FirstEnergy (FE) 10-K 19 Feb 19 2018 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2018	Jan. 31, 2019	Jun. 30, 2018
Document and Entity Information [Abstract]
Entity Registrant Name	FIRSTENERGY CORP
Entity Central Index Key	1,031,296
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Amendment Flag	false
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		530,152,175
Entity Public Float			$ 17,109,706,919
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Shell Company	false

Consolidated Statements of Inco

Consolidated Statements of Income (Loss) - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
REVENUES:
Total revenues	[1]	$ 11,261	$ 10,928	$ 10,700
OPERATING EXPENSES:
Fuel		538	497	571
Purchased power		3,109	2,926	3,310
Other operating expenses		3,133	2,761	2,579
Provision for depreciation		1,136	1,027	933
Amortization (deferral) of regulatory assets, net		(150)	308	297
General taxes		993	940	913
Impairment of assets (Note 1)		0	41	43
Total operating expenses		8,759	8,500	8,646
OPERATING INCOME		2,502	2,428	2,054
OTHER INCOME (EXPENSE):
Miscellaneous income, net		205	53	44
Pension and OPEB mark-to-market adjustment		(144)	(102)	(102)
Interest expense		(1,116)	(1,005)	(973)
Capitalized financing costs		65	52	55
Total other expense		(990)	(1,002)	(976)
INCOME BEFORE INCOME TAXES		1,512	1,426	1,078
INCOME TAXES		490	1,715	527
INCOME (LOSS) FROM CONTINUING OPERATIONS		1,022	(289)	551
Discontinued operations, net of tax		326	(1,435)	(6,728)
NET INCOME (LOSS)		1,348	(1,724)	(6,177)
INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 1)		367	0	0
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS		$ 981	$ (1,724)	$ (6,177)
EARNINGS (LOSS) PER SHARE OF COMMON STOCK:
Basic - Continuing Operations, in dollars per share		$ 1.33	$ (0.65)	$ 1.29
Basic - Discontinued Operations, in dollars per share		0.66	(3.23)	(15.78)
Basic - Net Income (Loss) Attributable to Common Stockholders, in dollars per share		1.99	(3.88)	(14.49)
Diluted - Continuing Operations, in dollars per share		1.33	(0.65)	1.29
Diluted - Discontinued Operations, in dollars per share		0.66	(3.23)	(15.78)
Diluted - Net Income (Loss) Attributable to Common Stockholders, in dollars per share		$ 1.99	$ (3.88)	$ (14.49)
WEIGHTED AVERAGE NUMBER OF SHARES OUTSTANDING:
Basic, in shares		492	444	426
Diluted, in shares		494	444	426
Electric Distribution and Electric Generation [Member]
REVENUES:
Total revenues		$ 8,937	$ 8,685	$ 8,685
Electric Transmission [Member]
REVENUES:
Total revenues		1,335	1,307	1,123
Product and Service, Other [Member]
REVENUES:
Total revenues		$ 989	$ 936	$ 892
[1]	Includes excise and gross receipts tax collections of $386 million, $370 million and $378 million in 2018, 2017 and 2016, respectively.

Consolidated Statements of In_2

Consolidated Statements of Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement [Abstract]
Excise tax collections included in Revenue	$ 386	$ 370	$ 378
Income tax expense (benefit)	$ 1,251	$ 820	$ 3,582

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)	$ 1,348	$ (1,724)	$ (6,177)
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(83)	(85)	(59)
Amortized losses on derivative hedges	21	10	8
Change in unrealized gains on available-for-sale securities	(106)	22	55
Other comprehensive income (loss)	(168)	(53)	4
Income taxes (benefits) on other comprehensive income (loss)	(67)	(21)	1
Other comprehensive income (loss), net of tax	(101)	(32)	3
COMPREHENSIVE INCOME (LOSS)	$ 1,247	$ (1,756)	$ (6,174)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 367	$ 588
Restricted cash	62	51
Receivables-
Customers, net of allowance for uncollectible accounts of $50 in 2018 and $49 in 2017	1,221	1,282
Other, net of allowance for uncollectible accounts of $2 in 2018 and $1 in 2017	270	170
Materials and supplies, at average cost	252	236
Prepaid taxes and other	175	151
Current assets - discontinued operations	25	632
Total current assets	2,392	3,110
PROPERTY, PLANT AND EQUIPMENT:
In service	39,469	37,113
Less — Accumulated provision for depreciation	10,793	10,011
Property, plant and equipment in service net of accumulated provision for depreciation	28,676	27,102
Construction work in progress	1,235	999
Total net property, plant and equipment	29,911	28,101
PROPERTY, PLANT AND EQUIPMENT, NET - DISCONTINUED OPERATIONS	0	1,132
INVESTMENTS:
Nuclear plant decommissioning trusts	790	822
Nuclear fuel disposal trust	256	251
Other	253	255
Investments - discontinued operations	0	1,875
Total other property and investments	1,299	3,203
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	5,618
Regulatory assets	91	40
Other	752	697
Deferred charges and other assets - discontinued operations	0	356
Total deferred charges and other assets	6,461	6,711
Total assets	40,063	42,257
CURRENT LIABILITIES:
Currently payable long-term debt	503	558
Short-term borrowings	1,250	300
Accounts payable	965	827
Accrued taxes	533	533
Accrued compensation and benefits	318	257
Collateral	39	39
Other	1,026	621
Disposal Group, Including Discontinued Operation, Liabilities, Current	0	978
Total current liabilities	4,634	4,113
Stockholders’ Equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 511,915,450 and 445,334,111 shares outstanding as of December 31, 2018 and December 31, 2017, respectively	51	44
Preferred stock, $100 par value, authorized 5,000,000 shares, of which 1,616,000 are designated Series A Convertible Preferred - 704,589 shares outstanding as of December 31, 2018	71	0
Other paid-in capital	11,530	10,001
Accumulated other comprehensive income	41	142
Accumulated deficit	(4,879)	(6,262)
Total stockholders' equity	6,814	3,925
Long-term debt and other long-term obligations	17,751	18,687
Total capitalization	24,565	22,612
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	2,502	3,171
Retirement benefits	2,906	3,975
Regulatory liabilities	2,498	2,720
Asset retirement obligations	812	570
Adverse power contract liability	89	130
Other	2,057	1,438
Noncurrent liabilities - discontinued operations	0	3,528
Total noncurrent liabilities	10,864	15,532
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 17)
Total liabilities and capitalization	40,063	42,257
Affiliated companies
Receivables-
Customers, net of allowance for uncollectible accounts of $50 in 2018 and $49 in 2017	$ 20	$ 0

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Stockholders’ Equity-
Common stock, par value (in dollars per share)	$ 0.1	$ 0.1
Common stock, shares authorized	700,000,000	700,000,000
Common stock, shares outstanding	511,915,450	445,334,111
Preferred stock, par value, in dollars per share	$ 100
Preferred stock, shares authorized	5,000,000
Preferred shares shares outstanding	0	0
Customer
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 50	$ 49
Other
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 2	$ 1
Series A Convertible Preferred Stock
Stockholders’ Equity-
Common stock, shares outstanding	700,000	0
Preferred stock, shares authorized	1,616,000
Preferred shares shares outstanding	704,589
Affiliated companies
Receivables-
Allowance for uncollectible accounts (in dollars)	$ 920

Consolidated Statements of Comm

Consolidated Statements of Common Stockholders' Equity (FirstEnergy Corp.) - USD ($) $ in Millions	Total	Common Stock	OPIC	AOCI	Retained Earnings (Accumulated Deficit)	Series A Convertible Preferred Stock
Beginning Balance, Shares at Dec. 31, 2015		424,000,000				0
Beginning Balance at Dec. 31, 2015	$ 12,421	$ 42	$ 9,952	$ 171	$ 2,256	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(6,177)				(6,177)
Other comprehensive loss, net of tax	3			3
Amortized gain (loss) on derivative hedges, net of income taxes	3			3
Stock-based compensation	49		49
Cash dividends declared on common stock	(611)				(611)
Stock Investment Plan and certain share-based benefit plans, shares		2,700,000
Stock Investment Plan and certain share-based benefit plans	56		56
Stock issuance (Note 13), shares		16,000,000
Stock issuance (Note 13)	500	$ 2	498
Ending Balance, Shares at Dec. 31, 2016		442,000,000				0
Ending Balance at Dec. 31, 2016	6,241	$ 44	10,555	174	(4,532)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income (Loss)	(1,724)				(1,724)
Other comprehensive loss, net of tax	(32)			(32)
Amortized gain (loss) on derivative hedges, net of income taxes	(32)			(32)
Stock-based compensation	36		36
Cash dividends declared on common stock	(639)		(639)
Stock Investment Plan and certain share-based benefit plans, shares		3,000,000
Stock Investment Plan and certain share-based benefit plans	56		56
Reclass to liability awards	$ (7)		(7)
Ending Balance, Shares at Dec. 31, 2017	445,334,111	445,000,000				0
Ending Balance at Dec. 31, 2017	$ 3,925	$ 44	10,001	142	(6,262)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based compensation accounting change	(6)				(6)
Net Income (Loss)	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)
Stock Investment Plan and certain share-based benefit plans, shares		3,200,000
Stock Investment Plan and certain share-based benefit plans	62	$ 1	61
Stock issuance (Note 13), shares		30,000,000				1,600,000
Stock issuance (Note 13)	2,462	$ 3	2,297			$ 162
Conversion of Series A Convertible Stock (Note 13), Shares		33,000,000				(900,000)
Conversion of Series A Convertible Stock (Note 13)	0	$ 3	88			$ (91)
Cash dividends declared on preferred stock	(71)		(71)
Impact of adopting new accounting pronouncements	$ 35				35
Ending Balance, Shares at Dec. 31, 2018	511,915,450	512,000,000				700,000
Ending Balance at Dec. 31, 2018	$ 6,814	$ 51	$ 11,530	$ 41	$ (4,879)	$ 71

Consolidated Statements of Co_2

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

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss)	$ 1,348	$ (1,724)	$ (6,177)
Adjustments to reconcile net income (loss) to net cash from operating activities-
Gain on disposal, net of tax (Note 3)	(435)	0	0
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	1,384	1,700	1,974
Impairment of assets and related charges	0	2,399	10,665
Pension trust contributions	(1,250)	0	(382)
Retirement benefits, net of payments	(137)	29	64
Pension and OPEB mark-to-market adjustment	144	141	147
Deferred income taxes and investment tax credits, net	485	839	(3,063)
Asset removal costs charged to income	42	22	54
Unrealized (gain) loss on derivative transactions	(5)	81	9
Gain on sale of investment securities held in trusts	(9)	(63)	(50)
Changes in current assets and liabilities-
Receivables	(248)	(39)	(11)
Materials and supplies	24	(6)	41
Prepaid taxes and other	(61)	30	27
Accounts payable	109	72	(37)
Accrued taxes	0	(9)	61
Accrued compensation and benefits	37	(27)	29
Other current liabilities	(146)	20	56
Cash collateral, net	(1)	27	(116)
Other	129	316	92
Net cash provided from operating activities	1,410	3,808	3,383
New Financing-
Long-term debt	1,474	4,675	1,976
Short-term borrowings, net	950	0	975
Preferred stock issuance	1,616	0	0
Common stock issuance	850	0	0
Redemptions and Repayments-
Long-term debt	(2,608)	(2,291)	(2,331)
Short-term borrowings, net	0	(2,375)	0
Tender premiums paid on debt redemptions	(89)	0	0
Preferred stock dividend payments	(61)	0	0
Common stock dividend payments	(711)	(639)	(611)
Other	(27)	(72)	(43)
Net cash provided from (used for) financing activities	1,394	(702)	(34)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,675)	(2,587)	(2,835)
Nuclear fuel	0	(254)	(232)
Proceeds from asset sales	425	388	15
Sales of investment securities held in trusts	909	2,170	1,678
Purchases of investment securities held in trusts	(963)	(2,268)	(1,789)
Notes receivable from affiliated companies	(500)	0	0
Asset removal costs	(218)	(172)	(145)
Other	4	0	6
Net cash used for investing activities	(3,018)	(2,723)	(3,302)
Net change in cash, cash equivalents and restricted cash	(214)	383	47
Cash, cash equivalents, and restricted cash at beginning of period	643	260	213
Cash, cash equivalents, and restricted cash at end of period	429	643	260
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction: stock contribution to pension plan	0	0	500
Non-cash transaction: beneficial conversion feature (Note1)	296	0	0
Non-cash transaction: deemed dividend convertible preferred stock (Note 1)	(296)	0	0
Interest (net of amounts capitalized)	1,071	1,039	1,050
Income taxes, net of refunds	$ 49	$ 53	$ (16)

Organization, Basis of Presenta

Organization, Basis of Presentation	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
ORGANIZATION AND BASIS OF PRESENTATION	ORGANIZATION AND BASIS OF PRESENTATION Unless otherwise indicated, defined terms and abbreviations used herein have the meanings set forth in the accompanying Glossary of Terms. FE was incorporated under Ohio law in 1996. FE’s principal business is the holding, directly or indirectly, of all of the outstanding equity of its principal subsidiaries: OE, CEI, TE, Penn (a wholly owned subsidiary of OE), JCP&L, ME, PN, FESC, AE Supply, MP, 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: FirstEnergy Properties, Inc., FEV, FELHC, Inc., GPU Nuclear, Inc., AESC and Allegheny Ventures, Inc. FE and its subsidiaries are principally involved in the transmission, distribution and generation of electricity. FirstEnergy’s ten utility operating companies comprise one of the nation’s largest investor-owned electric systems, based on serving over six million customers in the Midwest and Mid-Atlantic regions. FirstEnergy’s transmission operations include approximately 24,500 miles of lines and two regional transmission operation centers. AGC, JCP&L and MP control 3,790 MWs of total capacity. 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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 10, "Variable Interest Entities"). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss). Certain prior year amounts have been reclassified to conform to the current year presentation, as discussed in "New Accounting Pronouncements" and Note 3, "Discontinued Operations." FES and FENOC Chapter 11 Filing On March 31, 2018, the FES Debtors announced that, in order to facilitate an orderly financial restructuring, they filed voluntary petitions under Chapter 11 of the United States Bankruptcy Code with the Bankruptcy Court (which is referred to throughout as the FES Bankruptcy). As a result of the bankruptcy filings, FirstEnergy concluded that it no longer had a controlling interest in the FES Debtors as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, the FES Debtors were deconsolidated from FirstEnergy’s consolidated financial statements. Since such time, FE has accounted and will account for its investments in the FES Debtors at fair values of zero . FE concluded that in connection with the disposal, FES and FENOC became discontinued operations. On September 26, 2018, the Bankruptcy Court approved a FES Bankruptcy settlement agreement dated August 26, 2018, by and among FirstEnergy, two groups of key FES creditors (collectively, the FES Key Creditor Groups), the FES Debtors and the UCC. The FES Bankruptcy settlement agreement resolves certain claims by FirstEnergy against the FES Debtors and all claims by the FES Debtors and their creditors against FirstEnergy, and includes the following terms, among others: • FE will pay certain pre-petition FES and FENOC employee-related obligations, which include unfunded pension obligations and other employee benefits. • FE will waive all pre-petition claims (other than those claims under the Tax Allocation Agreement for the 2018 tax year) and certain post-petition claims, against the FES Debtors related to the FES Debtors and their businesses, including the full borrowings by FES under the $500 million secured credit facility, the $200 million credit agreement being used to support surety bonds, the BNSF/CSX rail settlement guarantee, and the FES Debtors' unfunded pension obligations. • The full release of all claims against FirstEnergy by the FES Debtors and their creditors. • A $225 million cash payment from FirstEnergy. • A $628 million aggregate principal amount note issuance by FirstEnergy to the FES Debtors, which may be decreased by the amount, if any, of cash paid by FirstEnergy to the FES Debtors under the Intercompany Income Tax Allocation Agreement for the tax benefits related to the sale or deactivation of certain plants. • Transfer of the Pleasants Power Station and related assets, including the economic interests therein as of January 1, 2019, and a requirement that FE continue to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred. FE will provide certain guarantees for retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. • FirstEnergy agrees to waive all pre-petition claims related to shared services and credit nine-months of the FES Debtors' shared service costs beginning as of April 1, 2018 through December 31, 2018, in an amount not to exceed $112.5 million, and FirstEnergy agrees to extend the availability of shared services until no later than June 30, 2020. • FirstEnergy agrees to fund through its pension plan a pension enhancement, subject to a cap, should FES offer a voluntary enhanced retirement package in 2019 and to offer certain other employee benefits. • FirstEnergy agrees to perform under the Intercompany Tax Allocation Agreement through the FES Debtors’ emergence from bankruptcy, at which time FirstEnergy will waive a 2017 overpayment for NOLs of approximately $71 million, reverse 2018 estimated payments for NOLs of approximately $88 million and pay the FES Debtors for the use of NOLs in an amount no less than $66 million for 2018 (of which approximately $52 million has been paid through December 31, 2018). FirstEnergy determined a loss is probable with respect to the FES Bankruptcy and recorded pre-tax charges totaling $877 million in 2018. See Note 3, "Discontinued Operations," for additional information. The FES Bankruptcy settlement agreement remains subject to satisfaction of certain conditions, most notably the issuance of a final order by the Bankruptcy Court approving the plan or plans of reorganization for the FES Debtors that are acceptable to FirstEnergy consistent with the requirements of the FES Bankruptcy settlement agreement. There can be no assurance that such conditions will be satisfied or the FES Bankruptcy settlement agreement will be otherwise consummated, and the actual outcome of this matter may differ materially from the terms of the agreement described herein. FirstEnergy will continue to evaluate the impact of any new factors on the settlement and their relative impact on the financial statements. In connection with the FES Bankruptcy settlement agreement, FirstEnergy entered into a separation agreement with the FES Debtors to implement the separation of the FES Debtors and their businesses from FirstEnergy. A business separation committee was established between FirstEnergy and the FES Debtors to review and determine issues that arise in the context of the separation of the FES Debtors’ businesses from those of FirstEnergy. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred, and FE will provide certain guarantees for retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including FERC approval of the transaction, the Bankruptcy Court’s approval of the agreement, effectiveness of the FES Bankruptcy settlement agreement and the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated. Restricted Cash Restricted cash primarily relates to the consolidated VIE's discussed in Note 10, "Variable Interest Entities." The cash collected from JCP&L, MP, PE and the Ohio Companies' customers is used to service debt of their respective funding companies. ACCOUNTING FOR THE EFFECTS OF REGULATION FirstEnergy accounts for the effects of regulation through the application of regulatory accounting to the Utilities, AGC, 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 (Loss) 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 and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions. The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2018 and December 31, 2017 , and the changes during the year ended December 31, 2018 : Net Regulatory Assets (Liabilities) by Source December 31, December 31, Change (In millions) Regulatory transition costs $ 49 $ 46 $ 3 Customer payables for future income taxes (2,725 ) (2,765 ) 40 Nuclear decommissioning and spent fuel disposal costs (148 ) (323 ) 175 Asset removal costs (787 ) (774 ) (13 ) Deferred transmission costs 170 187 (17 ) Deferred generation costs 202 198 4 Deferred distribution costs 208 258 (50 ) Contract valuations 62 118 (56 ) Storm-related costs 500 329 171 Other 62 46 16 Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,407 ) $ (2,680 ) $ 273 Approximately $503 million and $ 223 million of regulatory assets, primarily related to storm damage costs, do not earn a current return as of December 31, 2018 and 2017 , respectively, and a majority of which are currently being recovered through rates over varying periods depending on the nature of the deferral and the jurisdiction. Additionally, certain regulatory assets, totaling approximately $141 million as of December 31, 2018, are recorded based on prior precedent or anticipated recovery based on rate making premises without a specific order. CUSTOMER RECEIVABLES 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, 2018 and 2017 , with respect to any particular segment of FirstEnergy’s customers. Billed and unbilled customer receivables as of December 31, 2018 and 2017 , net of allowance for uncollectible accounts, are included below. Customer Receivables December 31, 2018 December 31, 2017 (In millions) Billed $ 686 $ 754 Unbilled 535 528 Total $ 1,221 $ 1,282 EARNINGS (LOSS) PER SHARE OF COMMON STOCK The convertible preferred stock issued in January 2018 (see Note 13, "Capitalization") is considered participating securities since these shares participate in dividends on common stock on an "as-converted" basis. As a result, EPS of common stock is computed using the two-class method required for participating securities. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • preferred stock dividends, • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and • an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends. Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations. The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million , represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature will be reflected in net income (loss) attributable to common stockholders as a deemed dividend. The amount amortized for the year ended December 31, 2018, was $296 million . Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible preferred shares. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred share 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 2018 2017 2016 (In millions, except per share amounts) EPS of Common Stock Income from continuing operations $ 1,022 $ (289 ) $ 551 Less: Preferred dividends (71 ) — — Less: Amortization of beneficial conversion feature (296 ) — — Less: Undistributed earnings allocated to preferred stockholders (1) — — — Income from continuing operations available to common stockholders 655 (289 ) 551 Discontinued operations, net of tax 326 (1,435 ) (6,728 ) Less: Undistributed earnings allocated to preferred stockholders (1) — — — Income (loss) from discontinued operations available to common stockholders 326 (1,435 ) (6,728 ) Net Income (loss) attributable to common stockholders, basic and diluted $ 981 $ (1,724 ) $ (6,177 ) Share Count information: Weighted average number of basic shares outstanding 492 444 426 Assumed exercise of dilutive stock options and awards 2 — — Weighted average number of diluted shares outstanding 494 444 426 Net Income (loss) attributable to common stockholders, per share: Income from continuing operations, basic $ 1.33 $ (0.65 ) $ 1.29 Discontinued operations, basic 0.66 (3.23 ) (15.78 ) Net income (loss) attributable to common stockholders, basic $ 1.99 $ (3.88 ) $ (14.49 ) Income from continuing operations, diluted $ 1.33 $ (0.65 ) $ 1.29 Discontinued operations, diluted 0.66 (3.23 ) (15.78 ) Net income (loss) attributable to common stockholders, diluted $ 1.99 $ (3.88 ) $ (14.49 ) (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 negative. For the years ended December 31, 2018, 2017 and 2016, approximately 1 million , 3 million and 3 million shares from stock options and awards were excluded from the calculation of diluted shares outstanding, respectively, as their inclusion would be antidilutive, and, in the case of 2017 and 2016, a result of the net loss for the period. Additionally, 26 million shares associated with the assumed conversion of preferred stock were excluded, as their inclusion would be antidilutive to basic EPS from continuing operations. 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, 2018 and 2017 , were as follows: December 31, 2018 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 27,520 $ (8,132 ) $ 19,388 $ 628 $ 20,016 Regulated Transmission 11,041 (2,210 ) 8,831 545 9,376 Corporate/Other 908 (451 ) 457 62 519 Total $ 39,469 $ (10,793 ) $ 28,676 $ 1,235 $ 29,911 December 31, 2017 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 25,950 $ (7,503 ) $ 18,447 $ 469 $ 18,916 Regulated Transmission 10,102 (2,055 ) 8,047 480 8,527 Corporate/Other 1,061 (453 ) 608 50 658 Total $ 37,113 $ (10,011 ) $ 27,102 $ 999 $ 28,101 (1) Includes capital leases of $173 million and $190 million as of December 31, 2018 and 2017, respectively. The major classes of Property, plant and equipment are largely consistent with the segment disclosures above. Regulated Distribution has approximately $2 billion of total regulated generation property, plant and equipment. 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 2.6% , 2.4% and 2.3% in 2018 , 2017 and 2016 , respectively. During the third quarter of 2016, FirstEnergy recorded a reduction to depreciation expense of $21 million ( $19 million prior to January 1, 2016) that related to prior periods. The out-of-period adjustment related to the utilization of an accelerated useful life for a component of a certain power station. Management determined this adjustment was not material to 2016 or any prior periods. For the years ended December 31, 2018 , 2017 and 2016 , capitalized financing costs on FirstEnergy's Consolidated Statements of Income (Loss) include $46 million , $35 million and $37 million , respectively, of allowance for equity funds used during construction and $19 million , $17 million and $18 million , respectively, of capitalized interest. Jointly Owned Plants FE, through its subsidiary, AGC, owns an undivided 16.25% interest ( 487 MWs) in a 3,003 MW pumped storage, hydroelectric station and a 40% interest in its connecting transmission facilities in Bath County, Virginia, operated by the 60% owner, VEPCO, a non-affiliated utility. Net Property, plant and equipment includes $188 million representing AGC's share in this facility as of December 31, 2018 . 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 FE's operating expenses on the Consolidated Statements of Income (Loss). AGC provides the generation capacity from this facility to its owner, MP. Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plant and future remediation of other 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, 2018 , are described further in Note 15, "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. Asset impairments associated with a discontinued operation (a portion of AE Supply, FES, FENOC and BSPC) are recognized in discontinued operations. See Note 3, "Discontinued Operations". 2017 Impairments As described in Note 16, "Regulatory Matters," on October 13, 2017, MAIT and certain parties filed a settlement agreement with FERC. As a result of the settlement agreement, MAIT recorded a pre-tax impairment charge of $13 million in the third quarter of 2017. As described in Note 16, "Regulatory Matters," on December 21, 2017, JCP&L and certain parties filed a settlement agreement with FERC. As a result of the settlement agreement, JCP&L recorded a pre-tax impairment charge of $28 million in the fourth quarter of 2017. 2016 Impairments During 2016, FirstEnergy recognized an impairment of approximately $43 million primarily associated with AE Supply's investment in OVEC. 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'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, 2018 : Regulated Distribution Regulated Transmission Consolidated (In millions) Goodwill $ 5,004 $ 614 $ 5,618 FirstEnergy tests goodwill for impairment annually as of July 31 and considers more frequent testing if indicators of potential impairment arise. As of July 31, 2018, 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 include: growth rates, interest rates, expected capital expenditures, utility sector market performance 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. INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes. Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. The fair values of FirstEnergy’s investments are disclosed in Note 11, "Fair Value Measurements." The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. 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. NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy evaluated its revenues and determined the new guidance had immaterial impacts to recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy did not record a cumulative effect adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes were implemented. See Note 2, "Revenue," for additional information on FirstEnergy's revenues. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (Issued January 2016 and subsequently updated in 2018): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. FirstEnergy adopted this standard on January 1, 2018, and recognizes all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting this standard, FirstEnergy recorded a cumulative effect adjustment to retained earnings of $57 million on January 1, 2018, representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. Following deconsolidation of the FES Debtors, the adoption of this standard is not expected to have a material impact on FirstEnergy's financial statements as the majority of its gains and losses on equity securities are offset against a regulatory asset or liability. ASU 2016-18, " Restricted Cash" (Issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. As a result of adopting this standard, FirstEnergy's statement of cash flows reports changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. Prior periods have been recast to conform to the current year presentation. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017) : ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. FirstEnergy adopted ASU 2017-01 on January 1, 2018. The ASU will be applied prospectively to future transactions. ASU 2017-04, "Goodwill Impairment" (Issued January 2017): ASU 2017-04 simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. FirstEnergy has elected to early adopt ASU 2017-04 as of January 1, 2018, and will apply this standard on a prospective basis. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017) : ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the other components) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. FirstEnergy adopted ASU 2017-07 on January 1, 2018. Beca

