	203
Operating Segments | Regulated Transmission
Segment Financial Information
Total revenues		1,630	1,526	1,353
Provision for depreciation		313	284	252
Deferral of regulatory assets, net		11	10	13
Miscellaneous income, net		30	15	14
Interest expense		219	192	167
Income taxes (benefits)		138	113	122
Income (loss) from continuing operations		464	447	397
Property additions		1,067	1,090	1,104
Total assets		12,592	11,611
Total goodwill		614	614
Operating Segments | Regulated Transmission | External revenues
Segment Financial Information
Total revenues		1,613	1,510	1,335
Operating Segments | Regulated Transmission | Internal revenues
Segment Financial Information
Total revenues		17	16	18
Corporate/ Other
Segment Financial Information
Total revenues		9	14	34
Provision for depreciation		4	5	3
Deferral of regulatory assets, net		0	0	0
Miscellaneous income, net		83	80	32
Interest expense		358	372	468
Income taxes (benefits)		(125)	(171)	(54)
Income (loss) from continuing operations		(420)	(619)	(617)
Property additions		76	102	133
Total assets		1,017	1,015
Total goodwill		0	0
Corporate/ Other | External revenues
Segment Financial Information
Total revenues		9	14	26
Corporate/ Other | Internal revenues
Segment Financial Information
Total revenues		0	0	8
Reconciling Adjustments
Segment Financial Information
Total revenues		(212)	(203)	(229)
Provision for depreciation		61	68	69
Deferral of regulatory assets, net		0	0	0
Miscellaneous income, net		(13)	(26)	(33)
Interest expense		(13)	(26)	(33)
Income taxes (benefits)		0	0	0
Income (loss) from continuing operations		0	0	0
Property additions		0	0	27
Total assets		0	33
Total goodwill		0	0
Reconciling Adjustments | External revenues
Segment Financial Information
Total revenues		0	0	0
Reconciling Adjustments | Internal revenues
Segment Financial Information
Total revenues		$ (212)	$ (203)	$ (229)
[1]	Includes excise and gross receipts tax collections of $362 million, $373 million and $386 million in 2020, 2019 and 2018, respectively.