Discontinued Operations

Discontinued Operations	12 Months Ended
	Dec. 31, 2018
Discontinued Operations and Disposal Groups [Abstract]
Discontinued Operations	DISCONTINUED OPERATIONS FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. During the third quarter of 2018, the Pleasants Power Station was reclassified to discontinued operations following its inclusion in the FES Bankruptcy settlement agreement for the benefit of FES' creditors. Prior period results have been reclassified to conform with such presentation as discontinued operations. FES and FENOC Chapter 11 Bankruptcy Filing As discussed in Note 1, "Organization and Basis of Presentation," on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy concluded that it no longer has a controlling interest in the FES Debtors, as the entities are subject to the jurisdiction of the Bankruptcy Court and, accordingly, as of March 31, 2018, FES and FENOC were deconsolidated from FirstEnergy's consolidated financial statements, and FirstEnergy has accounted and will account for its investments in FES and FENOC at fair values of zero . In connection with the disposal and the FES Bankruptcy settlement agreement approved by the Bankruptcy Court in September 2018, as further discussed in Note 1, "Organization and Basis of Presentation," FE recorded an after-tax gain on disposal of $435 million in 2018. By eliminating a significant portion of its competitive generation fleet with the deconsolidation of the FES Debtors, FirstEnergy has concluded the FES Debtors meet the criteria for discontinued operations, as this represents a significant event in management’s strategic review to exit commodity-exposed generation and transition to a fully regulated company. FES Borrowings from FE On March 9, 2018, FES borrowed $500 million from FE under the secured credit facility, dated as of December 6, 2016, among FES, as Borrower, FG and NG as guarantors, and FE, as lender, which fully utilized the committed line of credit available under the secured credit facility. Following deconsolidation of FES, FE fully reserved for the $500 million associated with the borrowings under the secured credit facility. Under the terms of the FES Bankruptcy settlement agreement discussed below, FE will release any and all claims against the FES Debtors with respect to the $500 million borrowed under the secured credit facility. On March 16, 2018, FES and FENOC withdrew from the unregulated companies' money pool, which included FE, FES and FENOC. Under the terms of the FES Bankruptcy settlement agreement, FE reinstated $88 million for 2018 estimated payments for NOLs applied against the FES Debtor’s position in the unregulated companies’ money pool prior to their withdrawal on March 16, 2018, which increased the amount the FES Debtors owed FE under the money pool to $92 million . In addition, as of March 31, 2018, AE Supply had a $102 million outstanding unsecured promissory note owed from FES. Following deconsolidation of FES and FENOC on March 31, 2018 and given the terms of the FES Bankruptcy settlement agreement, FE fully reserved the $92 million associated with the outstanding unsecured borrowings under the unregulated companies' money pool and the $102 million associated with the AE Supply unsecured promissory note, under the terms of the FES Bankruptcy settlement agreement, FirstEnergy will release any and all claims against the FES Debtors with respect to the $92 million owed under the unregulated money pool and $102 million unsecured promissory note. As of December 31, 2018, approximately $24 million of interest was accrued and subsequently reserved. Services Agreements Pursuant to the FES Bankruptcy settlement agreement, FirstEnergy entered into an amended and restated shared services agreement with the FES Debtors to extend the availability of shared services until no later than June 30, 2020, subject to reductions in services if requested by the FES Debtors. Under the amended shared services agreement, and consistent with the prior shared services agreements, costs are directly billed or assigned at no more than cost. In addition to providing for certain notice requirements and other terms and conditions, the agreement provides for a credit to the FES Debtors in an amount up to $112.5 million for charges incurred for services provided under prior shared services agreements and the amended shared services agreement from April 1, 2018 through December 31, 2018. As of December 31, 2018, approximately $169 million has been incurred since April 2018, which fully utilized the agreed credit and beyond and which $1 million has been paid by FES. The entire credit for shared services provided to the FES Debtors ( $112.5 million ) has been recognized by FE as a loss from discontinued operations as of December 31, 2018. In addition, on March 16, 2018, FES, FENOC and FESC entered into the FirstEnergy Solutions Money Pool Agreement for FESC to assist FES and FENOC with certain treasury support services under the shared service agreement. FESC is a party to the FirstEnergy Solutions Money Pool Agreement solely in the role as administrator of the money pool arrangement thereunder. Benefit Obligations FirstEnergy will retain certain obligations for the FES Debtors' employees for services provided prior to emergence from bankruptcy. The retention of this obligation at March 31, 2018, resulted in a net liability of $820 million (including EDCP, pension and OPEB) with a corresponding loss from discontinued operations. EDCP and pension/OPEB service costs earned by the FES Debtors' employees during bankruptcy are billed under the shared services agreement. As FE continues to provide pension benefits to FES/FENOC employees, all components of pension cost, including the mark to market, are seen as providing ongoing services and are reported in the continuing operations of FE, subsequent to the bankruptcy filing. Guarantees provided by FE FE previously guaranteed FG's remaining payments due to CSX and BNSF in connection with the definitive settlement of a coal transportation agreement dispute. As of March 31, 2018, FE recorded an obligation for this guarantee in other current liabilities with a corresponding loss from discontinued operations. On April 6, 2018, FE paid the remaining $72 million owed under the FES Bankruptcy settlement agreement. In addition, as of March 31, 2018, FE recorded, and on May 11, 2018, paid a $58 million obligation for a sale-leaseback indemnity in other current liabilities with a corresponding loss from discontinued operations. Under the terms of the FES Bankruptcy settlement agreement, FE will release all claims against the FES Debtors with respect to these guaranteed amounts. Purchase Power FES at times provides power through affiliated company power sales to meet a portion of the Utilities' POLR and default service requirements and provide power to certain affiliates' facilities. As of December 31, 2018, the Utilities owed FES approximately $27 million related to these purchases. The terms and conditions of the power purchase agreements are generally consistent with industry practices and other similar third-party arrangements. The Utilities purchased and recognized in continuing operations approximately $318 million of power purchases from FES for the year ended December 31, 2018. Income Taxes Until the FES Debtors emerge from bankruptcy, the FES Debtors will remain parties to the intercompany income tax allocation agreement with FE and its other subsidiaries, which 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. Under the terms of the FES Bankruptcy settlement agreement, FE agreed to waive settlement of the 2017 overpayment made to the FES Debtors and pay a minimum of $66 million to the FES Debtors for the 2018 tax year (approximately $52 million in estimated tax payments have been paid through December 31, 2018). For U.S. federal income taxes, until emergence from bankruptcy, the FES Debtors will continue to be consolidated in FirstEnergy’s tax return and taxable income will be determined based on the tax basis of underlying individual net assets. Deferred taxes previously recorded on the inside basis differences may not represent the actual tax consequence for the outside basis difference, causing a recharacterization of an existing consolidated-return NOL as a future worthless stock deduction. FirstEnergy currently estimates a future worthless stock deduction of approximately $4.8 billion ( $1.0 billion , net of tax) and is net of unrecognized tax benefits of $418 million ( $88 million , net of tax). The estimated worthless stock deduction is contingent upon the emergence of the FES Debtors from the FES Bankruptcy and such amounts may be materially impacted by future events. Because the FES Debtors remain part of FirstEnergy's consolidated tax return until emergence from bankruptcy, certain impacts of the Tax Act that otherwise would not occur on a consolidated basis have been reflected in discontinued operations. Specifically, all tax expense ( $60 million ) related to nondeductible interest in 2018 has been recorded in discontinued operations as it is entirely attributed to the anticipated inclusion of the FES Debtors in the FirstEnergy consolidated tax return. See further discussion in Note 7, "Taxes". See Note 1, "Organization and Basis of Presentation," for further discussion of the settlement among FirstEnergy, the FES Key Creditor Groups, the FES Debtors and the UCC. Competitive Generation Asset Sales FirstEnergy announced in January 2017 that AE Supply and AGC had entered into an asset purchase agreement with a subsidiary of LS Power, as amended and restated in August 2017, to sell four natural gas generating plants, AE Supply's interest in the Buchanan Generating facility and approximately 59% of AGC's interest in Bath County ( 1,615 MWs of combined capacity). On December 13, 2017, AE Supply completed the sale of the natural gas generating plants. On March 1, 2018, AE Supply completed the sale of the Buchanan Generating Facility. On May 3, 2018, AE Supply and AGC completed the sale of approximately 59% of AGC's interest in Bath County. In connection with its obligations under the asset purchase agreement, proceeds from the sales were used to redeem $405 million aggregate principal amount of outstanding AE Supply and AGC senior notes, which required payment of approximately $89 million in make-whole premiums, and AE Supply caused the redemption of approximately $142 million aggregate principal amount of PCRBs. Also, on May 3, 2018, following closing of the sale by AGC of a portion of its ownership interest in Bath County, AGC completed the redemption of AE Supply's shares in AGC and AGC became a wholly owned subsidiary of MP. On March 9, 2018, BSPC and FG entered into an asset purchase agreement with Walleye Power, LLC (formerly Walleye Energy, LLC), for the sale of the Bay Shore Generating Facility, including the 136 MW Bay Shore Unit 1 and other retired coal-fired generating equipment owned by FG. The Bankruptcy Court approved the sale on July 13, 2018, and the transaction was completed on July 31, 2018. As contemplated under the FES Bankruptcy settlement agreement, AE Supply entered into an agreement on December 31, 2018, to transfer the 1,300 MW Pleasants Power Station and related assets to FG, while retaining certain specified liabilities. Under the terms of the agreement, FG acquired the economic interests in Pleasants as of January 1, 2019, and AE Supply will operate Pleasants until the transfer is completed. After closing, AE Supply will continue to provide access to the McElroy's Run CCR Impoundment Facility, which is not being transferred, and FE will provide certain guarantees for retained environmental liabilities of AE Supply, including the McElroy’s Run CCR Impoundment Facility. The transfer of the Pleasants Power Station is subject to various customary and other closing conditions, including FERC approval of the transaction, the Bankruptcy Court’s approval of the agreement, effectiveness of the FES Bankruptcy settlement agreement and the effectiveness of a plan of reorganization for the FES Debtors in connection with the FES Bankruptcy. There can be no assurance that all closing conditions will be satisfied or that the transfer will be consummated. Individually, the AE Supply and BSPC asset sales and Pleasants Power Station transfer did not qualify for reporting as discontinued operations. However, in the aggregate, the transactions were part of management’s strategic review to exit commodity-exposed generation and, when considered with FES' and FENOC’s bankruptcy filings on March 31, 2018, represent a collective elimination of substantially all of FirstEnergy’s competitive generation fleet and meet the criteria for discontinued operations. Summarized Results of Discontinued Operations Summarized results of discontinued operations for the years ended December 31, 2018, 2017 and 2016 were as follows: For the Years Ended December 31, (In millions) 2018 2017 2016 Revenues $ 989 $ 3,055 $ 3,794 Fuel (304 ) (879 ) (1,073 ) Purchased power (84 ) (268 ) (533 ) Other operating expenses (435 ) (1,499 ) (1,263 ) Provision for depreciation (96 ) (109 ) (378 ) General taxes (35 ) (103 ) (129 ) Impairment of assets (2) — (2,358 ) (10,622 ) Other expense, net (83 ) (94 ) (106 ) Loss from discontinued operations, before tax (48 ) (2,255 ) (10,310 ) Income tax expense (benefit) (1) 61 (820 ) (3,582 ) Loss from discontinued operations, net of tax (109 ) (1,435 ) (6,728 ) Gain on disposal of FES and FENOC, net of tax 435 — — Income (Loss) from discontinued operations $ 326 $ (1,435 ) $ (6,728 ) (1) In conjunction with the sale of an interest in Bath County, AGC wrote off and recognized as a benefit in discontinued operations in the second quarter of 2018 its excess deferred tax liabilities of $32 million , created from the Tax Act, since they are not required to be refunded to ratepayers. Nondeductible interest of $60 million in 2018 has been recorded in discontinued operations as it is entirely attributed to the anticipated inclusion of the FES Debtors in the FirstEnergy consolidated tax return. See further discussion in Note 7, "Taxes". (2) Impairment of assets included in discontinued operations for the year ended December 31, 2017 include amounts related to impairment of the FES nuclear facilities, the Pleasants Power Station ( $120 million in the fourth quarter of 2017), and the competitive asset generation sale ( $193 million during 2017). Amounts included for the year ended December 31, 2016, include impairment of FES coal and nuclear plants and goodwill associated with AE Supply and FES, as well as other competitive assets including materials and supplies. The gain on disposal that was recognized in the year ended December 31, 2018, consisted of the following: (In millions) 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 (1,197 ) Loss on disposal of FES and FENOC, before tax (877 ) Income tax benefit, including estimated worthless stock deduction 1,312 Gain on disposal of FES and FENOC, net of tax $ 435 The following table summarizes the major classes of assets and liabilities as discontinued operations as of December 31, 2018, and 2017: (In millions) December 31, 2018 December 31, 2017 Carrying amount of the major classes of assets included in discontinued operations: Cash and cash equivalents $ — $ 1 Restricted cash — 3 Receivables — 202 Materials and supplies 25 227 Prepaid taxes and other — 199 Total current assets 25 632 Property, plant and equipment — 1,132 Investments — 1,875 Other noncurrent assets — 356 Total noncurrent assets — 3,363 Total assets included in discontinued operations $ 25 $ 3,995 Carrying amount of the major classes of liabilities included in discontinued operations: Currently payable long-term debt $ — $ 524 Accounts payable — 200 Accrued taxes — 38 Accrued compensation and benefits — 79 Other current liabilities — 137 Total current liabilities — 978 Long-term debt and other long-term obligations — 2,428 Accumulated deferred income taxes (1) — (1,812 ) Asset retirement obligations — 1,945 Deferred gain on sale and leaseback transaction — 723 Other noncurrent liabilities — 244 Total noncurrent liabilities — 3,528 Total liabilities included in discontinued operations $ — $ 4,506 (1) Represents an increase in FirstEnergy's ADIT liability as an ADIT asset was removed upon deconsolidation of FES and FENOC. FirstEnergy's Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items as discontinued operations for the years ended December 31, 2018, 2017 and 2016: For the Years Ended December 31, (In millions) 2018 2017 2016 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ 326 $ (1,435 ) $ (6,728 ) Gain on disposal, net of tax (435 ) — — Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs 110 333 669 Deferred income taxes and investment tax credits, net 61 (842 ) (3,582 ) Unrealized (gain) loss on derivative transactions (10 ) 81 9 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (27 ) (317 ) (615 ) Nuclear fuel — (254 ) (232 ) Sales of investment securities held in trusts 109 940 717 Purchases of investment securities held in trusts (122 ) (999 ) (783 )

Revenue

Revenue	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Revenue	REVENUE FirstEnergy accounts for revenues from contracts with customers under ASC 606, Revenue from Contracts with Customers, which became effective January 1, 2018. As part of the adoption of ASC 606, FirstEnergy applied the new standard on a modified retrospective basis analyzing open contracts as of January 1, 2018. However, no cumulative effect adjustment to retained earnings was necessary as no revenue recognition differences were identified when comparing the revenue recognition criteria under ASC 606 to previous requirements. Revenue from leases, financial instruments, other contractual rights or obligations and other revenues that are not from contracts with customers are outside the scope of the new standard and accounted for under other existing GAAP. FirstEnergy has elected to exclude sales taxes and other similar taxes collected on behalf of third parties from revenue as prescribed in the new standard. As a result, tax collections and remittances within the scope of this election are excluded from recognition in the income statement and instead recorded through the balance sheet, consistent with FirstEnergy’s accounting process prior to the adoption of ASC 606. Excise and gross receipts taxes that are assessed on FirstEnergy are not subject to the election and are included in revenue. FirstEnergy has elected the optional invoice practical expedient for most of its revenues and, with the exception of JCP&L transmission, utilizes the optional short-term contract exemption for transmission revenues due to the annual establishment of revenue requirements, which eliminates the need to provide certain revenue disclosures regarding unsatisfied performance obligations. For a qualitative overview of FirstEnergy's performance obligations, see below. FirstEnergy’s revenues are primarily derived from electric service provided by its Utilities and Transmission subsidiaries. The following tables represent a disaggregation of revenue from contracts with customers for the year ended December 31, 2018, by type of service from each reportable segment: 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 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 $147 million in net 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). Other non-customer revenue primarily includes revenue from derivatives and late payment charges of $18 million and $39 million , respectively, for the year ended December 31, 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. 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 16 "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 year ended December 31, 2018, by class: Revenues by Customer Class (In millions) Residential $ 5,598 Commercial 2,350 Industrial 1,056 Other 91 Total $ 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 from PJM to supply power to their customers. Generally, these power sales from generation and purchases to serve load are netted hourly and reported gross as either revenues or purchased power on the Consolidated Statements of Income (Loss) 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 BRA and incremental auctions. Capacity purchases and sales through PJM capacity auctions are reported within revenues on the Consolidated Statements of Income (Loss). 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 reverses the related prior period estimate. Customer payments vary by state but are generally due within 30 days. ASC 606 excludes industry-specific accounting guidance for recognizing revenue from ARPs as these programs represent contracts between the utility and its regulators, as opposed to customers. Therefore, revenue from these programs are not within the scope of ASC 606 and regulated utilities are permitted to continue to recognize such revenues in accordance with existing practice but are presented separately from revenue arising from contracts with customers. FirstEnergy currently has ARPs in Ohio, primarily under rider DMR, and in New Jersey. Regulated Transmission The Regulated Transmission segment provides transmission infrastructure owned and operated by 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. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. Revenue requirements under stated rates are calculated annually by multiplying the highest one-hour peak load in each respective transmission zone by the approved, stated rate in that zone. Revenues and cash receipts for the stand-ready obligation of providing transmission service are recognized ratably over time. Effective January 1, 2018, JCP&L is subject to a FERC-approved settlement agreement that provides an annual revenue requirement of $155 million through December 31, 2019 which is recognized ratably as revenue over time. The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the year ended December 31, 2018, by transmission owner: Revenues from Contracts with Customers by Transmission Asset Owner (In millions) ATSI $ 664 TrAIL 237 MAIT 150 Other 284 Total $ 1,335

Accumulated Other Comprehensive

Accumulated Other Comprehensive Income	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
ACCUMULATED OTHER COMPREHENSIVE INCOME	ACCUMULATED OTHER COMPREHENSIVE INCOME The changes in AOCI for the years ended December 31, 2018 , 2017 and 2016 , for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2016 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 106 13 119 Amounts reclassified from AOCI 8 (51 ) (72 ) (115 ) Other comprehensive income (loss) 8 55 (59 ) 4 Income tax (benefits) on other comprehensive income (loss) 3 21 (23 ) 1 Other comprehensive income (loss), net of tax 5 34 (36 ) 3 AOCI Balance, December 31, 2016 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 85 (11 ) 74 Amounts reclassified from AOCI 10 (63 ) (74 ) (127 ) Other comprehensive income (loss) 10 22 (85 ) (53 ) Income tax (benefits) on other comprehensive income (loss) 4 7 (32 ) (21 ) Other comprehensive income (loss), net of tax 6 15 (53 ) (32 ) AOCI Balance, December 31, 2017 $ (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 The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2018 , 2017 and 2016 : Year Ended December 31, Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (1) 2018 (3) 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 1 $ 2 $ — Other operating expenses Long-term debt 7 8 8 Interest expense 8 10 8 Total before taxes (2 ) (4 ) (3 ) Income taxes $ 6 $ 6 $ 5 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (1 ) $ (40 ) $ (32 ) Discontinued Operations Defined benefit pension and OPEB plans Prior-service costs $ (74 ) $ (74 ) $ (72 ) (2) 19 28 27 Income taxes $ (55 ) $ (46 ) $ (45 ) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Components are included in the computation of net periodic pension cost. See Note 5, "Pension and Other Postemployment Benefits," for additional details. (3) 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 ".

Stock-Based Compensation Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation Plans	STOCK-BASED COMPENSATION PLANS FirstEnergy grants stock-based awards through the ICP 2015, primarily in the form of restricted stock and performance-based restricted stock units. Under FirstEnergy's previous incentive compensation plan, the ICP 2007, FirstEnergy also granted stock options and performance shares. The ICP 2007 and ICP 2015 include shareholder authorization to issue 29 million shares and 10 million shares, respectively, of common stock or their equivalent. As of December 31, 2018 , approximately 4.7 million shares were available for future grants under the ICP 2015 assuming maximum performance metrics are achieved for the outstanding cycles of restricted stock units. No shares are available for future grants under the ICP 2007. Shares not issued due to forfeitures or cancellations may be added back to the ICP 2015. Shares granted under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from one 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. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," FE has elected to account for forfeitures as they occur. As discussed in Note 1, "Organization and Basis of Presentation," on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy will retain certain obligations for the FES Debtors employees' outstanding awards issued under the 2015 ICP for the 2016-2018 performance cycle. 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, 2018 , 2017 and 2016 , were $15 million , $15 million and $13 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 are included in the following tables: Years Ended December 31, Stock-based Compensation Plan 2018 2017 2016 (In millions) Restricted Stock Units $ 102 $ 49 $ 62 Restricted Stock 1 1 2 Performance Shares — — (3 ) 401(k) Savings Plan 33 42 39 EDCP & DCPD 7 6 5 Total $ 143 $ 98 $ 105 Stock-based compensation costs capitalized $ 60 $ 37 $ 37 Outstanding stock options were fully amortized as of December 31, 2016. Stock option expense was not material for FirstEnergy for the year December 31, 2016 , and there was no stock option expense for the years ended December 31, 2018 and 2017. Income tax benefits associated with stock-based compensation plan expense were $18 million, $10 million and $14 million for the years ended 2018 , 2017 and 2016 , 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. Outstanding restricted stock unit awards for FES and FENOC participants, however, were previously modified to only pay 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, 2018 , was $56 million . During 2018, approximately $30 million was paid in relation to the cash portion of restricted stock unit obligations that vested in 2018 . The vesting period for the performance-based restricted stock unit awards granted in 2016, 2017 and 2018, was each three 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, 2018 , was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2018 3.3 $ 33.24 Granted in 2018 2.0 36.78 Forfeited in 2018 (0.1 ) 33.77 Vested in 2018 (1) (1.9 ) 32.49 Nonvested as of December 31, 2018 3.3 $ 33.78 (1) Excludes dividend equivalents of approximately 143 thousand shares earned during vesting period. The weighted-average fair value of awards granted in 2018 , 2017 and 2016 was $ 36.78 , $31.71 and $34.77 , respectively. For the years ended December 31, 2018 , 2017 , and 2016 , the fair value of restricted stock units vested was $62 million , $42 million , and $36 million , respectively. As of December 31, 2018 , there was $30 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, 2018 , 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 2018 . Stock option activity during 2018 was as follows: Stock Option Activity Number of Shares (in millions) Weighted Average Exercise Price (per share) Balance, January 1, 2017 (all options exercisable) 1.4 $ 44.41 Options exercised (0.3 ) 35.45 Options forfeited (0.3 ) 79.99 Balance, December 31, 2018 (all options exercisable) 0.8 $ 37.37 Approximately $12 million of cash was received in 2018 from the exercise of stock options. There was no cash received from the exercise of stock options in 2017 and the amount in 2016 was not material. The weighted-average remaining contractual term of options outstanding as of December 31, 2018 , was 1.35 years . Performance Shares Prior to the 2015 grant of performance-based restricted stock units discussed above, performance shares were granted. Performance shares are share equivalents and do not have voting rights. The performance shares outstanding track the performance of FE's common stock over a three -year vesting period. Dividend equivalents accrued on performance shares and were reinvested into additional performance shares with the same performance conditions. The final award value could have been adjusted based on the performance of FE stock performance as compared to a composite of peer companies. In 2016 , $2 million cash was paid to settle performance shares that vested over the 2013-2015 performance cycle. In 2018 and 2017, no cash was paid to settle the last outstanding cycle of performance shares that could have vested over the 2014-2016 performance cycle. Following 2017, FirstEnergy no longer has outstanding performance share awards. 401(k) Savings Plan In each 2018 and 2017 , approximately 1.3 million shares of FE common stock 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 $9 million and $8 million as of December 31, 2018 and December 31, 2017 , respectively, is included in the caption “Retirement benefits,” on the Consolidated Balance Sheets.

Pension and Other Postemploymen

Pension and Other Postemployment Benefits	12 Months Ended
	Dec. 31, 2018
Retirement Benefits [Abstract]
PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS	PENSION AND OTHER POSTEMPLOYMENT 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. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2018, 2017, and 2016 were $145 million , $141 million , and $147 million , respectively. Of these amounts, approximately $1 million , $39 million , and $45 million , are included in discontinued operations for the years ended December 31, 2018, 2017, and 2016, respectively. In 2018, the pension and OPEB mark-to-market adjustment primarily reflects a 69 bps increase in the discount rate used to measure benefit obligations and lower than expected asset returns. 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. As a result of this contribution, FirstEnergy expects no required contributions through 2021. In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed 2017 funding obligations to its qualified pension plan with total contributions of $882 million (of which $138 million was cash contributions from FES), including $500 million of FE common stock contributed to the qualified pension plan on December 13, 2016. 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 2018 , FirstEnergy’s pension and OPEB plan assets experienced losses of $371 million , or (4.0)% , compared to gains of $999 million , or 15.1% , in 2017 and losses of $472 million , or 8.2% , in 2016 , and assumed a 7.50% rate of return for 2018, 2017 and 2016 which generated $605 million , $478 million and $429 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 increase or decrease 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. During 2018, the Society of Actuaries released its updated mortality improvement scale for pension plans, MP-2018, incorporating SSA mortality data from 2014-2016. The updated improvement scale indicates a slight decline in life expectancy. Due to the additional data on population mortality, the RP2014 mortality table with the projection scale MP-2018 was utilized to determine the 2018 benefit cost and obligation as of December 31, 2018, for the FirstEnergy pension and OPEB plans. The impact of using the projection scale MP-2018 resulted in a decrease in the projected pension benefit obligation of approximately $16 million and was included in the 2018 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 change did not affect the measurement of total benefit obligations or annual net period benefit cost and the change in service and interest cost is offset in the actuarial mark-to-market adjustment reported. This election is considered a change in estimate and, accordingly, accounted prospectively. Following adoption of ASU 2017-07, " Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost " in 2018, service costs, net of capitalization, continue to be reported within Other operating expenses on the FirstEnergy Consolidated Statements of Income (Loss). Non-service costs are reported within Miscellaneous income, net, within Other Income (Expense). Prior period amounts have been reclassified to conform with current year presentation. See Note 1, "Organization and Basis of Presentation," for additional information. Also in 2018, the FE Tomorrow cost cutting initiative was implemented to define the corporate services FirstEnergy would need to support its regulated business once the company exited commodity-exposed generation. Through the initiative, FirstEnergy sought to ensure the company has the right talent, organizational and cost structure to efficiently service customers and achieve its earnings growth targets. In support of the FE Tomorrow initiative, more than 80% of eligible employees, totaling nearly 500 people in the shared services, utility services and sustainability organizations, accepted a voluntary enhanced retirement package that included severance compensation and a temporary pension enhancement, with most employees having already retired. Management expects the cost savings resulting from the FE Tomorrow initiative to support the company's growth targets. Pension OPEB Obligations and Funded Status - Qualified and Non-Qualified Plans 2018 2017 2018 2017 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 10,167 $ 9,426 $ 731 $ 711 Service cost 224 208 5 5 Interest cost 372 390 25 27 Plan participants’ contributions — — 3 4 Plan amendments 5 11 5 — Special termination benefits 31 — 8 — Medicare retiree drug subsidy — — 1 1 Annuity purchase (129 ) — — — Actuarial (gain) loss (710 ) 610 (121 ) 32 Benefits paid (498 ) (478 ) (49 ) (49 ) Benefit obligation as of December 31 $ 9,462 $ 10,167 $ 608 $ 731 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 6,704 $ 6,213 $ 439 $ 420 Actual return on plan assets (363 ) 950 (8 ) 49 Annuity purchase (129 ) — — — Company contributions 1,270 18 22 16 Plan participants’ contributions — — 3 4 Benefits paid (498 ) (477 ) (48 ) (50 ) Fair value of plan assets as of December 31 $ 6,984 $ 6,704 $ 408 $ 439 Funded Status: Qualified plan $ (2,093 ) $ (3,043 ) $ — $ — Non-qualified plans (385 ) (420 ) — — Funded Status $ (2,478 ) $ (3,463 ) $ (200 ) $ (292 ) Accumulated benefit obligation $ 8,951 $ 9,583 $ — $ — Amounts Recognized on the Balance Sheet: Noncurrent assets $ 14 $ — $ — $ — Current liabilities (20 ) (19 ) — — Noncurrent liabilities (2,472 ) (3,444 ) (200 ) (292 ) Net liability as of December 31 $ (2,478 ) $ (3,463 ) $ (200 ) $ (292 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 30 $ 32 $ (121 ) $ (206 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 4.44 % 3.75 % 4.30 % 3.50 % Rate of compensation increase 4.10 % 4.20 % N/A N/A Cash balance weighted average interest crediting rate 3.34 % 2.88 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) 6.0-5.5% 6.0-5.5% 6.0-5.5% 6.0-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) 4.5 % 4.5 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate 2028 2027 2028 2027 Allocation of Plan Assets (as of December 31) Equity securities 36 % 42 % 48 % 50 % Bonds 34 % 32 % 35 % 33 % Absolute return strategies 11 % 10 % — % — % Real estate funds 10 % 9 % — % — % Derivatives 2 % — % — % — % Private equity funds 2 % 1 % — % — % Cash and short-term securities 5 % 6 % 17 % 17 % Total 100 % 100 % 100 % 100 % Components of Net Periodic Benefit Costs for Years Ended December 31, Pension OPEB 2018 2017 2016 2018 2017 2016 (In millions) Service cost $ 224 $ 208 $ 191 $ 5 $ 5 $ 5 Interest cost 372 390 398 25 27 30 Expected return on plan assets (574 ) (448 ) (399 ) (31 ) (30 ) (30 ) Amortization of prior service cost (credit) 7 7 8 (81 ) (81 ) (80 ) Special termination costs 31 — — 8 — — Pension & OPEB mark-to-market adjustment 227 108 179 (82 ) 13 15 Net periodic benefit cost (credit) $ 287 $ 265 $ 377 $ (156 ) $ (66 ) $ (60 ) Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31,* Pension OPEB 2018 2017 2016 2018 2017 2016 Weighted-average discount rate 3.75 % 4.25 % 4.50 % 3.50 % 4.00 % 4.25 % Expected long-term return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A N/A * Excludes impact of pension and OPEB mark-to-market adjustment. Amounts in the tables above include FES' and FENOC's share of the net periodic pension and OPEB costs (credits) of $64 million and $(25) million , respectively, for the year ended December 31, 2018. FES' and FENOC's share of the net periodic pension and OPEB costs (credits) were $60 million and $(17) million , respectively, for the year ended December 31, 2017. Such amounts are a component of Discontinued Operations in FirstEnergy's Consolidated Statements of Income (Loss). Following FES and FENOC’s voluntary bankruptcy filing, FE has billed FES and FENOC for their share of pension and OPEB service costs of $42 million for the last nine months of 2018. 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 11, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2018 and 2017 . December 31, 2018 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 342 $ — $ 342 5 % Equity investments: Domestic 723 122 — 845 12 % International 392 1,232 — 1,624 22 % Fixed income: Government bonds — 59 — 59 1 % Corporate bonds — 1,674 — 1,674 23 % High yield debt — 667 — 667 10 % Alternatives: Hedge funds (absolute return) — 681 — 681 11 % Derivatives 108 — — 108 2 % Real estate funds — — 665 665 10 % Total (1) $ 1,223 $ 4,777 $ 665 $ 6,665 96 % Private equity funds (2) 143 2 % Insurance-linked securities (2) 108 2 % Total Investments $ 6,916 100 % (1) Excludes $68 million as of December 31, 2018 , 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. December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 379 $ — $ 379 6 % Equity investments: Domestic 695 27 — 722 11 % International 514 1,569 — 2,083 31 % Fixed income: Government bonds — 251 — 251 4 % Corporate bonds — 1,237 — 1,237 18 % High yield debt — 689 — 689 10 % Mortgage-backed securities (non-government) — 31 — 31 — % Alternatives: Hedge funds (absolute return) — 635 — 635 10 % Derivatives — (1 ) — (1 ) — % Real estate funds — — 631 631 9 % Total (1) $ 1,209 $ 4,817 $ 631 $ 6,657 99 % Private equity funds (2) 57 1 % Total Investments $ 6,714 100 % (1) Excludes $(10) million as of December 31, 2017 , 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. The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2018 and 2017 : Real Estate Funds Balance as of January 1, 2017 $ 615 Actual return on plan assets: Unrealized gains 3 Realized gains 10 Transfers in 3 Balance as of December 31, 2017 $ 631 Actual return on plan assets: Unrealized gains 102 Realized losses (65 ) Transfers out (3 ) Balance as of December 31, 2018 $ 665 As of December 31, 2018 and 2017 , the OPEB trust investments measured at fair value were as follows: December 31, 2018 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 71 $ — $ 71 17 % Equity investment: Domestic 196 — — 196 48 % Fixed income: Government bonds — 107 — 107 26 % Corporate bonds — 32 — 32 8 % Mortgage-backed securities (non-government) 4 — 4 1 % Total (1) $ 196 $ 214 $ — $ 410 100 % (1) Excludes $(2) million as of December 31, 2018 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 75 $ — $ 75 17 % Equity investment: Domestic 220 — — 220 50 % Fixed income: Government bonds — 109 — 109 24 % Corporate bonds — 34 — 34 8 % Mortgage-backed securities (non-government) 3 — 3 1 % Total (1) $ 220 $ 221 $ — $ 441 100 % (1) Excludes $(2) million as of December 31, 2017 , 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. FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2018 and 2017 are shown in the following table: Target Asset Allocations Equities 38 % Fixed income 30 % Absolute return strategies 8 % Real estate 10 % Alternative investments 8 % Cash 6 % 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) 2019 $ 509 $ 57 $ (1 ) 2020 533 48 (1 ) 2021 554 48 (1 ) 2022 566 47 (1 ) 2023 580 46 (1 ) Years 2024-2028 3,047 213 (3 )

Taxes

Taxes	12 Months Ended
	Dec. 31, 2018
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, as well as FES and FENOC, 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. FES and FENOC are expected to remain parties to the intercompany tax allocation agreement until their emergence from bankruptcy, which is when they will no longer be part of FirstEnergy's consolidated tax group. On December 22, 2017, the President signed into law the Tax Act, which included significant changes to the Internal Revenue Code of 1986 (as amended, the Code). The more significant changes that impacted FirstEnergy were as follows: • Reduction of the corporate federal income tax rate from 35% to 21%, effective in 2018; • Full expensing of qualified property, excluding rate regulated utilities, through 2022 with a phase down beginning in 2023; • Limitations on interest deductions with an exception for rate regulated utilities, effective in 2018; • Limitation of the utilization of federal NOLs arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward; • Repeal of the corporate AMT and allowing taxpayers to claim a refund on any AMT credit carryovers. At December 31, 2017, FirstEnergy completed its assessment of the accounting for certain effects of the provisions in the Tax Act, and as allowed under SEC Staff Accounting Bulletin 118 (SAB 118), recorded provisional income tax amounts related to depreciation for which the impacts of the Tax Act could not be finalized, but for which a reasonable estimate could be determined. Under the Tax Act, qualified property acquired and placed into service after September 27, 2017, would be eligible for full expensing for all taxpayers other than regulated utilities. On August 3, 2018, the IRS released proposed regulations clarifying the immediate expensing of qualified property, specifically addressing that regulated utility property acquired after September 27, 2017, and placed into service by December 31, 2017, qualifies for full expensing. While not final as of December 31, 2018, corporate taxpayers may rely on the proposed regulations for tax years ending after September 27, 2017. As of December 31, 2018, FirstEnergy has now completed its accounting for all of the enactment-date income tax effects of the Tax Act, resulting in an immaterial adjustment to the provisional income tax amounts recorded at December 31, 2017. The Tax Act also amended Section 163(j) of the Code, limiting interest expense deductions for corporations, with exemption for certain regulated utilities. On November 26, 2018, the IRS issued proposed regulations implementing Section 163(j), including its application of the rules to consolidated groups with both regulated utility and non-regulated members. Based on its interpretation of these proposed regulations, FirstEnergy has estimated the amount of deductible interest for its consolidated group in 2018 and has recorded a deferred tax asset on the nondeductible portion as it is carried forward with an indefinite life. The deferred tax asset related to the indefinite lived carryforward of nondeductible interest has a full valuation allowance ( $60 million ) recorded against it as future profitability from sources other than regulated utility businesses is required for utilization. Of this tax effected nondeductible interest, $27 million has been reflected as an uncertain tax position. All tax expense related to nondeductible interest in 2018 has been recorded in discontinued operations as it is entirely attributed to the anticipated inclusion of entities reported in discontinued operations in FirstEnergy's consolidated federal tax return. For the Years Ended December 31, INCOME TAXES (1) 2018 2017 2016 (In millions) Currently payable (receivable)- Federal $ (16 ) $ 14 $ (1 ) State 17 20 9 1 34 8 Deferred, net- Federal 252 1,647 317 State 243 40 208 495 1,687 525 Investment tax credit amortization (6 ) (6 ) (6 ) Total income taxes $ 490 $ 1,715 $ 527 (1) Income Taxes on Income from Continuing Operations. Currently payable (receivable) in 2018 excludes $1 million of state taxes associated with discontinued operations. Deferred, net in 2018 excludes $1.3 billion of federal tax benefits and $12 million of state taxes associated with discontinued operations. 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, 2018, 2017 and 2016: For the Years Ended December 31, 2018 2017 2016 (In millions) Income from Continuing Operations, before income taxes $ 1,512 $ 1,426 $ 1,078 Federal income tax expense at statutory rate (21%, 35%, and 35% for 2018, 2017, and 2016, respectively) $ 318 $ 499 $ 377 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 90 40 16 AFUDC equity and other flow-through (31 ) (15 ) (13 ) Amortization of investment tax credits (5 ) (6 ) (6 ) ESOP dividend (3 ) (5 ) (4 ) Remeasurement of deferred taxes 24 1,193 — WV unitary group remeasurement 126 — — Excess deferred tax amortization due to the Tax Act (60 ) — — Uncertain tax positions 2 (3 ) (8 ) Valuation allowances 21 11 160 Other, net 8 1 5 Total income taxes $ 490 $ 1,715 $ 527 Effective income tax rate 32.4 % 120.3 % 49.0 % Excluding the impact of the remeasurement of FES's and FENOC's deferred taxes in 2017 resulting from the Tax Act, FirstEnergy’s effective tax rate on continuing operations was 43.3% . Although FES' and FENOC's operations are presented in discontinued operations, the 2017 remeasurement of deferred taxes remain in continuing operations in accordance with accounting standards for the impact of tax rate changes. Compared to FirstEnergy's effective tax rate on continuing operations in 2018 of 32.4% , the decrease from 2017 is primarily due to the decrease in the corporate federal income tax rate from 35% to 21%. Additionally, in 2018, FirstEnergy’s regulated distribution and transmission subsidiaries began amortizing the net regulatory liability associated with excess deferred taxes, resulting in an income tax benefit that reduced the effective tax rate. The income tax benefit is offset by a corresponding reduction in revenues, resulting from rate orders implemented by various regulatory commissions (see Note 16 "Regulatory Matters," for additional detail). These decreases were partially offset by the impact of the legal and financial separation of FES and FENOC from FirstEnergy in the first quarter of 2018 that officially eroded the ties between FES, FENOC and other FE subsidiaries doing business in West Virginia. As such, FES and FENOC were removed from the West Virginia unitary group when calculating West Virginia state income taxes, resulting in a $126 million charge to income tax expense in continuing operations associated with the remeasurement in state deferred taxes. 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, 2018 and 2017 , are as follows: As of December 31, 2018 2017 (In millions) Property basis differences $ 4,737 $ 4,354 Pension and OPEB (629 ) (708 ) TMI-2 nuclear decommissioning 82 37 AROs (215 ) (157 ) Regulatory asset/liability 414 416 Deferred compensation (170 ) (149 ) Estimated worthless stock deduction (1,004 ) — Loss carryforwards and AMT credits (899 ) (863 ) Valuation reserve 394 312 All other (208 ) (71 ) Net deferred income tax liability $ 2,502 $ 3,171 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, 2018, FirstEnergy's loss carryforwards and AMT credits consisted of $2.4 billion ( $493 million , net of tax) of Federal NOL carryforwards that will begin to expire in 2031 and Federal AMT credits of $18 million that have an indefinite carryforward period. The table below summarizes pre-tax NOL carryforwards for state and local income tax purposes of approximately $7.6 billion ( $365 million , net of tax) for FirstEnergy, of which approximately $2.1 billion ( $100 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. In addition to the valuation allowances on state and local NOLs, FirstEnergy has recorded a reserve against certain state and local property related DTAs (approximately $59 million , net of tax) and a reserve against the estimated nondeductible portion of interest expense, discussed above. Expiration Period State Local (In millions) 2019-2023 $ 1,583 $ 1,581 2024-2028 1,526 — 2029-2033 1,862 — 2034-2038 1,067 — $ 6,038 $ 1,581 FirstEnergy accounts for uncertainty in income taxes recognized in its financial statements. A recognition threshold and measurement attribute is utilized for financial statement recognition and measurement of tax positions taken or expected to be taken on the tax return. As of December 31, 2018 and 2017 , FirstEnergy's total unrecognized income tax benefits were approximately $158 million and $80 million , respectively. The change in unrecognized income tax benefits from the prior year is primarily attributable to a reserve of approximately $27 million for the estimated nondeductible interest under Section 163(j) and $88 million for reserves on the estimated worthless stock deduction. See Note 3, Discontinued Operations, for further discussion. If ultimately recognized in future years, approximately $142 million of unrecognized income tax benefits would impact the effective tax rate. On October 18, 2017, the Supreme Court of Pennsylvania affirmed the Commonwealth Court’s holding that the state’s net loss carryover provision violated the Pennsylvania Uniformity Clause and was unconstitutional. However, the court also opined that the portion of the net loss carryover provision that created the violation may be severed from the statute, enabling the statute to operate as the legislature intended, and on October 30, 2017, the Pennsylvania Governor signed House Bill 542 into law which, among other things, amended Pennsylvania’s limitation on net loss deductions to remove the flat-dollar limitation. On January 4, 2018, the Pennsylvania Supreme Court denied to further hear any arguments related to the matter and, as a result, FirstEnergy withdrew its protective refund claims from the state of Pennsylvania on January 30, 2018. Upon doing so, FirstEnergy reversed a previously recorded unrecognized tax benefit of approximately $45 million in the first quarter of 2018, none of which impacted FirstEnergy’s effective tax rate. As of December 31, 2018 , it is reasonably possible that approximately $6 million of unrecognized tax benefits may be resolved during 2019 as a result of settlements with taxing authorities or the statute of limitations expiring, of which $2 million would affect FirstEnergy's effective tax rate. The following table summarizes the changes in unrecognized tax positions for the years ended 2018 , 2017 and 2016 : (In millions) Balance, January 1, 2016 $ 26 Current year increases 2 Prior years increases 69 Prior years decreases (13 ) Balance, December 31, 2016 $ 84 Current year increases 2 Decrease for lapse in statute (6 ) Balance, December 31, 2017 $ 80 Current year increases 125 Prior years decreases (45 ) Decrease for lapse in statute (2 ) Balance, December 31, 2018 $ 158 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 2018 , 2017 and 2016 , was not material. For the years ended December 31, 2018 and 2017 , 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. FirstEnergy's tax returns for all state jurisdictions are open from 2009-2017. In January 2018, the IRS completed its examination of FirstEnergy's 2016 federal income tax return and issued a Full Acceptance Letter with no changes or adjustments to FirstEnergy's taxable income. Tax year 2017 is currently under review by the IRS. General Taxes General tax expense for the years ended December 31, 2018 , 2017 and 2016 , recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2018 2017 2016 (In millions) KWH excise $ 198 $ 188 $ 196 State gross receipts 192 184 184 Real and personal property 478 452 421 Social security and unemployment 103 96 91 Other 22 20 21 Total general taxes $ 993 $ 940 $ 913

Leases

Leases	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Leases	LEASES FirstEnergy leases certain office space and other property and equipment under cancelable and noncancelable leases. Operating lease expense for the years ended December 31, 2018 , 2017 and 2016 , was $48 million , $53 million and $62 million , respectively. The future minimum capital lease payments as of December 31, 2018 , are as follows: Capital Leases (In millions) 2019 $ 24 2020 19 2021 16 2022 13 2023 8 Years thereafter 16 Total minimum lease payments 96 Interest portion (23 ) Present value of net minimum lease payments 73 Less current portion 18 Noncurrent portion $ 55 The future minimum operating lease payments as of December 31, 2018 , are as follows: Operating Leases (In millions) 2019 $ 34 2020 36 2021 34 2022 30 2023 28 Years thereafter 127 Total minimum lease payments $ 289

Intangible Assets

Intangible Assets	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
INTANGIBLE ASSETS	INTANGIBLE ASSETS As of December 31, 2018 , 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 2018 2019 2020 2021 2022 2023 Thereafter NUG contracts (1) $ 124 $ 41 $ 83 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 58 OVEC 8 3 5 — 1 — — — 1 3 Coal contracts (2) 102 97 5 3 3 2 — — — — $ 234 $ 141 $ 93 $ 8 $ 9 $ 7 $ 5 $ 5 $ 6 $ 61 (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.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2018
Variable Interest Entities [Abstract]
VARIABLE INTEREST ENTITIES	VARIABLE INTEREST ENTITIES FirstEnergy performs qualitative analyses based on control and economics to determine whether a variable interest classifies FirstEnergy as the primary beneficiary (a controlling financial interest) of a VIE. An enterprise has a controlling financial interest if it has both power and economic control, such that an entity has: (i) the power to direct the activities of a VIE that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. FirstEnergy consolidates a VIE when it is determined that it is the primary beneficiary. In order to evaluate contracts for consolidation treatment and entities for which FirstEnergy has an interest, FirstEnergy aggregates variable interests into categories based on similar risk characteristics and significance. Consolidated VIEs VIEs in which FirstEnergy is the primary beneficiary consist of the following (included in FirstEnergy’s consolidated financial statements): • Ohio Securitization - In September 2012, the Ohio Companies created separate, wholly owned limited liability company SPEs which issued phase-in recovery bonds to securitize the recovery of certain all-electric customer heating discounts, fuel and purchased power regulatory assets. The phase-in recovery bonds are payable only from, and secured by, phase-in recovery property owned by the SPEs. The bondholder has no recourse to the general credit of FirstEnergy or any of the Ohio Companies. Each of the Ohio Companies, as servicer of its respective SPE, manages and administers the phase-in recovery property including the billing, collection and remittance of usage-based charges payable by retail electric customers. In the aggregate, the Ohio Companies are entitled to annual servicing fees of $445 thousand that are recoverable through the usage-based charges. The SPEs are considered VIEs and each one is consolidated into its applicable utility. As of December 31, 2018 and December 31, 2017 , $292 million and $315 million of the phase-in recovery bonds were outstanding, respectively. • JCP&L Securitization - In August 2006, JCP&L Transition Funding II sold transition bonds to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. JCP&L did not purchase and does not own any of the transition bonds, which are included as long-term debt on FirstEnergy’s Consolidated Balance Sheets. The transition bonds are the sole obligations of JCP&L Transition Funding II and are collateralized by its equity and assets, which consist primarily of bondable transition property. As of December 31, 2018 and December 31, 2017 , $41 million and $56 million of the transition bonds were outstanding, respectively. • MP and PE Environmental Funding Companies - The entities issued bonds, the proceeds of which were used to construct environmental control facilities. The limited liability company SPEs own the irrevocable right to collect non-bypassable environmental control charges from all customers who receive electric delivery service in MP's and PE's West Virginia service territories. Principal and interest owed on the environmental control bonds is secured by, and payable solely from, the proceeds of the environmental control charges. Creditors of FirstEnergy, other than the limited liability company SPEs, have no recourse to any assets or revenues of the special purpose limited liability companies. As of December 31, 2018 and December 31, 2017 , $358 million and $383 million of the environmental control bonds were outstanding, respectively. Unconsolidated VIEs FirstEnergy is not the primary beneficiary of the following VIEs: • Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint ventures economic performance. FEV's ownership interest is subject to the equity method of accounting. As of December 31, 2018 , the carrying value of the equity method investment was $7 million . As discussed in Note 17, "Commitments, Guarantees and Contingencies," FE is the guarantor under Global Holding's $300 million term loan facility, which matures in March 2020 and has an outstanding principal balance of $190 million as of December 31, 2018 . 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, 2018 , the carrying value of the equity method investment was $ 17 million . • Purchase Power Agreements - FirstEnergy evaluated its PPAs and determined that certain NUG entities at its Regulated Distribution segment may be VIEs to the extent that they own a plant that sells substantially all of its output to the applicable utilities and the contract price for power is correlated with the plant’s variable costs of production. FirstEnergy maintains 11 long-term PPAs with NUG entities that were entered into pursuant to PURPA. FirstEnergy was not involved in the creation of, and has no equity or debt invested in, any of these entities. FirstEnergy has determined that for all but one of these NUG entities, it does not have a variable interest or the entities do not meet the criteria to be considered a VIE. FirstEnergy may hold a variable interest in the remaining one entity; however, it applied the scope exception that exempts enterprises unable to obtain the necessary information to evaluate entities. Because FirstEnergy has no equity or debt interests in the NUG entities, its maximum exposure to loss relates primarily to the above-market costs incurred for power. FirstEnergy expects any above-market costs incurred at its Regulated Distribution segment to be recovered from customers. Purchased power costs related to the contract that may contain a variable interest were $108 million and $112 million , respectively, during the years ended December 31, 2018 and 2017 . • FES and FENOC - As a result of the Chapter 11 bankruptcy filing discussed in Note 3, "Discontinued Operations," FE evaluated its investments in FES and FENOC and determined they are VIEs. FE is not the primary beneficiary because it lacks a controlling interest in FES and FENOC, which are subject to the jurisdiction of the Bankruptcy Court as of March 31, 2018. The carrying values of the equity investments in FES and FENOC were zero at December 31, 2018 .

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2018
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. See Note 12, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs. 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 ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement. FirstEnergy primarily applies the market approach for recurring fair value measurements using the best information available. Accordingly, FirstEnergy maximizes the use of observable inputs and minimizes the use of unobservable inputs. There were no changes in valuation methodologies used as of December 31, 2018 , from those used as of December 31, 2017 . 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, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 405 $ — $ 405 $ — $ 476 $ — $ 476 Derivative assets FTRs (1) — — 10 10 — — 3 3 Equity securities (2) 339 — — 339 297 — — 297 Foreign government debt securities — 13 — 13 — 23 — 23 U.S. government debt securities — 20 — 20 — 21 — 21 U.S. state debt securities — 250 — 250 — 247 — 247 Other (3) 367 34 — 401 588 38 — 626 Total assets $ 706 $ 722 $ 10 $ 1,438 $ 885 $ 805 $ 3 $ 1,693 Liabilities Derivative liabilities FTRs (1) $ — $ — $ (1 ) $ (1 ) $ — $ — $ — $ — Derivative liabilities NUG contracts (1) — — (44 ) (44 ) — — (79 ) (79 ) Total liabilities $ — $ — $ (45 ) $ (45 ) $ — $ — $ (79 ) $ (79 ) Net assets (liabilities) (4) $ 706 $ 722 $ (35 ) $ 1,393 $ 885 $ 805 $ (76 ) $ 1,614 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index. (3) Primarily consists of short-term cash investments. (4) Excludes $4 million and $(11) million as of December 31, 2018 and December 31, 2017 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. Rollforward of Level 3 Measurements The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2018 and December 31, 2017 : NUG Contracts (1) FTRs (1) Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2017 Balance $ 1 $ (108 ) $ (107 ) $ 3 $ (1 ) $ 2 Unrealized gain (loss) — (10 ) (10 ) 1 (1 ) — Purchases — — — 3 — 3 Settlements (1 ) 39 38 (4 ) 2 (2 ) December 31, 2017 Balance $ — $ (79 ) $ (79 ) $ 3 $ — $ 3 Unrealized gain (loss) — 2 2 8 1 9 Purchases — — — 5 (5 ) — Settlements — 33 33 (6 ) 3 (3 ) December 31, 2018 Balance $ — $ (44 ) $ (44 ) $ 10 $ (1 ) $ 9 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. Level 3 Quantitative Information The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2018 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 9 Model RTO auction clearing prices $0.20 to $6.10 $1.80 Dollars/MWH NUG Contracts $ (44 ) Model Generation 400 to 1,214,000 $31.40 to $33.60 249,000 $32.60 MWH INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes. Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries. Nuclear Decommissioning and Nuclear Fuel Disposal Trusts JCP&L, ME and PN hold debt and equity securities within their respective NDT and nuclear fuel disposal trusts. The debt securities are classified as AFS securities, recognized at fair market value. The following table summarizes the amortized cost basis, unrealized gains, unrealized losses and fair values of investments held in NDT and nuclear fuel disposal trusts as of December 31, 2018 and December 31, 2017 : December 31, 2018 (1) December 31, 2017 (1) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 714 $ 2 $ (28 ) $ 688 $ 774 $ 11 $ (17 ) $ 768 Equity securities $ 339 $ 15 $ (16 ) $ 338 $ 254 $ 40 $ — $ 294 (1) Excludes short-term cash investments of $20 million and $11 million in 2018 and 2017, respectively. Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three years ended December 31, 2018 , 2017 and 2016 , were as follows: 2018 2017 2016 (In millions) Sale Proceeds $ 800 $ 1,230 $ 961 Realized Gains 41 74 53 Realized Losses (48 ) (58 ) (52 ) OTTI — — (2 ) Interest and Dividend Income 41 39 44 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 $253 million a nd $ 255 million as of December 31, 2018 and December 31, 2017 , respectively, and are excluded from the amounts reported above. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS All borrowings with initial maturities of less than one year are defined as short-term financial instruments under GAAP and are reported as Short-term borrowings on the Consolidated Balance Sheets at cost. Since these borrowings are short-term in nature, FirstEnergy believes that their costs approximate their fair market value. The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of December 31, 2018 and 2017: As of December 31, 2018 2017 (In millions) Carrying Value $ 18,315 $ 19,296 Fair Value 19,266 21,412 The fair values of long-term debt and other long-term obligations reflect the present value of the cash outflows relating to those securities based on the current call price, the yield to maturity or the yield to call, as deemed appropriate at the end of each respective period. The yields assumed were based on securities with similar characteristics offered by corporations with credit ratings similar to those of FirstEnergy. FirstEnergy classified short-term borrowings, long-term debt and other long-term obligations as Level 2 in the fair value hierarchy as of December 31, 2018 and December 31, 2017 .

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
DERIVATIVE INSTRUMENTS	DERIVATIVE INSTRUMENTS FirstEnergy is exposed to financial risks resulting from fluctuating interest rates and commodity prices, including prices for electricity, coal and energy transmission. To manage the volatility related to these exposures, FirstEnergy’s Risk Policy Committee, comprised of senior management, provides general management oversight for risk management activities throughout FirstEnergy. The Risk Policy Committee is responsible for promoting the effective design and implementation of sound risk management programs and oversees compliance with corporate risk management policies and established risk management practice. FirstEnergy also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance. FirstEnergy has contractual derivative agreements through 2020 . Cash Flow Hedges FirstEnergy has used forward starting interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities of its subsidiaries. These derivatives were designated as cash flow hedges, protecting against the risk of changes in future interest payments resulting from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. Total pre-tax unamortized losses included in AOCI associated with prior interest rate cash flow hedges totaled $15 million and $22 million as of December 31, 2018 and December 31, 2017 , respectively. Based on current estimates, approximately $2 million of these unamortized losses are expected to be amortized to interest expense during the next twelve months. Refer to Note 4, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the years ended December 31, 2018 and 2017 . As of December 31, 2018 and December 31, 2017 , no commodity or interest rate derivatives were designated as cash flow hedges. Fair Value Hedges FirstEnergy has used fixed-for-floating interest rate swap agreements to hedge a portion of the consolidated interest rate risk associated with the debt portfolio of its subsidiaries. As of December 31, 2018 and December 31, 2017 , no fixed-for-floating interest rate swap agreements were outstanding. Unamortized gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements totaled $2 million and $3 million as of December 31, 2018 and December 31, 2017 , respectively. NUGs As of December 31, 2018 and December 31, 2017 , FirstEnergy's net liability position under NUG contracts was $44 million and $79 million , respectively, representing contracts held at JCP&L and PN. NUG contracts are classified as an adverse power contract liability on the Consolidated Balance Sheets. During the year ended December 31, 2018 , there were settlements of $33 million and unrealized gains of $2 million . Changes in the fair value of NUG contracts are subject to regulatory accounting treatment and do not impact earnings. FTRs As of December 31, 2018 and December 31, 2017 , FirstEnergy's net asset position associated with FTRs was $9 million and $3 million , respectively. FirstEnergy holds FTRs that generally represent an economic hedge of future congestion charges that will be incurred in connection with FirstEnergy’s load obligations. FirstEnergy acquires the majority of its FTRs in an annual auction through a self-scheduling process involving the use of ARRs allocated to members of PJM that have load serving obligations. For the year ended December 31, 2018 , there were settlements of $3 million and there were unrealized gains of $9 million . Changes in the fair value of FTR contracts are subject to regulatory accounting treatment and do not impact earnings.

Capitalization

Capitalization	12 Months Ended
	Dec. 31, 2018
Capitalization, Long-term Debt and Equity [Abstract]
Capitalization	CAPITALIZATION COMMON STOCK Retained Earnings and Dividends As of December 31, 2018 , FirstEnergy had an accumulated deficit of $4.9 billion . Dividends declared in 2018 and 2017 were $1.82 and $1.44 per share, respectively. In each 2018 and 2017, dividends of $0.36 per share were paid in the first, second, third and fourth quarters. On November 9, 2018 , the Board of Directors declared a quarterly dividend of $0.38 per share to be paid from other paid-in-capital in the first quarter of 2019 . 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, TrAIL and AGC have authorization from FERC to pay cash dividends to their respective parents from paid-in capital accounts, as long as their 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, 2018 . Common Stock Issuance 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). In addition, during 2018, 911,411 of preferred shares were converted into 33,238,910 common shares at the option of the preferred holders. An additional 494,767 preferred shares were converted into 18,044,018 common shares at the option of the holders in January 2019, resulting in 209,822 preferred shares outstanding and yet to be converted. Additionally, FE issued approximately 3.2 million shares of common stock in 2018, 3.0 million shares of common stock in 2017 and 2.7 million shares of common stock in 2016 to registered shareholders and its directors and the employees of its subsidiaries under its Stock Investment Plan and certain share-based benefit plans. On December 13, 2016, FE contributed 16,097,875 newly issued shares of its common stock to its qualified pension plan in a private placement transaction. These shares were valued at approximately $500 million in the aggregate, and were issued to satisfy a portion of FirstEnergy’s future pension funding obligations. PREFERRED AND PREFERENCE STOCK FirstEnergy and the Utilities were authorized to issue preferred stock and preference stock as of December 31, 2018 , 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 Preferred Stock Issuance FE entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ( $162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). The preferred stock participates in dividends on the common stock on an as-converted basis based on the number of shares of common stock a holder of preferred stock would receive if its shares of preferred stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends are paid at the same time that the dividends on common stock are paid. Each share of preferred stock is convertible at the option of the holders into a number of shares of common stock equal to the $1,000 liquidation preference, divided by the Conversion Price then in effect. As of December 31, 2018, the Conversion Price in effect was $27.42 per share. The Conversion Price is subject to anti-dilution adjustments and adjustments for subdivisions and combinations of the common stock, as well as dividends on the common stock paid in common stock and for certain equity issuances below the Conversion Price then in effect. As of December 31, 2018, 911,411 preferred shares have been converted into 33,238,910 common shares at the option of the holders, resulting in 704,589 shares of preferred shares outstanding. An additional 494,767 preferred shares were converted into 18,044,018 common shares at the option of the holders in January 2019, resulting in 209,822 preferred shares outstanding and yet to be converted as of January 31, 2019. In general, any shares of preferred stock outstanding on July 22, 2019, will be automatically converted. Further, the preferred stock will automatically convert to common stock upon certain events of bankruptcy or liquidation of FE. FE may elect to convert the preferred stock if, at any time, fewer than 323,200 shares of preferred stock are outstanding. However, no shares of preferred stock will be converted prior to January 22, 2020, if such conversion will cause a converting holder to be deemed to beneficially own, together with its affiliates whose holdings would be aggregated with such holder for purposes of Section 13(d) under the Exchange Act, more than 4.9% of the then-outstanding common stock. Furthermore, in no event shall FE issue more than 58,964,222 shares of common stock (the Share Cap) in the aggregate upon conversion of the convertible preferred stock. From and after the time at which the aggregate number of shares of common stock issued upon conversion of the preferred stock equals the Share Cap, each holder electing to convert convertible preferred stock will be entitled to receive a cash payment equal to the market value of the common stock such holder does not receive upon conversion. The holders of preferred stock have limited class voting rights related to the creation of additional securities that are senior or equal with the preferred stock, as well as certain reclassifications and amendments that would affect the rights of the holders of preferred stock. The holders of preferred stock also have the right to approve issuances of securities convertible or exchangeable for common stock, subject to certain exceptions for compensation arrangements and bona fide dividend reinvestment or share purchase plans. Pursuant to the Preferred SPA, FirstEnergy formed an RWG composed of three employees of FirstEnergy and two outside members to advise FirstEnergy management regarding FES' restructuring. On September 20, 2018, pursuant to the Preferred SPA, the RWG was terminated in light of the substantial completion of the RWG’s role. As of December 31, 2017, there were no preferred stock outstanding. As of December 31, 2018 and 2017, there were no preference stock outstanding. LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS The following tables present outstanding long-term debt and capital lease obligations for FirstEnergy as of December 31, 2018 and 2017 : As of December 31, 2018 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2018 2017 FMBs and secured notes - fixed rate 2019 - 2056 1.726% - 9.740% $ 4,355 $ 4,692 Unsecured notes - fixed rate 2019 - 2047 2.850% - 7.700% 13,450 13,155 Unsecured notes - variable rate 2020 3.270% 500 1,450 Capital lease obligations 73 89 Unamortized debt discounts (39 ) (41 ) Unamortized debt issuance costs (95 ) (99 ) Unamortized fair value adjustments 10 (1 ) Currently payable long-term debt (503 ) (558 ) Total long-term debt and other long-term obligations $ 17,751 $ 18,687 On January 22, 2018, FE repaid $1.2 billion of a variable rate syndicated term loan and two separate $125 million term loans using the proceeds from the $2.5 billion equity investment as discussed above. On May 3, 2018, AGC redeemed $100 million of 5.06% senior notes due 2021 and paid $5.7 million in related make-whole premiums in connection with the redemption. On May 10, 2018, MAIT issued $450 million of 4.10% senior notes due 2028. Proceeds from the issuance of the notes were used to establish a capital structure, to finance capital improvements and for general corporate purposes, including funding working capital needs and day-to-day operations. On June 4, 2018, AE Supply repaid approximately $155 million of 5.75% senior notes due 2019 and approximately $150 million of 6.75% senior notes due 2039, and paid $83.3 million in related make-whole premiums in connection with repayments. On June 4, 2018, AE Supply and MP caused to be redeemed $73.5 million of 5.50% PCRBs due 2037. On July 10, 2018, such PCRBs were refinanced as MP issued $73.5 million of 3.0% PCRBs with an October 2021 mandatory put. On June 11, 2018, AE Supply caused to be redeemed $142 million of 5.25% PCRBs due 2037. On June 15, 2018, JCP&L retired $150 million of 4.8% senior notes at maturity. On September 27, 2018, ATSI issued $100 million of 4.32% senior notes due 2030. Proceeds were used to refinance existing indebtedness, including amounts under the FE regulated utility money pool, and remaining proceeds will be used to fund working capital needs, and for other general corporate purposes. On October 3, 2018, Penn issued $50 million of 4.37% first mortgage bonds due 2048. Proceeds were used to refinance existing indebtedness, including amounts under the FE regulated utility money pool, to fund capital expenditures; and for other general corporate purposes. On October 15, 2018, OE repaid $25 million of 8.25% first mortgage bonds at maturity. On October 19, 2018, FE entered into a $1.25 billion 364-day term loan due 2019 (classified as short-term borrowings). Proceeds were used for general corporate purposes. Additionally, on October 19, 2018, FE entered into a $500 million two-year variable rate term loan due 2020. Proceeds were used to reduce revolver borrowings. On November 2, 2018, CEI issued $300 million of 4.55% senior unsecured notes due 2030. Proceeds were used to retire $300 million of 8.875% first mortgage bonds at maturity on November 15, 2018. On January 10, 2019, ME issued $500 million of 4.30% senior note due 2029. Proceeds from the issuance of senior notes were used to refinance existing indebtedness, including ME's 7.70% senior notes due January 15, 2019, and borrowings outstanding under the FE regulated utility money pool, to fund capital expenditures, and for other general corporate purposes. On February 8, 2019, JCP&L issued $400 million of 4.30% senior notes due 2026. Proceeds from the issuance of the senior notes were used to refinance existing indebtedness, including amounts under the FE regulated utility money pool incurred in connection with the repayment at maturity of JCP&L's 7.35% senior notes due 2019. See Note 8, "Leases," for additional information related to capital 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. As of December 31, 2018 and 2017 , $358 million and $383 million of environmental control bonds were outstanding, respectively. Transition Bonds The consolidated financial statements of FirstEnergy and JCP&L include transition bonds issued by JCP&L Transition Funding and JCP&L Transition Funding II, wholly owned limited liability companies of JCP&L. The proceeds were used to securitize the recovery of JCP&L’s bondable stranded costs associated with the previously divested Oyster Creek Nuclear Generating Station and to securitize the recovery of deferred costs associated with JCP&L’s supply of BGS. As of December 31, 2018 and 2017 , $41 million and $56 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. As of December 31, 2018 and 2017 , $292 million and $315 million of the phase-in recovery bonds were outstanding, respectively. See Note 10, "Variable Interest Entities," for additional information on securitized bonds. 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, 2018 , 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 capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2018 . 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) 2019 $ 489 2020 $ 864 2021 $ 132 2022 $ 1,143 2023 $ 1,194 Certain PCRBs allow bondholders to tender their PCRBs for mandatory purchase prior to maturity. The following table classifies these PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs as of December 31, 2018: Year (In millions) 2019 $ — 2020 $ — 2021 $ 74 2022 $ — 2023 $ — 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, 2018 , FirstEnergy remains in compliance with all debt covenant provisions. Additionally, there are cross-default provisions in a number of the financing arrangements. These provisions generally trigger a default in the applicable financing arrangement of an entity if it or any of its significant subsidiaries, excluding AE Supply, default under another financing arrangement in excess of a certain principal amount, typically $100 million . Although such defaults by any of the Utilities, ATSI, TrAIL or MAIT would generally cross-default FE financing arrangements containing these provisions, defaults by AE Supply would generally not cross-default to applicable financing arrangements of FE. Also, defaults by FE would generally not cross-default applicable financing arrangements of any of FE’s subsidiaries. Cross-default provisions are not typically found in any of the senior notes or FMBs of FE or the Utilities.

Short-Term Borrowings and Bank

Short-Term Borrowings and Bank Lines of Credit	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT	SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT FirstEnergy had $1,250 million and $300 million of short-term borrowings as of December 31, 2018 and 2017 , respectively. FE and the Utilities, and FET and certain of its subsidiaries, each participate in two separate five-year syndicated revolving credit facilities, which were amended on October 19, 2018, providing for aggregate commitments of $3.5 billion (Facilities), which are available through December 6, 2022. Under the amended FE facility, an aggregate amount of $2.5 billion is available to be borrowed, repaid and reborrowed, subject to separate borrowing sub-limits for each borrower including FE and its regulated distribution subsidiaries. Under the amended FET Facility, an aggregate amount of $1.0 billion is available to be borrowed, repaid and reborrowed under a syndicated credit facility, subject to separate borrowing sub-limits for each borrower including FET and the Transmission Companies. Prior to the amendments to the Facilities, the aggregate commitments under the Facilities was $5.0 billion, which were available until December 6, 2021. FirstEnergy amended the Facilities to reduce costs and to better align FirstEnergy's ongoing liquidity needs with its strategy to be a fully regulated utility company. Borrowings under the 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 the Facilities are available to each borrower separately and mature on the earlier of 364 days from the date of borrowing or the commitment termination date, as the same may be extended. Each of the Facilities contains financial covenants requiring each borrower to maintain a consolidated debt-to-total-capitalization ratio (as defined under each of the Facilities) of no more than 65%, and 75% for FET, measured at the end of each fiscal quarter. FirstEnergy’s available liquidity from external sources as of February 18, 2019, was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving December 2022 $ 2,500 $ 2,490 FET (2) Revolving December 2022 1,000 1,000 Subtotal $ 3,500 $ 3,490 Cash and cash equivalents — 156 Total $ 3,500 $ 3,646 (1) FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. (2) Includes FET and the Transmission Companies. The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of January 31, 2019 : Borrower FirstEnergy Revolving Credit Facility Sub-Limits FET Revolving Credit Facility Sub-Limits Regulatory and Other Short-Term Debt Limitations (In millions) FE $ 2,500 $ — $ — (1) FET — 1,000 — (1) OE 500 — 500 (2) CEI 500 — 500 (2) TE 300 — 300 (2) JCP&L 500 — 500 (2) ME 500 — 500 (2) PN 300 — 300 (2) WP 200 — 200 (2) MP 500 — 500 (2) PE 150 — 150 (2) ATSI — 500 500 (2) Penn 100 — 100 (2) TrAIL — 400 400 (2) MAIT — 400 400 (2) (1) No limitations. (2) Includes amounts which may be borrowed under the regulated companies' money pool. The FE Facility and the FET Facility have $250 million and $100 million, respectively, subject to each borrower's sub-limit, available for the issuance of LOCs (subject to borrowings drawn under the Facilities) expiring up to one year from the date of issuance. The stated amount of outstanding LOCs will count against total commitments available under each of the Facilities and against the applicable borrower’s borrowing sub-limit. The Facilities do not contain provisions that restrict the ability to borrow or accelerate payment of outstanding advances in the event of any change in credit ratings of the borrowers. Pricing is defined in “pricing grids,” whereby the cost of funds borrowed under the facilities is related to the credit ratings of the company borrowing the funds, other than the FET Facility, which is based on its subsidiaries' credit ratings. Additionally, borrowings under each of the Facilities are subject to the usual and customary provisions for acceleration upon the occurrence of events of default, including a cross-default for other indebtedness in excess of $100 million . As of December 31, 2018, the borrowers were in compliance with the applicable debt-to-total-capitalization covenants in each case as defined under the respective Facilities. The minimum interest charge coverage ratio no longer applies following FE's upgrade to an investment grade credit rating. Term Loans On October 19, 2018, FE entered into two separate syndicated term loan credit agreements, the first being a $1.25 billion 364-day facility with The Bank of Nova Scotia, as administrative agent, and the lenders identified therein, and the second being a $500 million two-year facility with JPMorgan Chase Bank, N.A., as administrative agent, and the lenders identified therein, respectively, the proceeds of each were used to reduce short-term debt. The term loans contain covenants and other terms and conditions substantially similar to those of the FE Facility described above, including a consolidated debt-to-total-capitalization ratio. The initial borrowing of $1.75 billion under the new term loans, which took the form of a Eurodollar rate advance, may be converted from time to time, in whole or in part, to alternate base rate advances or other Eurodollar rate advances. Outstanding alternate base rate advances will bear interest at a fluctuating interest rate per annum equal to the sum of an applicable margin for alternate base rate advances determined by reference to FE’s reference ratings plus the highest of (i) the administrative agent’s publicly-announced “prime rate”, (ii) the sum of 1/2 of 1% per annum plus the Federal Funds Rate in effect from time to time and (iii) the rate of interest per annum appearing on a nationally-recognized service such as the Dow Jones Market Service (Telerate) equal to one-month LIBOR on each day plus 1%. Outstanding Eurodollar rate advances will bear interest at LIBOR for interest periods of one week or one, two, three or six months plus an applicable margin determined by reference to FE’s reference ratings. Changes in FE’s reference ratings would lower or raise its applicable margin depending on whether ratings improved or were lowered, respectively. 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 2018 was 2.26% per annum for the regulated companies’ money pool and 2.96% per annum for the unregulated companies’ money pools. Weighted Average Interest Rates The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2018 and 2017 , were 3.07% and 3.24% , respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
ASSET RETIREMENT OBLIGATIONS	ASSET RETIREMENT OBLIGATIONS FirstEnergy has recognized applicable legal obligations for AROs and their associated cost, primarily for the decommissioning of the TMI-2 nuclear generating facility and environmental remediation, 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. JCP&L, ME and PN maintain NDTs that are legally restricted for purposes of settling the TMI-2 nuclear decommissioning ARO. The fair values of the decommissioning trust assets as of December 31, 2018 and 2017 , were $790 million and $822 million , respectively. The following table summarizes the changes to the ARO balances during 2018 and 2017 : ARO Reconciliation (In millions) Balance, January 1, 2017 $ 581 Transfer of BV-2 liability to NG (49 ) Liabilities settled (1 ) Accretion 39 Balance, December 31, 2017 $ 570 Changes in timing and amount of estimated cash flows 203 Liabilities settled (1 ) Accretion 40 Balance, December 31, 2018 $ 812 During the second quarter of 2017, in connection with NG purchasing the lessor equity interests of the remaining non-affiliated leasehold interests from an owner participant in the Beaver Valley Unit 2 sale leaseback and the expiration of the leases, OE and TE transferred the ARO (approximately $49 million ) and NDT assets associated with their leasehold interests to NG. 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. AE Supply assessed the changes in timing and closure plan requirements associated with the McElroy's Run impoundment site and increased the ARO by approximately $43 million in the third quarter of 2018. During the fourth quarter of 2018, based on studies completed by a third-party to reassess the estimated costs and timing to decommission TMI-2, JCP&L, ME and PN increased their ARO by a total of approximately $172 million , which was offset against a regulatory asset. The increase in the ARO resulted primarily from accelerated timing of the estimated cash flows associated with decommissioning.

Regulatory Matters

Regulatory Matters	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
REGULATORY MATTERS	REGULATORY MATTERS STATE REGULATION Each of the Utilities' retail rates, conditions of service, issuance of securities and other matters are subject to regulation in the states in which it operates - in Maryland by the MDPSC, in Ohio by the PUCO, in New Jersey by the NJBPU, in Pennsylvania by the PPUC, in West Virginia by the WVPSC and in New York by the NYPSC. The transmission operations of PE in Virginia are subject to certain regulations of the VSCC. In addition, under Ohio law, municipalities may regulate rates of a public utility, subject to appeal to the PUCO if not acceptable to the utility. 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 distribution rate orders in effect for the Utilities. 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 January 2017 55% / 45% 9.6% OE January 2009 51% / 49% 10.5% PE-West Virginia February 2015 54% / 46% Settled (2) PE-Maryland November 1994 48% / 52% 11.9% 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. MARYLAND PE operates under MDPSC approved base rates that were effective as of November 11, 1994. PE also provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The EmPOWER Maryland program requires each electric utility to file a plan to reduce electric consumption and demand 0.2% per year, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE's 2016 starting goal under this requirement was 0.97%. PE's approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. In 2013, the MDPSC required Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's submitted analysis projected that it would require up to approximately $2.7 billion in infrastructure investments over 15 years to attempt to achieve the quickest level of response for the largest storm projected in MDPSC's scenarios. The MDPSC conducted a hearing September 2014, but has not taken further action on this matter. 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. On January 12, 2018, the MDPSC instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of Maryland utilities. PE must track and apply regulatory accounting treatment for the impacts beginning January 1, 2018, and submitted a report to the MDPSC on February 15, 2018, estimating that the Tax Act impacts would be approximately $7 million to $8 million annually for PE’s customers. On August 17, 2018, the Staff of the MDPSC filed a reply that recommended the MDPSC instead direct PE to reduce base rates by $6.5 million to reflect reduced federal tax costs pending resolution of PE's upcoming rate case and further direct that PE pay customers a one-time credit for what the Staff estimated were the tax savings to PE through the end of July 2018. On October 5, 2018, the MDPSC issued an order requiring PE to pay a one-time credit for tax savings through September 30, 2018, which totaled approximately $5 million, and reserved all other Tax Act impacts to be resolved in the pending rate case. 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 reflects $7.3 million in annual savings for customers resulting from the recent federal tax law changes. On November 20, 2018, the Staff of the MDPSC filed testimony recommending an increase in base rates of $12.9 million and conditional approval of the EDIS, while the Maryland Office of People's Counsel filed testimony recommending a reduction in rates of $11.1 million and rejection of the EDIS. The evidentiary hearing concluded on January 28, 2019, and a final order is expected by March 23, 2019. NEW JERSEY JCP&L operates under NJBPU approved rates that were effective as of January 1, 2017. In addition, on January 25, 2017, the NJBPU approved the acceleration of the amortization of JCP&L’s 2012 major storm expenses that are recovered through the SRC in order for JCP&L to achieve full recovery by December 31, 2019. 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. 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 rate payers; 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. Also in December 2017, the NJBPU approved its IIP rulemaking. The IIP creates a financial incentive for utilities to accelerate the level of investment needed to promote the timely rehabilitation and replacement of certain non-revenue producing components that enhance reliability, resiliency, and/or safety. On July 13, 2018, JCP&L filed an infrastructure plan, JCP&L Reliability Plus, which proposed to accelerate $386.8 million of electric distribution infrastructure investment over four years to enhance the reliability and resiliency of its distribution system and reduce the frequency and duration of power outages. On August 29, 2018, the NJBPU retained the petition for hearing and, on November 22, 2018, issued a procedural schedule. On December 17, 2018, the Division of Rate Counsel recommended a $97 million program, a return on equity of 8.75%, and 5.38% cost of debt. On January 23, 2019, the NJBPU granted JCP&L's request to temporarily suspend procedural schedule in the matter pending settlement discussions. There can be no assurance that a definitive settlement agreement will be reached and, if so, will be approved by the NJBPU. On January 31, 2018, the NJBPU instituted a proceeding to examine the impacts of the Tax Act on the rates and charges of New Jersey utilities. The NJBPU ordered New Jersey utilities to: (1) defer on their books the impacts of the Tax Act effective January 1, 2018; (2) to file tariffs effective April 1, 2018, reflecting the rate impacts of changes in current taxes; and (3) to file tariffs effective July 1, 2018, reflecting the rate impacts of changes in deferred taxes. On March 2, 2018, JCP&L filed a petition with the NJBPU, which included proposed tariffs for a base rate reduction of $28.6 million effective April 1, 2018, and a rider to reflect $1.3 million in rate impacts of changes in deferred taxes. On March 26, 2018, the NJBPU approved JCP&L’s rate reduction effective April 1, 2018, on an interim basis subject to refund, pending the outcome of this proceeding. The NJBPU, however, did not address refunds and other proposed rider tariffs at such time. OHIO The Ohio Companies currently operate under ESP IV through May 31, 2024. ESP IV includes Rider DMR, which provides for the Ohio Companies to collect $132.5 million annually for three years, with the possibility of a two -year extension and is grossed up for federal income taxes, resulting in an approved amount of approximately $168 million annually in 2018 and 2019. Revenues from Rider DMR will be excluded from the significantly excessive earnings test for the initial three -year term but the exclusion will be reconsidered upon application for a potential two -year extension. The PUCO set three conditions for continued recovery under Rider DMR: (1) retention of the corporate headquarters and nexus of operations in Akron, Ohio; (2) no change in control of the Ohio Companies; and (3) a demonstration of sufficient progress in the implementation of grid modernization programs approved by the PUCO. ESP IV also continues a base distribution rate freeze through May 31, 2024. In addition, ESP IV continues the supply of power to non-shopping customers at a market-based price set through an auction process. On February 1, 2019, the Ohio Companies filed with the PUCO an application requesting a two-year extension of Rider DMR at the same amount and conditions. ESP IV also continues Rider DCR, which supports continued investment related to the distribution system for the benefit of customers, with increased revenue caps of $30 million per year through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. ESP IV also includes: (1) the collection of lost distribution revenues associated with energy efficiency and peak demand reduction programs; (2) an agreement to file a Grid Modernization Business Plan for PUCO consideration and approval, which was filed in February 2016, and remains pending as part of the grid modernization settlement described below; (3) a goal across FirstEnergy to reduce CO 2 emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Council to ensure preservation and growth of the competitive market in Ohio; and (5) an agreement to file an application to transition to a straight fixed variable cost recovery mechanism for residential customers' base distribution rates, which filing the PUCO denied on June 13, 2018. Several parties, including the Ohio Companies, filed applications for rehearing regarding the Ohio Companies’ ESP IV with the PUCO. On August 16, 2017, the PUCO denied all remaining intervenor applications for rehearing, denied the Ohio Companies’ challenges to the modifications to Rider DMR and added a third-party monitor to ensure that Rider DMR funds are spent appropriately. The Ohio Companies then filed an application for rehearing of the PUCO’s August 16, 2017 ruling on the issues of the third-party monitor and the ROE calculation for advanced metering infrastructure, which the PUCO denied. In October 2017, the Sierra Club and the OMAEG filed notices of appeal with the Supreme Court of Ohio appealing various PUCO entries on their applications for rehearing. The Ohio Companies intervened in the appeal, and additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. On September 26, 2018, the Supreme Court of Ohio denied a July 30, 2018 joint motion filed by the OCC, the NOAC, and the OMAEG to stay the portions of the PUCO's orders and entries under appeal that authorized Rider DMR. Oral argument on the appeals was held on January 9, 2019. Under Ohio law, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. The Ohio Companies’ 2017-2019 plan, as proposed in April 2016, includes a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. In December 2016, the Ohio Companies filed a Stipulation and Recommendation with several parties that contained changes to the plan and a decrease in the plan costs. The Ohio Companies anticipate the cost of the plans will be approximately $268 million over the life of the portfolio plans and such costs are expected to be recovered through the Ohio Companies’ existing rate mechanisms. On November 21, 2017, the PUCO issued an order that approved the proposed plans with several modifications, including a cap on the Ohio Companies’ collection of program costs and shared savings set at 4% of the Ohio Companies’ total sales to customers. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modifications, which the PUCO denied on January 10, 2018. On March 12, 2018, the Ohio Companies appealed to the Supreme Court of Ohio challenging the PUCO’s imposition of a 4% cost cap. Various other parties also appealed challenging various PUCO entries on their applications for rehearing. Oral argument on the appeals is scheduled for February 20, 2019. Ohio law requires electric utilities and electric service companies in Ohio to serve part of their load from renewable energy resources measured by an annually increasing percentage, which in 2017 was 3.5%, and increases 1% each year through 2026 (to 12.5%) and shall remain at 12.5% in 2027 and each year thereafter. The Ohio Companies conducted RFPs in 2009, 2010 and 2011 to secure RECs to help meet these renewable energy requirements. In September 2011, the PUCO opened a docket to review the Ohio Companies' alternative energy recovery rider through which the Ohio Companies recover the costs of acquiring these RECs. In August 2013, the PUCO approved the Ohio Companies' REC acquisitions except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. Following appeals, on January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against retroactive ratemaking. After the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition, on April 25, 2018, the Supreme Court of Ohio denied the motion for reconsideration. As a result, in the second quarter of 2018, the Ohio Companies recognized a pre-tax benefit to earnings (within the Amortization (deferral) of regulatory assets, net line on the Consolidated Statement of Income (Loss)) of approximately $72 million to reverse the liability associated with the PUCO opinion and order. On December 1, 2017, the Ohio Companies filed an application with the PUCO for approval of a DPM Plan. The DPM Plan is a portfolio of approximately $450 million in distribution platform investment projects, which are designed to modernize the Ohio Companies’ distribution grid, prepare it for further grid modernization projects, and provide customers with immediate reliability benefits. On November 9, 2018, the Ohio Companies filed a settlement agreement that provides for the implementation of the first phase of grid modernization plans, including the investment of $516 million over three years to modernize the Ohio Companies’ electric distribution system, and for all tax savings associated with the Tax Act, discussed below, to flow back to customers. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The settlement has broad support, including PUCO Staff, the OCC, representatives of industrial and commercial customers, a low-income advocate, environmental advocates, hospitals, competitive generation suppliers and other parties. The PUCO conducted a hearing and the settlement agreement remains subject to PUCO approval. On January 10, 2018, the PUCO opened a case to consider the impacts of the Tax Act and determine the appropriate course of action to pass benefits on to customers. The Ohio Companies, effective January 1, 2018, were required to establish a regulatory liability for the estimated reduction in federal income tax resulting from the Tax Act, and filed comments on February 15, 2018, explaining that customers will save nearly $40 million annually as a result of updating tariff riders for the tax rate changes and that the Ohio Companies’ base distribution rates are not impacted by the Tax Act changes because they are frozen through May 2024. On October 24, 2018, the PUCO entered an Order in its investigation into the impacts of the Tax Act on Ohio's utilities directing that by January 1, 2019, all Ohio rate-regulated utility companies, unless ordered otherwise, file applications not for an increase in rates to reflect the impact of the Tax Act on each specific utility's current rates. On October 30, 2018, the Ohio Companies filed an application to open a new proceeding for the implementation of matters relating to the impact of the Tax Act. As discussed further above, on November 9, 2018, the Ohio Companies filed a settlement agreement that provides for all tax savings associated with the Tax Act to flow back to customers and for the implementation of the first phase of grid modernization plans. As part of the agreement, the Ohio Companies also filed an application for approval of a rider to return the remaining tax savings to customers following PUCO approval of the settlement. On December 19, 2018, the PUCO upheld its January 10, 2018 ruling that utilities should be required to establish a deferred tax liability, effective January 1, 2018, in response to the Tax Act. On January 25, 2019, the Ohio Companies filed a supplemental settlement agreement that keeps intact the provisions of the settlement described above and adds further customer benefits and protections, which broadened support for the settlement. The PUCO conducted a hearing and the settlement agreement remains subject to PUCO approval. PENNSYLVANIA The Pennsylvania Companies operate under rates approved by the PPUC, effective as of January 27, 2017. The Pennsylvania Companies operate under DSPs for the June 1, 2017 through May 31, 2019 delivery period, which provide for the competitive procurement of generation supply for customers who do not choose an alternative EGS or for customers of alternative EGSs that fail to provide the contracted service. Under the DSPs, the supply will be provided by wholesale suppliers through a mix of 12 and 24 -month energy contracts, as well as one RFP for 2 -year SREC contracts for ME, PN and Penn. The DSPs include modifications to the Pennsylvania Companies’ POR programs in order to reduce the level of uncollectible expense the Pennsylvania Companies experience associated with alternative EGS charges. The Pennsylvania Companies' DSPs for the June 1, 2019 through May 31, 2023 delivery period were approved by the PPUC in September 2018. Under the 2019-2023 DSPs, the supply will be provided by wholesale suppliers through a mix of 3, 12 and 24-month energy contracts, as well as two RFPs for 2-year SREC contracts for ME, PN and Penn. The 2019-2023 DSPs also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program term, and modifications to the Pennsylvania Companies’ customer class definitions to allow for the introduction of hourly priced default service to customers at or above 100kW . The PPUC directed a working group to further discuss the implementation of customer assistance program shopping limitations and appropriate scripting for the Pennsylvania Companies' customer referral programs, and in November 2018, issued a subsequent order to approve additional customer assistance program shopping parameters and further limit the scope of the working group discussion. On December 21, 2018, the PPUC issued a tentative order proposing a model to incorporate the directed shopping restrictions. Comments on the proposal were filed January 22, 2019. Pursuant to Pennsylvania's EE&C legislation in Act 129 of 2008 and PPUC orders, Pennsylvania EDCs implement energy efficiency and peak demand reduction programs. The Pennsylvania Companies' Phase III EE&C plans for the June 2016 through May 2021 period, which were approved in March 2016, with expected costs up to $390 million, are designed to achieve the targets established in the PPUC's Phase III Final Implementation Order with full recovery through the reconcilable EE&C riders. Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. LTIIPs outlining infrastructure improvement plans for PPUC review and approval must be filed prior to approval of a DSIC. On June 14, 2017, the PPUC approved modified LTIIPs for ME, PN and Penn for the remaining years of 2017 through 2020 to provide additional support for reliability and infrastructure investments. On September 20, 2018, following a periodic review of the LTIIPs as required by regulation once every five years, the PPUC entered an Order concluding that the Pennsylvania Companies have substantially adhered to the schedules and expenditures outlined in their LTIIPs, but that changes to the LTIIPs as designed are necessary to maintain and improve reliability and directed the Pennsylvania Companies to file modified or new LTIIPs. On January 18, 2019, the Pennsylvania Companies filed modifications to their current LTIIPs that would terminate those LTIIPs at the end of 2019, and proposed revised LTIIP spending in 2019 of $44.52 million by ME, $24.72 million by PN, $26.06 million by Penn and $50.85 million by WP. The Pennsylvania Companies also committed to making filings later in 2019, which would propose new LTIIPs for the 2020 through 2024 period. The Pennsylvania Companies’ approved DSIC riders for quarterly cost recovery went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. In the January 19, 2017 order approving the Pennsylvania Companies’ general rate cases, the PPUC added an additional issue to the DSIC proceeding to include whether ADIT should be included in DSIC calculations. On February 2, 2017, the parties to the DSIC proceeding submitted a Joint Settlement to the ALJ that resolved the issues that were pending from the order issued on June 9, 2016. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ's previous decision that would have required the Pennsylvania Companies to reflect all federal and state income tax deductions related to DSIC-eligible property in currently effective DSIC rates. On May 21, 2018, the Pennsylvania OCA filed an appeal with the Pennsylvania Commonwealth Court of the PPUC's decision of April 19, 2018. On June 11, 2018, the Pennsylvania Companies filed a Notice of Intervention in the Pennsylvania OCA's appeal to the Commonwealth Court. Briefing is complete and oral argument is scheduled for June 3, 2019. On February 12, 2018, the PPUC initiated a proceeding to determine the effects of the Tax Act on the tax liability of utilities and the feasibility of reflecting such impacts in rates charged to customers. On March 9, 2018, the Pennsylvania Companies submitted their calculation of the net annual effect of the Tax Act on income tax expense and rate base to be $37 million for ME, $40 million for PN, $9 million for Penn, and $30 million for WP. The Pennsylvania Companies also filed comments proposing that rates be adjusted to reflect the tax rate changes prospectively from the date of a final PPUC order via a reconcilable rider, with the amount that would otherwise accrue between January 1, 2018 and the date of a final order being used to invest in the Pennsylvania Companies’ infrastructure. On March 15, 2018, the PPUC issued a Temporary Rates Order making the Pennsylvania Companies’ rates temporary and subject to refund for six months. On May 17, 2018, the PPUC issued orders directing that the Pennsylvania Companies implement a reconcilable negative surcharge mechanism in order to refund to customers the net effect of the Tax Act for the period July 1, 2018 through December 31, 2018, to be prospectively updated for new rates effective January 1, 2019. The Pennsylvania Companies were also directed to establish a regulatory liability for the net impact of the Tax Act for the period of January 1, 2018 through June 30, 2018. On June 14, 2018, the PPUC issued an order revising this directive such that the Pennsylvania Companies must instead establish accounts to track tax savings for the period January 1, 2018 through March 14, 2018, and record regulatory liabilities associated with tax savings for only the period March 15, 2018 through June 30, 2018. The cumulative value of the tracked amounts and the regulatory liability is expected to amount to $12 million for ME, $13 million for PN, $3 million for Penn, and $10 million for WP. These amounts are expected to be addressed in the Pennsylvania Companies' next available rate proceedings, or independent filings to be made within three years, whichever comes sooner. The Pennsylvania Companies filed voluntary surcharges on June 1, 2018, to adjust rates for the reduced tax rate, which were effective for bills rendered starting July 1, 2018. For the first six-month period, the surcharge returned to customers was approximately $22 million for ME, $23 million for PN, $6 million for Penn, and $18 million for WP. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking and operates under rates approved by the WVPSC effective February 2015. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. In September 2016, the WVPSC approved the Phase II energy efficiency program for MP and PE as reflected in a unanimous settlement, which included three energy efficiency programs to meet the Phase II requirement of energy efficiency reductions of 0.5% of 2013 distribution sales for the January 1, 2017 through May 31, 2018 period. On December 15, 2017, the WVPSC approved MP's and PE's proposed annual decrease in their EE&C rates, effective January 1, 2018, which is not material to FirstEnergy. This Phase II energy efficiency program ended May 31, 2018. Previously, AE Supply was the winning bidder of a December 2016 RFP to address MP’s generation shortfall and on March 6, 2017, MP and AE Supply signed an asset purchase agreement for MP to acquire AE Supply’s Pleasants Power Station (1,300 MWs), subject to customary and other closing conditions, including regulatory approvals . In January 2018, FERC issued an order denying authorization for the transaction and the WVPSC issued an order approving the transfer of Pleasants Power Station conditioned on MP assuming significant commodity risk. Based on the adverse FERC ruling and the conditions included in the WVPSC order, MP and AE Supply terminated the asset purchase agreement. On August 31, 2018, MP and PE filed a $100.9 million decrease in their ENEC rates proposed to be effective January 1, 2019, which included a $25.6 million annual decrease impact associated with the settlement regarding the impact of the Tax Act on West Virginia rates, as noted below. Additionally, the August 31, 2018 filing included an elimination of the Energy Efficiency Cost Rate Surcharge effective January 1, 2019, equating to an additional $2.1 million decrease. The rate decreases represent an approximate 7.2% annual decrease in rates versus those in effect on August 31, 2018. A unanimous settlement was filed with the WVPSC on November 20, 2018, and a hearing was held on November 27, 2018. An order adopting the settlement in full without modification was issued on January 2, 2019. On January 3, 2018, the WVPSC initiated a proceeding to investigate the effects of the Tax Act on the revenue requirements of utilities. MP and PE must track the tax savings resulting from the Tax Act on a monthly basis, effective January 1, 2018. On January 26, 2018, the WVPSC issued an order clarifying that regulatory accounting should be implemented as of January 1, 2018, including the recording of any regulatory liabilities resulting from the Tax Act. MP and PE filed written testimony on May 30, 2018, explaining the impact of the Tax Act on federal income tax and revenue requirements and showing an annual rate impact of $26.2 million. MP and PE, the Staff of the WVPSC, the WV Consumer Advocate and a coalition of industrial customers entered into a settlement agreement on August 23, 2018, to have $25.6 million in rate reductions flow through to customers beginning September 1, 2018, and to defer to the next base rate case (or a separate proceeding if a base rate case is not filed by August 31, 2020) the amount and classification of the excess ADITs resulting from the Tax Act and the issue of whether MP and PE should be required to credit to customers any of the reduced income tax expense occurring between January 1, 2018 and August 31, 2018. The WVPSC approved the settlement on August 24, 2018. RELIABILITY MATTERS Federally-enforceable mandatory reliability standards apply to the bulk electric system and impose certain operating, record-keeping and reporting requirements on the Utilities, AGC, AE Supply, and the Transmission Companies. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards to eight regional entities, including RFC. All of FirstEnergy's facilities are located within the RFC region. FirstEnergy actively participates in the NERC and RFC stakeholder processes, and otherwise monitors and manages its companies in response to the ongoing development, implementation and enforcement of the reliability standards implemented and enforced by RFC. FirstEnergy believes that it is in compliance with all currently-effective and enforceable reliability standards. Nevertheless, in the course of operating its extensi

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 2018
Commitments and Contingencies Disclosure [Abstract]
COMMITMENTS, GUARANTEES AND CONTINGENCIES	COMMITMENTS, GUARANTEES AND CONTINGENCIES NUCLEAR INSURANCE JCP&L, ME and PN maintain property damage insurance provided by NEIL for their interest in the retired TMI- 2 nuclear facility, a permanently shut down and defueled facility. Under these arrangements, up to $150 million of coverage for decontamination costs, decommissioning costs, debris removal and repair and/or replacement of property is provided. JCP&L, ME and PN pay annual premiums and are subject to retrospective premium assessments of up to approximately $1.2 million during a policy year. JCP&L, ME and PN intend to maintain insurance against nuclear risks as long as it is available. To the extent that property damage, decontamination, decommissioning, repair and replacement costs and other such costs arising from a nuclear incident at any of JCP&L, ME or PN’s plants exceed the policy limits of the insurance in effect with respect to that plant, to the extent a nuclear incident is determined not to be covered by JCP&L, ME or PN’s insurance policies, or to the extent such insurance becomes unavailable in the future, JCP&L, ME or PN would remain at risk for such costs. The Price-Anderson Act limits public liability relative to a single incident at a nuclear power plant. In connection with TMI-2, JCP&L, ME and PN carry the required ANI third party liability coverage and also have coverage under a Price Anderson indemnity agreement issued by the NRC. The total available coverage in the event of a nuclear incident is $560 million , which is also the limit of public liability for any nuclear incident involving TMI-2. 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, 2018 , outstanding guarantees and other assurances aggregated approximately $1.7 billion , consisting of guarantees on behalf of FES and FENOC ( $345 million ), parental guarantees on behalf of its consolidated subsidiaries' guarantees ( $1.0 billion ), other guarantees ($ 190 million ) and other assurances ( $140 million ). FirstEnergy has also committed to provide certain additional guarantees to the FES Debtors for retained environmental liabilities of AE Supply related to the Pleasants Power Station and McElroy's Run CCR disposal facility as part of the settlement agreement in connection with the FES Bankruptcy. COLLATERAL AND CONTINGENT-RELATED FEATURES In the normal course of business, FE and its subsidiaries routinely enter into physical or financially settled contracts for the sale and purchase of electric capacity, energy, fuel and emission allowances. Certain bilateral agreements and derivative instruments contain provisions that require FE or its subsidiaries to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon FE's or its subsidiaries' credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. The incremental collateral requirement allows for the offsetting of assets and liabilities with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. Bilateral agreements and derivative instruments entered into by FE and its subsidiaries have margining provisions that require posting of collateral. Based on AE Supply's power portfolio exposure as of December 31, 2018 , AE Supply has posted no collateral . The Utilities and Transmission Companies have posted collateral totaling $2 million . These credit-risk-related contingent features, or the margining provisions within bilateral agreements, stipulate that if the subsidiary were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. Depending on the volume of forward contracts and future price movements, higher amounts for margining, which is the ability to secure additional collateral when needed, could be required. The following table discloses the potential additional credit rating contingent contractual collateral obligations as of December 31, 2018 : Potential Collateral Obligations AE Supply Utilities and FET FE Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 1 $ — $ — $ 1 Upon Further Downgrade — 62 — 62 Surety Bonds (Collateralized Amount) (1) 1 59 246 306 Total Exposure from Contractual Obligations $ 2 $ 121 $ 246 $ 369 Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively. OTHER COMMITMENTS AND CONTINGENCIES FE is a guarantor under a $300 million syndicated senior secured term loan facility due March 3, 2020, under which Global Holding's outstanding principal balance is $190 million as of December 31, 2018. In addition to FE, Signal Peak, Global Rail, Global Mining Group, LLC and Global Coal Sales Group, LLC, each being a direct or indirect subsidiary of Global Holding, continue to provide their joint and several guaranties of the obligations of Global Holding under the facility. In connection with the facility, 69.99% of Global Holding's direct and indirect membership interests in Signal Peak, Global Rail and their affiliates along with FEV's and WMB Marketing Ventures, LLC's respective 33-1/3% membership interests in Global Holding, are pledged to the lenders under the current facility as collateral. ENVIRONMENTAL MATTERS Various federal, state and local authorities regulate FirstEnergy with regard to air and water quality and other environmental matters. Pursuant to a March 28, 2017 executive order, the EPA and other federal agencies are to review existing regulations that potentially burden the development or use of domestically produced energy resources and appropriately suspend, revise or rescind those that unduly burden the development of domestic energy resources beyond the degree necessary to protect the public interest or otherwise comply with the law. FirstEnergy cannot predict the timing or ultimate outcome of any of these reviews or how any future actions taken as a result thereof, in particular with respect to existing environmental regulations, may materially impact its business, results of operations, cash flows and financial condition. Compliance with environmental regulations could have a material adverse effect on FirstEnergy's earnings, cash flow and competitive position to the extent that FirstEnergy competes with companies that are not subject to such regulations and, therefore, do not bear the risk of costs associated with compliance, or failure to comply, with such regulations. Clean Air Act FirstEnergy complies with 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 Ohio, Pennsylvania and West Virginia. This follows the 2014 U.S. Supreme Court ruling generally upholding the EPA’s regulatory approach under CSAPR, but questioning whether the EPA required upwind states to reduce emissions by more than their contribution to air pollution in downwind states. The EPA issued a CSAPR update rule on September 7, 2016, reducing summertime NOx emissions from power plants in 22 states in the eastern U.S., including Ohio, Pennsylvania and West Virginia, beginning in 2017. Various states and other stakeholders appealed the CSAPR update rule to the D.C. Circuit in November and December 2016. On September 6, 2017, the D.C. Circuit rejected the industry's bid for a lengthy pause in the litigation and set a briefing schedule. Depending on the outcome of the appeals, the EPA’s reconsideration of the CSAPR update rule and how the EPA and the states ultimately implement CSAPR, the future cost of compliance may be material and changes to FirstEnergy's operations may result. The EPA tightened the primary and secondary NAAQS for ozone from the 2008 standard levels of 75 PPB to 70 PPB on October 1, 2015. The EPA stated the vast majority of U.S. counties will meet the new 70 PPB standard by 2025 due to other federal and state rules and programs but on April 30, 2018, the EPA designated fifty-one areas in twenty-two states as non-attainment; however, FirstEnergy has no power plants operating in those areas. States have roughly three years to develop implementation plans to attain the new 2015 ozone NAAQS. Depending on how the EPA and the states implement the new 2015 ozone NAAQS, the future cost of compliance may be material and changes to FirstEnergy’s operations may result. In August 2016, the State of Delaware filed a CAA Section 126 petition with the EPA alleging that the Harrison generating facility's NOx emissions significantly contribute to Delaware's inability to attain the ozone NAAQS. The petition sought a short-term NOx emission rate limit of 0.125 lb/mmBTU over an averaging period of no more than 24 hours. In November 2016, the State of Maryland filed a CAA Section 126 petition with the EPA alleging that NOx emissions from 36 EGUs, including Harrison Units 1, 2 and 3 and Pleasants Units 1 and 2, significantly contribute to Maryland's inability to attain the ozone NAAQS. The petition sought NOx emission rate limits for the 36 EGUs by May 1, 2017. On September 14, 2018, the EPA denied both the States of Delaware and Maryland petitions under CAA Section 126. In October 2018, Delaware and Maryland appealed the denials of their petitions to the D.C. Circuit. In March 2018, the State of New York filed a CAA Section 126 petition with the EPA alleging that NOx emissions from nine states (including Ohio, Pennsylvania and West Virginia) significantly contribute to New York’s inability to attain the ozone NAAQS. The petition seeks suitable emission rate limits for large stationary sources that are affecting New York’s air quality within the three years allowed by CAA Section 126. On May 3, 2018, the EPA extended the time frame for acting on the CAA Section 126 petition by six months to November 9, 2018, but has not taken any further action. FirstEnergy is unable to predict the outcome of these matters or estimate the loss or range of loss. On May 1, 2017, FE and FG, and CSX and BNSF entered into a definitive settlement agreement, which resolved all claims related to a coal transportation contract dispute as a result of MATS. Pursuant to the settlement agreement, FG agreed to pay CSX and BNSF an aggregate amount equal to $109 million, payable in three annual installments, the first of which was made on May 1, 2017. FE agreed to unconditionally and continually guarantee the settlement payments due by FG pursuant to the terms of the settlement agreement. The settlement agreement further provided that in the event of the initiation of bankruptcy proceedings or failure to make timely settlement payments, the unpaid settlement amount will immediately accelerate and become due and payable in full. On April 6, 2018, FE paid the remaining $72 million under the settlement agreement as a result of the FES Bankruptcy. As to a specific coal supply agreement, AE Supply, the party thereto, asserted termination rights effective in 2015 as a result of MATS. In response to notification of the termination, on January 15, 2015, Tunnel Ridge, LLC, the coal supplier, commenced litigation in the Court of Common Pleas of Allegheny County, Pennsylvania , alleging AE Supply did not have sufficient justification to terminate the agreement and seeking damages for the difference between the market and contract price of the coal, or lost profits plus incidental damages. On February 18, 2018, the parties reached an agreement in principle settling all claims in dispute. The agreement in principle includes, among other matters, a $93 million payment by AE Supply, as well as certain coal supply commitments for Pleasants Power Station during its remaining operation by AE Supply. Certain aspects of the final settlement agreement are guaranteed by FE, including the $93 million payment, which was paid in the first quarter of 2018. The parties executed the final settlement agreement on March 9, 2018, and the plaintiff dismissed the matter with prejudice on March 15, 2018. Climate Change FirstEnergy has established a goal to reduce CO 2 emissions by 90% below 2005 levels by 2045. There are a number of initiatives to reduce GHG emissions at the state, federal and international level. Certain northeastern states are participating in the RGGI and western states led by California, have implemented programs, primarily cap and trade mechanisms, to control emissions of certain GHGs. Additional policies reducing GHG emissions, such as demand reduction programs, renewable portfolio standards and renewable subsidies have been implemented across the nation. The EPA released its final “Endangerment and Cause or Contribute Findings for Greenhouse Gases under the Clean Air Act,” in December 2009, concluding that concentrations of several key GHGs constitutes an "endangerment" and may be regulated as "air pollutants" under the CAA and mandated measurement and reporting of GHG emissions from certain sources, including electric generating plants. The EPA released its final CPP regulations in August 2015 to reduce CO 2 emissions from existing fossil fuel-fired EGUs and also 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 January 21, 2016, a panel of the D.C. Circuit denied the motions for stay and set an expedited schedule for briefing and argument. On February 9, 2016, the U.S. Supreme Court stayed the rule during the pendency of the challenges to the D.C. Circuit and U.S. Supreme Court . On March 28, 2017, an executive order, entitled “Promoting Energy Independence and Economic Growth,” instructed the EPA to review the CPP and related rules addressing GHG emissions and suspend, revise or rescind the rules if appropriate. On October 16, 2017, the EPA issued a proposed rule to repeal the CPP. To replace the CPP, the EPA proposed the ACE rule on August 21, 2018, which would establish emission guidelines for states to develop plans to address GHG emissions from existing coal-fired power plants. Depending on the outcomes of the review pursuant to the executive order, of further appeals and how any final rules are ultimately implemented, the future cost of compliance may be material. 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, and in September 2016, 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 was ratified by the requisite number of countries (i.e., at least 55 countries representing at least 55% of global GHG emissions) in October 2016 and its non-binding obligations to limit global warming to well below two degrees Celsius became effective on November 4, 2016. On June 1, 2017, the Trump Administration announced that the U.S. would cease all participation in the Paris Agreement. FirstEnergy cannot currently estimate the financial impact of climate change policies, although potential legislative or regulatory programs restricting CO 2 emissions, or litigation alleging damages from GHG emissions, could require material capital and other expenditures or result in changes to its operations. Clean Water Act Various water quality regulations, the majority of which are the result of the federal CWA and its amendments, apply to FirstEnergy's plants. In addition, the states in which FirstEnergy operates have water quality standards applicable to FirstEnergy's operations. The EPA finalized CWA Section 316(b) regulations in May 2014, requiring cooling water intake structures with an intake velocity greater than 0.5 feet per second to reduce fish impingement when aquatic organisms are pinned against screens or other parts of a cooling water intake system to a 12% annual average and requiring cooling water intake structures exceeding 125 million gallons per day to conduct studies to determine site-specific controls, if any, to reduce entrainment, which occurs when aquatic life is drawn into a facility's cooling water system. Depending on any final action taken by the states with respect to impingement and entrainment, the future capital costs of compliance with these standards may be material. On September 30, 2015, the EPA finalized new, more stringent effluent limits for the Steam Electric Power Generating category (40 CFR Part 423) for arsenic, mercury, selenium and nitrogen for wastewater from wet scrubber systems and zero discharge of pollutants in ash transport water. The treatment obligations phase-in as permits are renewed on a five -year cycle from 2018 to 2023. On April 13, 2017, the EPA granted a Petition for Reconsideration and administratively stayed all deadlines in the effluent limits rule pending a new rulemaking. On September 18, 2017, the EPA replaced the administrative stay with a rulemaking which postponed only certain compliance deadlines for two years. Depending on the outcome of appeals and how any final rules are ultimately implemented, the future costs of compliance with these standards may be substantial and changes to FirstEnergy's operations may result. In October 2009, the WVDEP issued an NPDES water discharge permit for the Fort Martin plant, which imposes TDS, sulfate concentrations and other effluent limitations for heavy metals, as well as temperature limitations. Concurrent with the issuance of the Fort Martin NPDES permit, WVDEP also issued an administrative order setting deadlines for MP to meet certain of the effluent limits that were effective immediately under the terms of the NPDES permit. MP appealed, and a stay of certain conditions of the NPDES permit and order have been granted pending a final decision on the appeal and subject to WVDEP moving to dissolve the stay. The Fort Martin NPDES permit could require an initial capital investment ranging from $150 million to $300 million in order to install technology to meet the TDS and sulfate limits, which technology may also meet certain of the other effluent limits. March 2018, the WVDEP issued a draft NPDES Permit Renewal that, if finalized as proposed, would moot the appeal and reduce the estimated capital investment requirements. MP intends to vigorously pursue these issues but cannot predict the outcome of the appeal or estimate the possible loss or range of loss. FirstEnergy intends to vigorously defend against the CWA matters described above but, except as indicated above, cannot predict their outcomes or estimate the loss or range of loss. Regulation of Waste Disposal Federal and state hazardous waste regulations have been promulgated as a result of the RCRA, as amended, and the Toxic Substances Control Act. Certain 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. AE Supply assessed the changes in timing and closure plan requirements associated with the McElroy's Run impoundment site and increased the ARO by approximately $43 million in the third quarter of 2018. Pursuant to a 2013 consent decree, PA DEP issued a 2014 permit for the Little Blue Run CCR impoundment requiring the Bruce Mansfield plant to cease disposal of CCRs by December 31, 2016, and FG to provide bonding for 45 years of closure and post-closure activities and to complete closure within a 12-year period, but authorizing FG to seek a permit modification based on "unexpected site conditions that have or will slow closure progress." The permit does not require active dewatering of the CCRs, but does require a groundwater assessment for arsenic and abatement if certain conditions in the permit are met. The CCRs from the Bruce Mansfield plant are being beneficially reused with the majority used for reclamation of a site owned by the Marshall County Coal Company in Moundsville, West Virginia, and the remainder recycled into drywall by National Gypsum. These beneficial reuse options are expected to be sufficient for ongoing plant operations, however, the Bruce Mansfield plant is pursuing other options. On May 22, 2015 and September 21, 2015, the PA DEP reissued a permit for the Hatfield's Ferry CCR disposal facility and then modified that permit to allow disposal of Bruce Mansfield plant CCR. The Sierra Club's Notices of Appeal before the Pennsylvania Environmental Hearing Board challenging the renewal, reissuance and modification of the permit for the Hatfield’s Ferry CCR disposal facility were resolved through a Consent Adjudication between FG, PA DEP and the Sierra Club requiring operational changes that became effective November 3, 2017. As noted above, FE provides credit support for FG surety bonds of $169 million and $31 million for the benefit of the PA DEP with respect to LBR and the Hatfield's Ferry disposal site, respectively. FirstEnergy or its subsidiaries have been named as potentially responsible parties at waste disposal sites, which may require cleanup under the CERCLA. Allegations of disposal of hazardous substances at historical sites and the liability involved are often unsubstantiated and subject to dispute; however, federal law provides that all potentially responsible parties for a particular site may be liable on a joint and several basis. Environmental liabilities that are considered probable have been recognized on the Consolidated Balance Sheets as of December 31, 2018, 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 $121 million have been accrued through December 31, 2018, including approximately $85 million for environmental remediation of former manufactured gas plants and gas holder facilities in New Jersey, which are being recovered by JCP&L through a non-bypassable SBC. FE or its subsidiaries could be found potentially responsible for additional amounts or additional sites, but the loss or range of losses cannot be determined or reasonably estimated at this time. OTHER LEGAL PROCEEDINGS Nuclear Plant Matters Under NRC regulations, JCP&L, ME and PN must ensure that adequate funds will be available to decommission their retired nuclear facility, TMI-2. As of December 31, 2018 , JCP&L, ME and PN had in total approximately $790 million invested in external trusts to be used for the decommissioning and environmental remediation of their retired TMI-2 nuclear generating facility. The values of these NDTs also fluctuate based on market conditions. If the values of the trusts decline by a material amount, the obligation to JCP&L, ME and PN to fund the trusts may increase. Disruptions in the capital markets and their effects on particular businesses and the economy could also affect the values of the NDTs. FES Bankruptcy On March 31, 2018, FES, including its consolidated subsidiaries, FG, NG, FE Aircraft Leasing Corp., Norton Energy Storage L.L.C. and FGMUC, and FENOC filed voluntary petitions for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code in the Bankruptcy Court. See Note 3, "Discontinued Operations," for additional information. Other Legal Matters There are various lawsuits, claims (including claims for asbestos exposure) and proceedings related to FirstEnergy's normal business operations pending against FE or its subsidiaries. The loss or range of loss in these matters is not expected to be material to FE or its subsidiaries. The other potentially material items not otherwise discussed above are described under Note 16, "Regulatory Matters," of the Notes to Consolidated Financial Statements. FirstEnergy accrues legal liabilities only when it concludes that it is probable that it has an obligation for such costs and can reasonably estimate the amount of such costs. In cases where FirstEnergy determines that it is not probable, but reasonably possible that it has a material obligation, it discloses such obligations and the possible loss or range of loss if such estimate can be made. If it were ultimately determined that FE or its subsidiaries have legal liability or are otherwise made subject to liability based on any of the matters referenced above, it could have a material adverse effect on FE's or its subsidiaries' financial condition, results of operations and cash flows.

Transactions With Affiliated Co

Transactions With Affiliated Companies	12 Months Ended
	Dec. 31, 2018
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, as well as FES and FENOC, 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, including FES and FENOC, 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"). Additionally, the Utilities purchase power from FES to meet a portion of their POLR and default service requirements and provide power to certain facilities. See Note 3 "Discontinued Operations" for additional details.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
SEGMENT INFORMATION	SEGMENT INFORMATION Regulated Distribution and Regulated Transmission are FirstEnergy's reportable segments. Financial information for each of FirstEnergy’s reportable segments is presented in the tables below. 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. This segment also controls 3,790 MWs of regulated electric generation capacity located primarily in West Virginia, Virginia and New Jersey. Regulation of our retail distribution rates is generally premised on providing an opportunity to earn a reasonable return of and on prudently incurred invested capital to provide service to our customers through the use of both base rate proceedings and other cost-based rate mechanisms, including recovery riders and trackers. The segment's results reflect the costs of securing and delivering electric generation from transmission facilities to customers, including the deferral and amortization of certain related costs. The Regulated Transmission segment provides transmission infrastructure owned and operated by the Transmission Companies and certain of FirstEnergy's utilities (JCP&L, MP, PE and WP) to transmit electricity from generation sources to distribution facilities. The segment's revenues are primarily derived from forward-looking formula rates at the Transmission Companies as well as stated transmission rates at JCP&L, MP, PE and WP. Both the forward-looking formula and stated rates recover costs that the regulatory agencies determine are permitted to be recovered and provide a return on transmission capital investment. Under forward-looking formula rates, the revenue requirement is updated annually based on a projected rate base and projected costs, which is subject to an annual true-up based on actual costs. The segment's results also reflect the net transmission expenses related to the delivery of electricity on FirstEnergy's transmission facilities. The Corporate/Other segment reflects corporate support not charged to FE's subsidiaries, interest expense on FE’s holding company debt and other businesses that do not constitute an operating segment. Additionally, reconciling adjustments for the elimination of inter-segment transactions and discontinued operations are included in Corporate/Other. Reconciling adjustments are shown separately in the following table of Segment Financial Information. As of December 31, 2018, approximately 70 MWs of electric generating capacity, representing AE Supply's OVEC capacity entitlement, was included in continuing operations of the Corporate/Other reportable segment. As of December 31, 2018, Corporate/Other had approximately $7.1 billion of FE holding company debt. FES, FENOC, BSPC and a portion of AE Supply (including the Pleasants Power Station), representing substantially all of FirstEnergy’s operations that previously comprised the CES reportable operating segment, are presented as discontinued operations in FirstEnergy’s consolidated financial statements resulting from the FES Bankruptcy and actions taken as part of the strategic review to exit commodity-exposed generation, as discussed below. During the third quarter of 2018, the Pleasants Power Station was reclassified to discontinued operations following its inclusion in the definitive FES Bankruptcy settlement agreement for the benefit of FES' creditors. Prior period results have been reclassified to conform with such presentation as discontinued operations. The financial information for all periods has been revised to present the discontinued operations within Reconciling Adjustments. The remaining business activities that previously comprised the CES reportable operating segment were not material and, as such, have been combined into Corporate/Other for reporting purposes. Segment Financial Information For the Years Ended December 31, Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) 2018 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 Total assets 28,690 10,404 969 — 40,063 Total goodwill 5,004 614 — — 5,618 Property additions 1,411 1,104 133 27 2,675 2017 Total revenues $ 9,760 $ 1,324 $ 43 $ (199 ) $ 10,928 Provision for depreciation 724 224 10 69 1,027 Amortization of regulatory assets, net 292 16 — — 308 Impairment of assets — 41 — — 41 Miscellaneous income (expense), net 57 1 39 (44 ) 53 Interest expense 535 156 358 (44 ) 1,005 Income taxes (benefits) 580 205 930 — 1,715 Income (loss) from continuing operations 916 336 (1,541 ) — (289 ) Total assets 27,730 9,525 1,007 3,995 42,257 Total goodwill 5,004 614 — — 5,618 Property additions 1,191 1,030 49 317 2,587 2016 Total revenues $ 9,619 $ 1,143 $ 140 $ (202 ) $ 10,700 Provision for depreciation 676 187 3 67 933 Amortization of regulatory assets, net 290 7 — — 297 Impairment of assets — — 43 — 43 Miscellaneous income (expense), net 85 (1 ) (17 ) (23 ) 44 Interest expense 586 158 252 (23 ) 973 Income taxes (benefits) 375 187 (35 ) — 527 Income (loss) from continuing operations 651 331 (431 ) — 551 Total assets 27,702 8,755 1,061 5,630 43,148 Total goodwill 5,004 614 — — 5,618 Property additions 1,063 1,101 56 615 2,835

Summary of Quarterly Financial

Summary of Quarterly Financial Data (Unaudited)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Data [Abstract]
SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED)	SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED) The following summarizes certain consolidated operating results by quarter for 2018 and 2017 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2018 2017 (4) Dec. 31 Sep. 30 Jun. 30 Mar. 31 Dec. 31 Sep. 30 Jun. 30 Mar. 31 Revenues $ 2,710 $ 3,064 $ 2,625 $ 2,862 $ 2,681 $ 2,910 $ 2,561 $ 2,776 Other operating expense 770 739 684 940 803 651 657 650 Provision for depreciation 293 283 283 277 262 261 254 250 Impairment of assets (Note 1) — — — — 28 13 — — Operating Income 512 710 700 580 505 733 574 616 Pension and OPEB mark-to-market adjustment (144 ) — — — (102 ) — — — Income before income taxes 169 520 409 414 171 503 352 400 Income taxes (13 ) 133 121 249 1,232 202 132 149 Income from continuing operations 182 387 288 165 (1,061 ) 301 220 251 Discontinued operations (1) (Note 3) (44 ) (845 ) 11 1,204 (1,438 ) 95 (46 ) (46 ) Net Income (Loss) 138 (458 ) 299 1,369 (2,499 ) 396 174 205 Income allocated to preferred shareholders (2) 10 54 165 156 — — — — Net income (loss) attributable to common shareholders 128 (512 ) 134 1,213 (2,499 ) 396 174 205 Earnings (loss) per share of common stock- (3) Basic - Continuing Operations 0.34 0.66 0.27 0.01 (2.39 ) 0.68 0.49 0.57 Basic - Discontinued Operations (Note 3) (0.09 ) (1.68 ) 0.01 2.54 (3.23 ) 0.21 (0.10 ) (0.11 ) Basic - Net Income (Loss) Attributable to Common Shareholders 0.25 (1.02 ) 0.28 2.55 (5.62 ) 0.89 0.39 0.46 Diluted - Continuing Operations 0.34 0.66 0.27 0.01 (2.39 ) 0.68 0.49 0.57 Diluted - Discontinued Operations (Note 3) (0.09 ) (1.68 ) 0.01 2.53 (3.23 ) 0.21 (0.10 ) (0.11 ) Diluted - Net Income (Loss) Attributable to Common Shareholders 0.25 (1.02 ) 0.28 2.54 (5.62 ) 0.89 0.39 0.46 (1) Net of income taxes (2) The sum of quarterly income allocated to preferred shareholders may not equal annual income allocated to preferred shareholders as quarter-to-date and year-to-date amounts are calculated independently. (3) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares and conversion of preferred shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 6, "Stock-Based Compensation Plans," for additional information. (4) Prior year numbers have been re-casted for discontinued operations.

Consolidated Valuation and Qual

Consolidated Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2018
SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]
CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS	FIRSTENERGY CORP. CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 2018 , 2017 AND 2016 Additions Description Beginning Balance Charged to Income Charged to Other Accounts (1) Deductions (2) Ending Balance (In thousands) Year Ended December 31, 2018 (4) : Accumulated provision for uncollectible accounts — customers $ 48,937 $ 77,254 $ 60,307 $ 136,700 $ 49,798 — other 990 12,487 — 11,699 1,778 — affiliated companies (5) $ — $ 919,851 $ 919,851 Valuation allowance on various DTAs (3) $ 312,135 $ 81,977 $ — $ — $ 394,112 Year Ended December 31, 2017 (4) : Accumulated provision for uncollectible accounts — customers $ 48,409 $ 73,486 $ 49,728 $ 122,686 $ 48,937 — other 884 6,461 — 6,355 990 Valuation allowance on state and local DTAs $ 240,289 $ 71,846 $ — $ — $ 312,135 Year Ended December 31, 2016 (4) : Accumulated provision for uncollectible accounts — customers $ 60,309 $ 76,953 $ 15,222 $ 104,075 $ 48,409 — other 2,731 13,597 11,329 26,773 884 Valuation allowance on state and local DTAs $ 146,589 $ 93,700 $ — $ — $ 240,289 (1) Represents recoveries and reinstatements of accounts previously written off for uncollectible accounts. (2) Represents the write-off of accounts considered to be uncollectible. (3) Starting in 2018, valuation allowances are now being recorded against federal and state DTA's related to disallowed business interest and certain employee remuneration, in addition to the state and local DTA's in the prior years presented. (4) Amounts exclude FES and FENOC. (5) Amounts relate to FES and FENOC and are included in discontinued operations. See Note 3, "Discontinued Operations" for additional information.

Organization and Basis of Prese

Organization and Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [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. FE and its subsidiaries consolidate a VIE when it is determined that it is the primary beneficiary (see Note 10, "Variable Interest Entities"). Investments in affiliates over which FE and its subsidiaries have the ability to exercise significant influence, but do not have a controlling financial interest, follow the equity method of accounting. Under the equity method, the interest in the entity is reported as an investment in the Consolidated Balance Sheets and the percentage of FE's ownership share of the entity’s earnings is reported in the Consolidated Statements of Income (Loss) and Comprehensive Income (Loss).
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, AGC, 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 (Loss) 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 and the Utilities net their regulatory assets and liabilities based on federal and state jurisdictions.
Revenues and Receivables	CUSTOMER RECEIVABLES Receivables from customers include retail electric sales and distribution deliveries to residential, commercial and industrial customers for the Utilities.
Earnings Per Share of Common Stock	EARNINGS (LOSS) PER SHARE OF COMMON STOCK The convertible preferred stock issued in January 2018 (see Note 13, "Capitalization") is considered participating securities since these shares participate in dividends on common stock on an "as-converted" basis. As a result, EPS of common stock is computed using the two-class method required for participating securities. The two-class method uses an earnings allocation formula that treats participating securities as having rights to earnings that otherwise would have been available only to common stockholders. Under the two-class method, net income attributable to common stockholders is derived by subtracting the following from income from continuing operations: • preferred stock dividends, • deemed dividends for the amortization of the beneficial conversion feature recognized at issuance of the preferred stock (if any), and • an allocation of undistributed earnings between the common stock and the participating securities (convertible preferred stock) based on their respective rights to receive dividends. Net losses are not allocated to the convertible preferred stock as they do not have a contractual obligation to share in the losses of FirstEnergy. FirstEnergy allocates undistributed earnings based upon income from continuing operations. The preferred stock includes an embedded conversion option at a price that is below the fair value of the common stock on the commitment date. This beneficial conversion feature, which was approximately $296 million , represents the difference between the fair value per share of the common stock and the conversion price, multiplied by the number of common shares issuable upon conversion. The beneficial conversion feature was amortized as a deemed dividend over the period from the issue date to the first allowable conversion date (July 22, 2018) as a charge to OPIC, since FE is in an accumulated deficit position with no retained earnings to declare a dividend. As noted above, for EPS reporting purposes, this beneficial conversion feature will be reflected in net income (loss) attributable to common stockholders as a deemed dividend. The amount amortized for the year ended December 31, 2018, was $296 million . Basic EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding during the period. Participating securities are excluded from basic weighted average ordinary shares outstanding. Diluted EPS available to common stockholders is computed by dividing income available to common stockholders by the weighted average number of common shares outstanding, including all potentially dilutive common shares, if the effect of such common shares is dilutive. Diluted EPS reflects the dilutive effect of potential common shares from share-based awards and convertible preferred shares. The dilutive effect of outstanding share-based awards is computed using the treasury stock method, which assumes any proceeds that could be obtained upon the exercise of the award would be used to purchase common stock at the average market price for the period. The dilutive effect of the convertible preferred stock is computed using the if-converted method, which assumes conversion of the convertible preferred stock at the beginning of the period, giving income recognition for the add-back of the preferred share dividends, amortization of beneficial conversion feature, and undistributed earnings allocated to preferred stockholders.
Property, Plant and Equipment	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.
Asset Retirement Obligations	Asset Retirement Obligations FE recognizes an ARO for the future decommissioning of its nuclear power plant and future remediation of other 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.
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	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'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, 2018 :
Investments	INVESTMENTS All temporary cash investments purchased with an initial maturity of three months or less are reported as cash equivalents on the Consolidated Balance Sheets at cost, which approximates their fair market value. Investments other than cash and cash equivalents include equity securities, AFS debt securities and other investments. FirstEnergy has no debt securities held for trading purposes. Generally, unrealized gains and losses on equity securities are recognized in income whereas unrealized gains and losses on AFS debt securities are recognized in AOCI. However, the NDTs of JCP&L, ME and PN are subject to regulatory accounting with all gains and losses on equity and AFS debt securities offset against regulatory assets. The fair values of FirstEnergy’s investments are disclosed in Note 11, "Fair Value Measurements." The investment policy for the NDT funds restricts or limits the trusts' ability to hold certain types of assets including private or direct placements, warrants, securities of FirstEnergy, investments in companies owning nuclear power plants, financial derivatives, securities convertible into common stock and securities of the trust funds' custodian or managers and their parents or subsidiaries.
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.
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Recently Adopted Pronouncements ASU 2014-09, "Revenue from Contracts with Customers" (Issued May 2014 and subsequently updated to address implementation questions): The new revenue recognition guidance establishes a new control-based revenue recognition model, changes the basis for deciding when revenue is recognized over time or at a point in time, provides new and more detailed guidance on specific topics and expands and improves disclosures about revenue. FirstEnergy evaluated its revenues and determined the new guidance had immaterial impacts to recognition practices upon adoption on January 1, 2018. As part of the adoption, FirstEnergy elected to apply the new guidance on a modified retrospective basis. FirstEnergy did not record a cumulative effect adjustment to retained earnings for initially applying the new guidance as no revenue recognition differences were identified in the timing or amount of revenue. In addition, upon adoption, certain immaterial financial statement presentation changes were implemented. See Note 2, "Revenue," for additional information on FirstEnergy's revenues. ASU 2016-01, "Financial Instruments-Overall: Recognition and Measurement of Financial Assets and Financial Liabilities" (Issued January 2016 and subsequently updated in 2018): ASU 2016-01 primarily affects the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. FirstEnergy adopted this standard on January 1, 2018, and recognizes all gains and losses for equity securities in income with the exception of those that are accounted for under the equity method of accounting. The NDT equity portfolios of JCP&L, ME and PN will not be impacted as unrealized gains and losses will continue to be offset against regulatory assets or liabilities. As a result of adopting this standard, FirstEnergy recorded a cumulative effect adjustment to retained earnings of $57 million on January 1, 2018, representing unrealized gains on equity securities with FES NDTs that were previously recorded to AOCI. Following deconsolidation of the FES Debtors, the adoption of this standard is not expected to have a material impact on FirstEnergy's financial statements as the majority of its gains and losses on equity securities are offset against a regulatory asset or liability. ASU 2016-18, " Restricted Cash" (Issued November 2016): ASU 2016-18 addresses the presentation of changes in restricted cash and restricted cash equivalents in the statement of cash flows. The guidance is required to be applied retrospectively. As a result of adopting this standard, FirstEnergy's statement of cash flows reports changes in the total of cash, cash equivalents, restricted cash and restricted cash equivalents. Prior periods have been recast to conform to the current year presentation. ASU 2017-01, "Business Combinations: Clarifying the Definition of a Business" (Issued January 2017) : ASU 2017-01 assists entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. FirstEnergy adopted ASU 2017-01 on January 1, 2018. The ASU will be applied prospectively to future transactions. ASU 2017-04, "Goodwill Impairment" (Issued January 2017): ASU 2017-04 simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. FirstEnergy has elected to early adopt ASU 2017-04 as of January 1, 2018, and will apply this standard on a prospective basis. ASU 2017-07, "Compensation-Retirement Benefits: Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost" (Issued March 2017) : ASU 2017-07 requires entities to retrospectively (1) disaggregate the current-service-cost component from the other components of net benefit cost (the other components) and present it with other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the income statement and outside of income from operations if such a subtotal is presented. In addition, only service costs are eligible for capitalization on a prospective basis. FirstEnergy adopted ASU 2017-07 on January 1, 2018. Because the non-service cost components of net benefit cost are no longer eligible for capitalization after December 31, 2017, FirstEnergy has recognized these components in income as a result of adopting this standard. FirstEnergy reclassified approximately $27 million and $6 million of non-service costs from Other operating expenses to Miscellaneous income, net, for the years ended December 31, 2017 and December 31, 2016, respectively. ASU 2018-02, " Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income " (Issued February 2018): ASU 2018-02 allows entities to reclassify from AOCI to retained earnings stranded tax effects resulting from the Tax Act. FirstEnergy early adopted this standard during the first quarter of 2018 and has elected to present the change in the period of adoption. Upon adoption, FirstEnergy recorded a $22 million cumulative effect adjustment for stranded tax effects, such as pension and OPEB prior service costs and losses on derivative hedges, to retained earnings on January 1, 2018, of which $8 million was related to the FES Debtors. ASU 2018-05, " Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118 " (Issued March 2018): ASU 2018-05, effective 2018, expands income tax accounting and disclosure guidance to include SAB 118 issued by the SEC in December 2017. SAB 118 provides guidance on accounting for the income tax effects of the Tax Act and among other things allows for a measurement period not to exceed one year for companies to finalize the provisional amounts recorded as of December 31, 2017. See Note 7, "Taxes," for additional information on FirstEnergy's accounting for the Tax Act. ASU 2018-13, " Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement " (Issued August 2018): ASU 2018-13 eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB's disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, but public companies will be required to disclose the range and weighted average used to develop significant unobservable inputs for Level 3 fair value measurements. Entities are permitted to early adopt either the entire standard or only the provisions that eliminate or modify the requirements. FirstEnergy early adopted all the provisions of this standard as of December 31, 2018 which are reflected in Note 11, "Fair Value Measurements". ASU 2018-14, " Compensation-Retirement Benefits-Defined Benefit Plans-General (Subtopic 715-20): Disclosure Framework-Changes to the Disclosure Requirements for Defined Benefit Plans " (Issued August 2018): ASU 2018-14 amends ASC 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. FirstEnergy early adopted ASU 2018-14 as of December 31, 2018 and the provisions of this standard are reflected within Note 5, "Pension and Other Postemployment Benefits". Recently Issued Pronouncements - The following new authoritative accounting guidance issued by the FASB was not adopted in 2018. 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 and has not included these standards based upon the current expectation that such new standards will not significantly impact FirstEnergy's financial reporting. ASU 2016-02, "Leases (Topic 842) " (Issued February 2016 and subsequently updated to address implementation questions): The new guidance will require organizations that lease assets with lease terms of more than 12 months to recognize assets and liabilities for the rights and obligations created by those leases on their balance sheets as well as new qualitative and quantitative disclosures. FirstEnergy has implemented a third-party software tool that will assist with the initial adoption and ongoing compliance. The standard provides a number of transition practical expedients that entities may elect. These include a "package of three" expedients that must be taken together and allow 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. A separate practical expedient allows entities to not evaluate land easements under the new guidance at adoption if they were not previously accounted for as leases. Additionally, entities have the option to apply the requirements of the standard in the period of adoption (January 1, 2019) with no restatement of prior periods. FirstEnergy elected all of these practical expedients. Upon adoption, on January 1, 2019, FirstEnergy increased assets and liabilities by approximately $190 million, with no impact to results of operations or cash flows. ASU 2016-13, “ Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments ” (issued June 2016 and subsequently updated): ASU 2016-13 removes all recognition thresholds and will require companies to recognize an allowance for credit losses for the difference between the amortized cost basis of a financial instrument and the amount of amortized cost that the company expects to collect over the instrument’s contractual life. The ASU is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. Early adoption is permitted for fiscal years beginning after December 15, 2018 . ASU 2018-15, " Intangibles-Goodwill and Other-Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract " (Issued August 2018): ASU 2018-15 requires implementation costs incurred by customers in cloud computing arrangements to be deferred and recognized over the term of the arrangement, if those costs would be capitalized by the customers in a software licensing arrangement. The guidance will be effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019, with early adoption permitted.
Pension and Other Postretirement Plans	PENSION AND OTHER POSTEMPLOYMENT 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. The pension and OPEB mark-to-market adjustment for the years ended December 31, 2018, 2017, and 2016 were $145 million , $141 million , and $147 million , respectively. Of these amounts, approximately $1 million , $39 million , and $45 million , are included in discontinued operations for the years ended December 31, 2018, 2017, and 2016, respectively. In 2018, the pension and OPEB mark-to-market adjustment primarily reflects a 69 bps increase in the discount rate used to measure benefit obligations and lower than expected asset returns. 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. As a result of this contribution, FirstEnergy expects no required contributions through 2021. In 2016, FirstEnergy satisfied its minimum required funding obligations of $382 million and addressed 2017 funding obligations to its qualified pension plan with total contributions of $882 million (of which $138 million was cash contributions from FES), including $500 million of FE common stock contributed to the qualified pension plan on December 13, 2016.
Share-based Compensation, Option and Incentive Plans	Shares granted under the ICP 2007 and ICP 2015 are issued from authorized but unissued common stock. Vesting periods for stock-based awards range from one 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. Beginning in 2017, based upon the adoption of ASU 2016-09, "Improvements to Employee Share-Based Payment Accounting," FE has elected to account for forfeitures as they occur. As discussed in Note 1, "Organization and Basis of Presentation," on March 31, 2018, FES and FENOC announced the FES Bankruptcy. FirstEnergy will retain certain obligations for the FES Debtors employees' outstanding awards issued under the 2015 ICP for the 2016-2018 performance cycle. 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
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.
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. See Note 12, "Derivative Instruments," for additional information regarding FirstEnergy's FTRs. 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 ICE quotes and management assumptions. Generation MWH reflects data provided by contractual arrangements and historical trends. The model calculates the fair value by multiplying the prices by the generation MWH. Significant increases or decreases in inputs in isolation may have resulted in a higher or lower fair value measurement.
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 also uses a variety of derivative instruments for risk management purposes including forward contracts, options, futures contracts and swaps. FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows: • Changes in the fair value of derivative instruments that are designated and qualify as cash flow hedges are recorded to AOCI with subsequent reclassification to earnings in the period during which the hedged forecasted transaction affects earnings. • Changes in the fair value of derivative instruments that are designated and qualify as fair value hedges are recorded as an adjustment to the item being hedged. When fair value hedges are discontinued, the adjustment recorded to the item being hedged is amortized into earnings. • Changes in the fair value of derivative instruments that are not designated in a hedging relationship are recorded in earnings on a mark-to-market basis, unless otherwise noted. Derivative instruments meeting the normal purchases and normal sales criteria are accounted for under the accrual method of accounting with their effects included in earnings at the time of contract performance.
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, as well as FES and FENOC, 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.

Organization and Basis of Pre_2

Organization and Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2018
Accounting Policies [Abstract]
Regulatory assets on the Balance Sheets	The following table provides information about the composition of net regulatory assets and liabilities as of December 31, 2018 and December 31, 2017 , and the changes during the year ended December 31, 2018 : Net Regulatory Assets (Liabilities) by Source December 31, December 31, Change (In millions) Regulatory transition costs $ 49 $ 46 $ 3 Customer payables for future income taxes (2,725 ) (2,765 ) 40 Nuclear decommissioning and spent fuel disposal costs (148 ) (323 ) 175 Asset removal costs (787 ) (774 ) (13 ) Deferred transmission costs 170 187 (17 ) Deferred generation costs 202 198 4 Deferred distribution costs 208 258 (50 ) Contract valuations 62 118 (56 ) Storm-related costs 500 329 171 Other 62 46 16 Net Regulatory Liabilities included on the Consolidated Balance Sheets $ (2,407 ) $ (2,680 ) $ 273
Receivables from customers	Billed and unbilled customer receivables as of December 31, 2018 and 2017 , net of allowance for uncollectible accounts, are included below. Customer Receivables December 31, 2018 December 31, 2017 (In millions) Billed $ 686 $ 754 Unbilled 535 528 Total $ 1,221 $ 1,282
Reconciliation of basic and diluted earnings per share	Year Ended December 31, Reconciliation of Basic and Diluted EPS of Common Stock 2018 2017 2016 (In millions, except per share amounts) EPS of Common Stock Income from continuing operations $ 1,022 $ (289 ) $ 551 Less: Preferred dividends (71 ) — — Less: Amortization of beneficial conversion feature (296 ) — — Less: Undistributed earnings allocated to preferred stockholders (1) — — — Income from continuing operations available to common stockholders 655 (289 ) 551 Discontinued operations, net of tax 326 (1,435 ) (6,728 ) Less: Undistributed earnings allocated to preferred stockholders (1) — — — Income (loss) from discontinued operations available to common stockholders 326 (1,435 ) (6,728 ) Net Income (loss) attributable to common stockholders, basic and diluted $ 981 $ (1,724 ) $ (6,177 ) Share Count information: Weighted average number of basic shares outstanding 492 444 426 Assumed exercise of dilutive stock options and awards 2 — — Weighted average number of diluted shares outstanding 494 444 426 Net Income (loss) attributable to common stockholders, per share: Income from continuing operations, basic $ 1.33 $ (0.65 ) $ 1.29 Discontinued operations, basic 0.66 (3.23 ) (15.78 ) Net income (loss) attributable to common stockholders, basic $ 1.99 $ (3.88 ) $ (14.49 ) Income from continuing operations, diluted $ 1.33 $ (0.65 ) $ 1.29 Discontinued operations, diluted 0.66 (3.23 ) (15.78 ) Net income (loss) attributable to common stockholders, diluted $ 1.99 $ (3.88 ) $ (14.49 ) (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 negative.
Property, plant and equipment balances	Property, plant and equipment balances by segment as of December 31, 2018 and 2017 , were as follows: December 31, 2018 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 27,520 $ (8,132 ) $ 19,388 $ 628 $ 20,016 Regulated Transmission 11,041 (2,210 ) 8,831 545 9,376 Corporate/Other 908 (451 ) 457 62 519 Total $ 39,469 $ (10,793 ) $ 28,676 $ 1,235 $ 29,911 December 31, 2017 Property, Plant and Equipment In Service (1) Accum. Depr. Net Plant CWIP Total (In millions) Regulated Distribution $ 25,950 $ (7,503 ) $ 18,447 $ 469 $ 18,916 Regulated Transmission 10,102 (2,055 ) 8,047 480 8,527 Corporate/Other 1,061 (453 ) 608 50 658 Total $ 37,113 $ (10,011 ) $ 27,102 $ 999 $ 28,101 (1) Includes capital leases of $173 million and $190 million as of December 31, 2018 and 2017, respectively.
Annual composite rates	The respective annual composite depreciation rates for FirstEnergy were 2.6% , 2.4% and 2.3% in 2018 , 2017 and 2016 , respectively.
Summary of changes in goodwill	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, 2018 : Regulated Distribution Regulated Transmission Consolidated (In millions) Goodwill $ 5,004 $ 614 $ 5,618

Discontinued Operations (Tables

Discontinued Operations (Tables)	12 Months Ended
	Dec. 31, 2018
Discontinued Operations and Disposal Groups [Abstract]
Disposal Groups, Including Discontinued Operations	Summarized results of discontinued operations for the years ended December 31, 2018, 2017 and 2016 were as follows: For the Years Ended December 31, (In millions) 2018 2017 2016 Revenues $ 989 $ 3,055 $ 3,794 Fuel (304 ) (879 ) (1,073 ) Purchased power (84 ) (268 ) (533 ) Other operating expenses (435 ) (1,499 ) (1,263 ) Provision for depreciation (96 ) (109 ) (378 ) General taxes (35 ) (103 ) (129 ) Impairment of assets (2) — (2,358 ) (10,622 ) Other expense, net (83 ) (94 ) (106 ) Loss from discontinued operations, before tax (48 ) (2,255 ) (10,310 ) Income tax expense (benefit) (1) 61 (820 ) (3,582 ) Loss from discontinued operations, net of tax (109 ) (1,435 ) (6,728 ) Gain on disposal of FES and FENOC, net of tax 435 — — Income (Loss) from discontinued operations $ 326 $ (1,435 ) $ (6,728 ) (1) In conjunction with the sale of an interest in Bath County, AGC wrote off and recognized as a benefit in discontinued operations in the second quarter of 2018 its excess deferred tax liabilities of $32 million , created from the Tax Act, since they are not required to be refunded to ratepayers. Nondeductible interest of $60 million in 2018 has been recorded in discontinued operations as it is entirely attributed to the anticipated inclusion of the FES Debtors in the FirstEnergy consolidated tax return. See further discussion in Note 7, "Taxes". (2) Impairment of assets included in discontinued operations for the year ended December 31, 2017 include amounts related to impairment of the FES nuclear facilities, the Pleasants Power Station ( $120 million in the fourth quarter of 2017), and the competitive asset generation sale ( $193 million during 2017). Amounts included for the year ended December 31, 2016, include impairment of FES coal and nuclear plants and goodwill associated with AE Supply and FES, as well as other competitive assets including materials and supplies. The gain on disposal that was recognized in the year ended December 31, 2018, consisted of the following: (In millions) 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 (1,197 ) Loss on disposal of FES and FENOC, before tax (877 ) Income tax benefit, including estimated worthless stock deduction 1,312 Gain on disposal of FES and FENOC, net of tax $ 435 The following table summarizes the major classes of assets and liabilities as discontinued operations as of December 31, 2018, and 2017: (In millions) December 31, 2018 December 31, 2017 Carrying amount of the major classes of assets included in discontinued operations: Cash and cash equivalents $ — $ 1 Restricted cash — 3 Receivables — 202 Materials and supplies 25 227 Prepaid taxes and other — 199 Total current assets 25 632 Property, plant and equipment — 1,132 Investments — 1,875 Other noncurrent assets — 356 Total noncurrent assets — 3,363 Total assets included in discontinued operations $ 25 $ 3,995 Carrying amount of the major classes of liabilities included in discontinued operations: Currently payable long-term debt $ — $ 524 Accounts payable — 200 Accrued taxes — 38 Accrued compensation and benefits — 79 Other current liabilities — 137 Total current liabilities — 978 Long-term debt and other long-term obligations — 2,428 Accumulated deferred income taxes (1) — (1,812 ) Asset retirement obligations — 1,945 Deferred gain on sale and leaseback transaction — 723 Other noncurrent liabilities — 244 Total noncurrent liabilities — 3,528 Total liabilities included in discontinued operations $ — $ 4,506 (1) Represents an increase in FirstEnergy's ADIT liability as an ADIT asset was removed upon deconsolidation of FES and FENOC. FirstEnergy's Consolidated Statement of Cash Flows combines cash flows from discontinued operations with cash flows from continuing operations within each cash flow category. The following table summarizes the major classes of cash flow items as discontinued operations for the years ended December 31, 2018, 2017 and 2016: For the Years Ended December 31, (In millions) 2018 2017 2016 CASH FLOWS FROM OPERATING ACTIVITIES: Income from discontinued operations $ 326 $ (1,435 ) $ (6,728 ) Gain on disposal, net of tax (435 ) — — Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs 110 333 669 Deferred income taxes and investment tax credits, net 61 (842 ) (3,582 ) Unrealized (gain) loss on derivative transactions (10 ) 81 9 CASH FLOWS FROM INVESTING ACTIVITIES: Property additions (27 ) (317 ) (615 ) Nuclear fuel — (254 ) (232 ) Sales of investment securities held in trusts 109 940 717 Purchases of investment securities held in trusts (122 ) (999 ) (783 )

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue	The following table represents a disaggregation of revenue from contracts with regulated transmission customers for the year ended December 31, 2018, by transmission owner: Revenues from Contracts with Customers by Transmission Asset Owner (In millions) ATSI $ 664 TrAIL 237 MAIT 150 Other 284 Total $ 1,335 The following table represents a disaggregation of the Regulated Distribution segment revenue from contracts with distribution service and retail generation customers for the year ended December 31, 2018, by class: Revenues by Customer Class (In millions) Residential $ 5,598 Commercial 2,350 Industrial 1,056 Other 91 Total $ 9,095 The following tables represent a disaggregation of revenue from contracts with customers for the year ended December 31, 2018, by type of service from each reportable segment: 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 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 $147 million in net 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).

Accumulated Other Comprehensi_2

Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2018
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income	The changes in AOCI for the years ended December 31, 2018 , 2017 and 2016 , for FirstEnergy are shown in the following table: Gains & Losses on Cash Flow Hedges Unrealized Gains on AFS Securities Defined Benefit Pension & OPEB Plans Total (In millions) AOCI Balance, January 1, 2016 $ (33 ) $ 18 $ 186 $ 171 Other comprehensive income before reclassifications — 106 13 119 Amounts reclassified from AOCI 8 (51 ) (72 ) (115 ) Other comprehensive income (loss) 8 55 (59 ) 4 Income tax (benefits) on other comprehensive income (loss) 3 21 (23 ) 1 Other comprehensive income (loss), net of tax 5 34 (36 ) 3 AOCI Balance, December 31, 2016 $ (28 ) $ 52 $ 150 $ 174 Other comprehensive income before reclassifications — 85 (11 ) 74 Amounts reclassified from AOCI 10 (63 ) (74 ) (127 ) Other comprehensive income (loss) 10 22 (85 ) (53 ) Income tax (benefits) on other comprehensive income (loss) 4 7 (32 ) (21 ) Other comprehensive income (loss), net of tax 6 15 (53 ) (32 ) AOCI Balance, December 31, 2017 $ (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
Reclassification out of Accumulated Other Comprehensive Income	The following amounts were reclassified from AOCI for FirstEnergy in the years ended December 31, 2018 , 2017 and 2016 : Year Ended December 31, Affected Line Item in Consolidated Statements of Income (Loss) Reclassifications from AOCI (1) 2018 (3) 2017 2016 (In millions) Gains & losses on cash flow hedges Commodity contracts $ 1 $ 2 $ — Other operating expenses Long-term debt 7 8 8 Interest expense 8 10 8 Total before taxes (2 ) (4 ) (3 ) Income taxes $ 6 $ 6 $ 5 Net of tax Unrealized gains on AFS securities Realized gains on sales of securities $ (1 ) $ (40 ) $ (32 ) Discontinued Operations Defined benefit pension and OPEB plans Prior-service costs $ (74 ) $ (74 ) $ (72 ) (2) 19 28 27 Income taxes $ (55 ) $ (46 ) $ (45 ) Net of tax (1) Amounts in parenthesis represent credits to the Consolidated Statements of Income (Loss) from AOCI. (2) Components are included in the computation of net periodic pension cost. See Note 5, "Pension and Other Postemployment Benefits," for additional details. (3) 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 ".

Stock-Based Compensation Plans

Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2018
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 are included in the following tables: Years Ended December 31, Stock-based Compensation Plan 2018 2017 2016 (In millions) Restricted Stock Units $ 102 $ 49 $ 62 Restricted Stock 1 1 2 Performance Shares — — (3 ) 401(k) Savings Plan 33 42 39 EDCP & DCPD 7 6 5 Total $ 143 $ 98 $ 105 Stock-based compensation costs capitalized $ 60 $ 37 $ 37
Schedule of Nonvested Restricted Stock Units Activity	Restricted stock unit activity for the year ended December 31, 2018 , was as follows: Restricted Stock Unit Activity Shares (in millions) Weighted-Average Grant Date Fair Value (per share) Nonvested as of January 1, 2018 3.3 $ 33.24 Granted in 2018 2.0 36.78 Forfeited in 2018 (0.1 ) 33.77 Vested in 2018 (1) (1.9 ) 32.49 Nonvested as of December 31, 2018 3.3 $ 33.78 (1) Excludes dividend equivalents of approximately 143 thousand shares earned during vesting period
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 2018 . Stock option activity during 2018 was as follows: Stock Option Activity Number of Shares (in millions) Weighted Average Exercise Price (per share) Balance, January 1, 2017 (all options exercisable) 1.4 $ 44.41 Options exercised (0.3 ) 35.45 Options forfeited (0.3 ) 79.99 Balance, December 31, 2018 (all options exercisable) 0.8 $ 37.37

Pension and Other Postemploym_2

Pension and Other Postemployment Benefits (Tables)	12 Months Ended
	Dec. 31, 2018
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 2018 2017 2018 2017 (In millions) Change in benefit obligation: Benefit obligation as of January 1 $ 10,167 $ 9,426 $ 731 $ 711 Service cost 224 208 5 5 Interest cost 372 390 25 27 Plan participants’ contributions — — 3 4 Plan amendments 5 11 5 — Special termination benefits 31 — 8 — Medicare retiree drug subsidy — — 1 1 Annuity purchase (129 ) — — — Actuarial (gain) loss (710 ) 610 (121 ) 32 Benefits paid (498 ) (478 ) (49 ) (49 ) Benefit obligation as of December 31 $ 9,462 $ 10,167 $ 608 $ 731 Change in fair value of plan assets: Fair value of plan assets as of January 1 $ 6,704 $ 6,213 $ 439 $ 420 Actual return on plan assets (363 ) 950 (8 ) 49 Annuity purchase (129 ) — — — Company contributions 1,270 18 22 16 Plan participants’ contributions — — 3 4 Benefits paid (498 ) (477 ) (48 ) (50 ) Fair value of plan assets as of December 31 $ 6,984 $ 6,704 $ 408 $ 439 Funded Status: Qualified plan $ (2,093 ) $ (3,043 ) $ — $ — Non-qualified plans (385 ) (420 ) — — Funded Status $ (2,478 ) $ (3,463 ) $ (200 ) $ (292 ) Accumulated benefit obligation $ 8,951 $ 9,583 $ — $ — Amounts Recognized on the Balance Sheet: Noncurrent assets $ 14 $ — $ — $ — Current liabilities (20 ) (19 ) — — Noncurrent liabilities (2,472 ) (3,444 ) (200 ) (292 ) Net liability as of December 31 $ (2,478 ) $ (3,463 ) $ (200 ) $ (292 ) Amounts Recognized in AOCI: Prior service cost (credit) $ 30 $ 32 $ (121 ) $ (206 ) Assumptions Used to Determine Benefit Obligations (as of December 31) Discount rate 4.44 % 3.75 % 4.30 % 3.50 % Rate of compensation increase 4.10 % 4.20 % N/A N/A Cash balance weighted average interest crediting rate 3.34 % 2.88 % N/A N/A Assumed Health Care Cost Trend Rates (as of December 31) Health care cost trend rate assumed (pre/post-Medicare) 6.0-5.5% 6.0-5.5% 6.0-5.5% 6.0-5.5% Rate to which the cost trend rate is assumed to decline (the ultimate trend rate) 4.5 % 4.5 % 4.5 % 4.5 % Year that the rate reaches the ultimate trend rate 2028 2027 2028 2027 Allocation of Plan Assets (as of December 31) Equity securities 36 % 42 % 48 % 50 % Bonds 34 % 32 % 35 % 33 % Absolute return strategies 11 % 10 % — % — % Real estate funds 10 % 9 % — % — % Derivatives 2 % — % — % — % Private equity funds 2 % 1 % — % — % Cash and short-term securities 5 % 6 % 17 % 17 % Total 100 % 100 % 100 % 100 %
Components of Net Periodic Benefit Costs	Components of Net Periodic Benefit Costs for Years Ended December 31, Pension OPEB 2018 2017 2016 2018 2017 2016 (In millions) Service cost $ 224 $ 208 $ 191 $ 5 $ 5 $ 5 Interest cost 372 390 398 25 27 30 Expected return on plan assets (574 ) (448 ) (399 ) (31 ) (30 ) (30 ) Amortization of prior service cost (credit) 7 7 8 (81 ) (81 ) (80 ) Special termination costs 31 — — 8 — — Pension & OPEB mark-to-market adjustment 227 108 179 (82 ) 13 15 Net periodic benefit cost (credit) $ 287 $ 265 $ 377 $ (156 ) $ (66 ) $ (60 )
Assumptions Used to Determine Net Periodic Benefit Cost	Assumptions Used to Determine Net Periodic Benefit Cost for the Years Ended December 31,* Pension OPEB 2018 2017 2016 2018 2017 2016 Weighted-average discount rate 3.75 % 4.25 % 4.50 % 3.50 % 4.00 % 4.25 % Expected long-term return on plan assets 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % 7.50 % Rate of compensation increase 4.20 % 4.20 % 4.20 % N/A N/A N/A * Excludes impact of pension and OPEB mark-to-market adjustment.
Target asset allocations for pension and OPEB portfolio	FirstEnergy’s target asset allocations for its pension and OPEB trust portfolios for 2018 and 2017 are shown in the following table: Target Asset Allocations Equities 38 % Fixed income 30 % Absolute return strategies 8 % Real estate 10 % Alternative investments 8 % Cash 6 % 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) 2019 $ 509 $ 57 $ (1 ) 2020 533 48 (1 ) 2021 554 48 (1 ) 2022 566 47 (1 ) 2023 580 46 (1 ) Years 2024-2028 3,047 213 (3 )
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 11, "Fair Value Measurements," for a description of each level of the fair value hierarchy. There were no significant transfers between levels during 2018 and 2017 . December 31, 2018 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 342 $ — $ 342 5 % Equity investments: Domestic 723 122 — 845 12 % International 392 1,232 — 1,624 22 % Fixed income: Government bonds — 59 — 59 1 % Corporate bonds — 1,674 — 1,674 23 % High yield debt — 667 — 667 10 % Alternatives: Hedge funds (absolute return) — 681 — 681 11 % Derivatives 108 — — 108 2 % Real estate funds — — 665 665 10 % Total (1) $ 1,223 $ 4,777 $ 665 $ 6,665 96 % Private equity funds (2) 143 2 % Insurance-linked securities (2) 108 2 % Total Investments $ 6,916 100 % (1) Excludes $68 million as of December 31, 2018 , 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. December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 379 $ — $ 379 6 % Equity investments: Domestic 695 27 — 722 11 % International 514 1,569 — 2,083 31 % Fixed income: Government bonds — 251 — 251 4 % Corporate bonds — 1,237 — 1,237 18 % High yield debt — 689 — 689 10 % Mortgage-backed securities (non-government) — 31 — 31 — % Alternatives: Hedge funds (absolute return) — 635 — 635 10 % Derivatives — (1 ) — (1 ) — % Real estate funds — — 631 631 9 % Total (1) $ 1,209 $ 4,817 $ 631 $ 6,657 99 % Private equity funds (2) 57 1 % Total Investments $ 6,714 100 % (1) Excludes $(10) million as of December 31, 2017 , 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.
Reconciliation of changes in the fair value of pension investments	The following table provides a reconciliation of changes in the fair value of pension investments classified as Level 3 in the fair value hierarchy during 2018 and 2017 : Real Estate Funds Balance as of January 1, 2017 $ 615 Actual return on plan assets: Unrealized gains 3 Realized gains 10 Transfers in 3 Balance as of December 31, 2017 $ 631 Actual return on plan assets: Unrealized gains 102 Realized losses (65 ) Transfers out (3 ) Balance as of December 31, 2018 $ 665
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	As of December 31, 2018 and 2017 , the OPEB trust investments measured at fair value were as follows: December 31, 2018 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 71 $ — $ 71 17 % Equity investment: Domestic 196 — — 196 48 % Fixed income: Government bonds — 107 — 107 26 % Corporate bonds — 32 — 32 8 % Mortgage-backed securities (non-government) 4 — 4 1 % Total (1) $ 196 $ 214 $ — $ 410 100 % (1) Excludes $(2) million as of December 31, 2018 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table. December 31, 2017 Asset Allocation Level 1 Level 2 Level 3 Total (In millions) Cash and short-term securities $ — $ 75 $ — $ 75 17 % Equity investment: Domestic 220 — — 220 50 % Fixed income: Government bonds — 109 — 109 24 % Corporate bonds — 34 — 34 8 % Mortgage-backed securities (non-government) 3 — 3 1 % Total (1) $ 220 $ 221 $ — $ 441 100 % (1) Excludes $(2) million as of December 31, 2017 , of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.

Taxes (Tables)

Taxes (Tables)	12 Months Ended
	Dec. 31, 2018
Income Tax Disclosure [Abstract]
Provision for income taxes (benefits)	For the Years Ended December 31, INCOME TAXES (1) 2018 2017 2016 (In millions) Currently payable (receivable)- Federal $ (16 ) $ 14 $ (1 ) State 17 20 9 1 34 8 Deferred, net- Federal 252 1,647 317 State 243 40 208 495 1,687 525 Investment tax credit amortization (6 ) (6 ) (6 ) Total income taxes $ 490 $ 1,715 $ 527 (1) Income Taxes on Income from Continuing Operations. Currently payable (receivable) in 2018 excludes $1 million of state taxes associated with discontinued operations. Deferred, net in 2018 excludes $1.3 billion of federal tax benefits and $12 million of state taxes associated with discontinued operations
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, 2018, 2017 and 2016: For the Years Ended December 31, 2018 2017 2016 (In millions) Income from Continuing Operations, before income taxes $ 1,512 $ 1,426 $ 1,078 Federal income tax expense at statutory rate (21%, 35%, and 35% for 2018, 2017, and 2016, respectively) $ 318 $ 499 $ 377 Increases (reductions) in taxes resulting from- State income taxes, net of federal tax benefit 90 40 16 AFUDC equity and other flow-through (31 ) (15 ) (13 ) Amortization of investment tax credits (5 ) (6 ) (6 ) ESOP dividend (3 ) (5 ) (4 ) Remeasurement of deferred taxes 24 1,193 — WV unitary group remeasurement 126 — — Excess deferred tax amortization due to the Tax Act (60 ) — — Uncertain tax positions 2 (3 ) (8 ) Valuation allowances 21 11 160 Other, net 8 1 5 Total income taxes $ 490 $ 1,715 $ 527 Effective income tax rate 32.4 % 120.3 % 49.0 %
Accumulated deferred income taxes	Accumulated deferred income taxes as of December 31, 2018 and 2017 , are as follows: As of December 31, 2018 2017 (In millions) Property basis differences $ 4,737 $ 4,354 Pension and OPEB (629 ) (708 ) TMI-2 nuclear decommissioning 82 37 AROs (215 ) (157 ) Regulatory asset/liability 414 416 Deferred compensation (170 ) (149 ) Estimated worthless stock deduction (1,004 ) — Loss carryforwards and AMT credits (899 ) (863 ) Valuation reserve 394 312 All other (208 ) (71 ) Net deferred income tax liability $ 2,502 $ 3,171
Pre-tax net operating loss expiration period	Expiration Period State Local (In millions) 2019-2023 $ 1,583 $ 1,581 2024-2028 1,526 — 2029-2033 1,862 — 2034-2038 1,067 — $ 6,038 $ 1,581
Changes in unrecognized tax benefits	The following table summarizes the changes in unrecognized tax positions for the years ended 2018 , 2017 and 2016 : (In millions) Balance, January 1, 2016 $ 26 Current year increases 2 Prior years increases 69 Prior years decreases (13 ) Balance, December 31, 2016 $ 84 Current year increases 2 Decrease for lapse in statute (6 ) Balance, December 31, 2017 $ 80 Current year increases 125 Prior years decreases (45 ) Decrease for lapse in statute (2 ) Balance, December 31, 2018 $ 158
Details of general taxes	General tax expense for the years ended December 31, 2018 , 2017 and 2016 , recognized in continuing operations is summarized as follows: For the Years Ended December 31, 2018 2017 2016 (In millions) KWH excise $ 198 $ 188 $ 196 State gross receipts 192 184 184 Real and personal property 478 452 421 Social security and unemployment 103 96 91 Other 22 20 21 Total general taxes $ 993 $ 940 $ 913

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2018
Leases [Abstract]
Future minimum capital lease payments	The future minimum capital lease payments as of December 31, 2018 , are as follows: Capital Leases (In millions) 2019 $ 24 2020 19 2021 16 2022 13 2023 8 Years thereafter 16 Total minimum lease payments 96 Interest portion (23 ) Present value of net minimum lease payments 73 Less current portion 18 Noncurrent portion $ 55
Future minimum operating lease payments	The future minimum operating lease payments as of December 31, 2018 , are as follows: Operating Leases (In millions) 2019 $ 34 2020 36 2021 34 2022 30 2023 28 Years thereafter 127 Total minimum lease payments $ 289

Intangible Assets (Tables)

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2018
Goodwill and Intangible Assets Disclosure [Abstract]
Future Amortization	As of December 31, 2018 , 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 2018 2019 2020 2021 2022 2023 Thereafter NUG contracts (1) $ 124 $ 41 $ 83 $ 5 $ 5 $ 5 $ 5 $ 5 $ 5 $ 58 OVEC 8 3 5 — 1 — — — 1 3 Coal contracts (2) 102 97 5 3 3 2 — — — — $ 234 $ 141 $ 93 $ 8 $ 9 $ 7 $ 5 $ 5 $ 6 $ 61 (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, 2018
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, 2018 December 31, 2017 Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Assets (In millions) Corporate debt securities $ — $ 405 $ — $ 405 $ — $ 476 $ — $ 476 Derivative assets FTRs (1) — — 10 10 — — 3 3 Equity securities (2) 339 — — 339 297 — — 297 Foreign government debt securities — 13 — 13 — 23 — 23 U.S. government debt securities — 20 — 20 — 21 — 21 U.S. state debt securities — 250 — 250 — 247 — 247 Other (3) 367 34 — 401 588 38 — 626 Total assets $ 706 $ 722 $ 10 $ 1,438 $ 885 $ 805 $ 3 $ 1,693 Liabilities Derivative liabilities FTRs (1) $ — $ — $ (1 ) $ (1 ) $ — $ — $ — $ — Derivative liabilities NUG contracts (1) — — (44 ) (44 ) — — (79 ) (79 ) Total liabilities $ — $ — $ (45 ) $ (45 ) $ — $ — $ (79 ) $ (79 ) Net assets (liabilities) (4) $ 706 $ 722 $ (35 ) $ 1,393 $ 885 $ 805 $ (76 ) $ 1,614 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings. (2) NDT funds hold equity portfolios whose performance is benchmarked against the S&P 500 Low Volatility High Dividend Index, S&P 500 Index, MSCI World Index and MSCI AC World IMI Index. (3) Primarily consists of short-term cash investments. (4) Excludes $4 million and $(11) million as of December 31, 2018 and December 31, 2017 , respectively, of receivables, payables, taxes and accrued income associated with financial instruments reflected within the fair value table.
Reconciliation of changes in the fair value roll forward of level 3 measurements of NUG contracts	The following table provides a reconciliation of changes in the fair value of NUG contracts and FTRs that are classified as Level 3 in the fair value hierarchy for the periods ended December 31, 2018 and December 31, 2017 : NUG Contracts (1) FTRs (1) Derivative Assets Derivative Liabilities Net Derivative Assets Derivative Liabilities Net (In millions) January 1, 2017 Balance $ 1 $ (108 ) $ (107 ) $ 3 $ (1 ) $ 2 Unrealized gain (loss) — (10 ) (10 ) 1 (1 ) — Purchases — — — 3 — 3 Settlements (1 ) 39 38 (4 ) 2 (2 ) December 31, 2017 Balance $ — $ (79 ) $ (79 ) $ 3 $ — $ 3 Unrealized gain (loss) — 2 2 8 1 9 Purchases — — — 5 (5 ) — Settlements — 33 33 (6 ) 3 (3 ) December 31, 2018 Balance $ — $ (44 ) $ (44 ) $ 10 $ (1 ) $ 9 (1) Contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.
Quantitative information for level 3 valuation	The following table provides quantitative information for FTRs and NUG contracts that are classified as Level 3 in the fair value hierarchy for the period ended December 31, 2018 : Fair Value, Net (In millions) Valuation Significant Input Range Weighted Average Units FTRs $ 9 Model RTO auction clearing prices $0.20 to $6.10 $1.80 Dollars/MWH NUG Contracts $ (44 ) Model Generation 400 to 1,214,000 $31.40 to $33.60 249,000 $32.60 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, 2018 and December 31, 2017 : December 31, 2018 (1) December 31, 2017 (1) Cost Basis Unrealized Gains Unrealized Losses Fair Value Cost Basis Unrealized Gains Unrealized Losses Fair Value (In millions) Debt securities $ 714 $ 2 $ (28 ) $ 688 $ 774 $ 11 $ (17 ) $ 768 Equity securities $ 339 $ 15 $ (16 ) $ 338 $ 254 $ 40 $ — $ 294 (1) Excludes short-term cash investments of $20 million and $11 million in 2018 and 2017, respectively
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income	Proceeds from the sale of investments in equity and AFS debt securities, realized gains and losses on those sales and interest and dividend income for the three years ended December 31, 2018 , 2017 and 2016 , were as follows: 2018 2017 2016 (In millions) Sale Proceeds $ 800 $ 1,230 $ 961 Realized Gains 41 74 53 Realized Losses (48 ) (58 ) (52 ) OTTI — — (2 ) Interest and Dividend Income 41 39 44
Fair value and related carrying amounts of long-term debt and other long-term obligations	The following table provides the approximate fair value and related carrying amounts of long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of December 31, 2018 and 2017: As of December 31, 2018 2017 (In millions) Carrying Value $ 18,315 $ 19,296 Fair Value 19,266 21,412

Capitalization (Tables)

Capitalization (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 , 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 capital lease obligations for FirstEnergy as of December 31, 2018 and 2017 : As of December 31, 2018 As of December 31, (Dollar amounts in millions) Maturity Date Interest Rate 2018 2017 FMBs and secured notes - fixed rate 2019 - 2056 1.726% - 9.740% $ 4,355 $ 4,692 Unsecured notes - fixed rate 2019 - 2047 2.850% - 7.700% 13,450 13,155 Unsecured notes - variable rate 2020 3.270% 500 1,450 Capital lease obligations 73 89 Unamortized debt discounts (39 ) (41 ) Unamortized debt issuance costs (95 ) (99 ) Unamortized fair value adjustments 10 (1 ) Currently payable long-term debt (503 ) (558 ) Total long-term debt and other long-term obligations $ 17,751 $ 18,687
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 capital leases, fair value purchase accounting adjustments and unamortized debt discounts and premiums, for the next five years as of December 31, 2018 . 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) 2019 $ 489 2020 $ 864 2021 $ 132 2022 $ 1,143 2023 $ 1,194
Outstanding PCRBs for the next three years	The following table classifies these PCRBs by year, excluding unamortized debt discounts and premiums, for the next five years based on the next date on which the debt holders may exercise their right to tender their PCRBs as of December 31, 2018: Year (In millions) 2019 $ — 2020 $ — 2021 $ 74 2022 $ — 2023 $ —

Short-Term Borrowings and Ban_2

Short-Term Borrowings and Bank Lines of Credit (Tables)	12 Months Ended
	Dec. 31, 2018
Debt Disclosure [Abstract]
Liquidity	FirstEnergy’s available liquidity from external sources as of February 18, 2019, was as follows: Borrower(s) Type Maturity Commitment Available Liquidity (In millions) FirstEnergy (1) Revolving December 2022 $ 2,500 $ 2,490 FET (2) Revolving December 2022 1,000 1,000 Subtotal $ 3,500 $ 3,490 Cash and cash equivalents — 156 Total $ 3,500 $ 3,646 (1) FE and the Utilities. Available liquidity includes impact of $10 million of LOCs issued under various terms. (2) Includes FET and the Transmission Companies.
Borrowing sub-limits for each borrower and limitations on short-term indebtedness	The following table summarizes the borrowing sub-limits for each borrower under the facilities, the limitations on short-term indebtedness applicable to each borrower under current regulatory approvals and applicable statutory and/or charter limitations as of January 31, 2019 : Borrower FirstEnergy Revolving Credit Facility Sub-Limits FET Revolving Credit Facility Sub-Limits Regulatory and Other Short-Term Debt Limitations (In millions) FE $ 2,500 $ — $ — (1) FET — 1,000 — (1) OE 500 — 500 (2) CEI 500 — 500 (2) TE 300 — 300 (2) JCP&L 500 — 500 (2) ME 500 — 500 (2) PN 300 — 300 (2) WP 200 — 200 (2) MP 500 — 500 (2) PE 150 — 150 (2) ATSI — 500 500 (2) Penn 100 — 100 (2) TrAIL — 400 400 (2) MAIT — 400 400 (2) (1) No limitations. (2) Includes amounts which may be borrowed under the regulated companies' money pool.
Weighted average interest rates on short-term borrowings outstanding	The weighted average interest rates on short-term borrowings outstanding, including borrowings under the FirstEnergy Money Pools, as of December 31, 2018 and 2017 , were 3.07% and 3.24% , respectively.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2018
Asset Retirement Obligation [Abstract]
Changes to the asset retirement obligations	The following table summarizes the changes to the ARO balances during 2018 and 2017 : ARO Reconciliation (In millions) Balance, January 1, 2017 $ 581 Transfer of BV-2 liability to NG (49 ) Liabilities settled (1 ) Accretion 39 Balance, December 31, 2017 $ 570 Changes in timing and amount of estimated cash flows 203 Liabilities settled (1 ) Accretion 40 Balance, December 31, 2018 $ 812

Regulatory Matters (Tables)

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2018
Regulated Operations [Abstract]
Distribution Rate Orders	The following table summarizes the key terms of rate orders in effect for transmission customer billings for FirstEnergy's transmission owner entities: Company Rates Effective Capital Structure Allowed ROE ATSI January 1, 2015 Actual (13 month average) 10.38% JCP&L June 1, 2017 Settled (1) Settled (1) MP March 21, 2018 (2) Settled (1) Settled (1) PE March 21, 2018 (2) Settled (1) Settled (1) WP March 21, 2018 (2) Settled (1) Settled (1) MAIT July 1, 2017 50% / 50% (hypothetical) (3) 10.3% TrAIL July 1, 2008 Actual (year-end) 12.7% (TrAIL the Line & Black Oak SVC) 11.7% (All other projects) (1) FERC-approved settlement agreements did not specify. (2) See FERC Actions on Tax Act below. (3) Effective January 2019, converts to lower of actual (13 month average) or 60%. The following table summarizes the key terms of distribution rate orders in effect for the Utilities. 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 January 2017 55% / 45% 9.6% OE January 2009 51% / 49% 10.5% PE-West Virginia February 2015 54% / 46% Settled (2) PE-Maryland November 1994 48% / 52% 11.9% 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.

Commitments, Guarantees and C_2

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2018
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, 2018 : Potential Collateral Obligations AE Supply Utilities and FET FE Total (In millions) Contractual Obligations for Additional Collateral At Current Credit Rating $ 1 $ — $ — $ 1 Upon Further Downgrade — 62 — 62 Surety Bonds (Collateralized Amount) (1) 1 59 246 306 Total Exposure from Contractual Obligations $ 2 $ 121 $ 246 $ 369 Surety Bonds are not tied to a credit rating. Surety Bonds' impact assumes maximum contractual obligations (typical obligations require 30 days to cure). FE provides credit support for FG surety bonds for $169 million and $31 million for the benefit of the PA DEP with respect to LBR CCR impoundment closure and post-closure activities and the Hatfield's Ferry CCR disposal site, respectively.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2018
Segment Reporting [Abstract]
Segment Financial Information	Segment Financial Information For the Years Ended December 31, Regulated Distribution Regulated Transmission Corporate/ Other Reconciling Adjustments FirstEnergy Consolidated (In millions) 2018 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 Total assets 28,690 10,404 969 — 40,063 Total goodwill 5,004 614 — — 5,618 Property additions 1,411 1,104 133 27 2,675 2017 Total revenues $ 9,760 $ 1,324 $ 43 $ (199 ) $ 10,928 Provision for depreciation 724 224 10 69 1,027 Amortization of regulatory assets, net 292 16 — — 308 Impairment of assets — 41 — — 41 Miscellaneous income (expense), net 57 1 39 (44 ) 53 Interest expense 535 156 358 (44 ) 1,005 Income taxes (benefits) 580 205 930 — 1,715 Income (loss) from continuing operations 916 336 (1,541 ) — (289 ) Total assets 27,730 9,525 1,007 3,995 42,257 Total goodwill 5,004 614 — — 5,618 Property additions 1,191 1,030 49 317 2,587 2016 Total revenues $ 9,619 $ 1,143 $ 140 $ (202 ) $ 10,700 Provision for depreciation 676 187 3 67 933 Amortization of regulatory assets, net 290 7 — — 297 Impairment of assets — — 43 — 43 Miscellaneous income (expense), net 85 (1 ) (17 ) (23 ) 44 Interest expense 586 158 252 (23 ) 973 Income taxes (benefits) 375 187 (35 ) — 527 Income (loss) from continuing operations 651 331 (431 ) — 551 Total assets 27,702 8,755 1,061 5,630 43,148 Total goodwill 5,004 614 — — 5,618 Property additions 1,063 1,101 56 615 2,835

Summary of Quarterly Financia_2

Summary of Quarterly Financial Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2018
Quarterly Financial Data [Abstract]
Schedule of Quarterly Financial Information	The following summarizes certain consolidated operating results by quarter for 2018 and 2017 . FirstEnergy CONSOLIDATED STATEMENTS OF INCOME (LOSS) (In millions, except per share amounts) 2018 2017 (4) Dec. 31 Sep. 30 Jun. 30 Mar. 31 Dec. 31 Sep. 30 Jun. 30 Mar. 31 Revenues $ 2,710 $ 3,064 $ 2,625 $ 2,862 $ 2,681 $ 2,910 $ 2,561 $ 2,776 Other operating expense 770 739 684 940 803 651 657 650 Provision for depreciation 293 283 283 277 262 261 254 250 Impairment of assets (Note 1) — — — — 28 13 — — Operating Income 512 710 700 580 505 733 574 616 Pension and OPEB mark-to-market adjustment (144 ) — — — (102 ) — — — Income before income taxes 169 520 409 414 171 503 352 400 Income taxes (13 ) 133 121 249 1,232 202 132 149 Income from continuing operations 182 387 288 165 (1,061 ) 301 220 251 Discontinued operations (1) (Note 3) (44 ) (845 ) 11 1,204 (1,438 ) 95 (46 ) (46 ) Net Income (Loss) 138 (458 ) 299 1,369 (2,499 ) 396 174 205 Income allocated to preferred shareholders (2) 10 54 165 156 — — — — Net income (loss) attributable to common shareholders 128 (512 ) 134 1,213 (2,499 ) 396 174 205 Earnings (loss) per share of common stock- (3) Basic - Continuing Operations 0.34 0.66 0.27 0.01 (2.39 ) 0.68 0.49 0.57 Basic - Discontinued Operations (Note 3) (0.09 ) (1.68 ) 0.01 2.54 (3.23 ) 0.21 (0.10 ) (0.11 ) Basic - Net Income (Loss) Attributable to Common Shareholders 0.25 (1.02 ) 0.28 2.55 (5.62 ) 0.89 0.39 0.46 Diluted - Continuing Operations 0.34 0.66 0.27 0.01 (2.39 ) 0.68 0.49 0.57 Diluted - Discontinued Operations (Note 3) (0.09 ) (1.68 ) 0.01 2.53 (3.23 ) 0.21 (0.10 ) (0.11 ) Diluted - Net Income (Loss) Attributable to Common Shareholders 0.25 (1.02 ) 0.28 2.54 (5.62 ) 0.89 0.39 0.46 (1) Net of income taxes (2) The sum of quarterly income allocated to preferred shareholders may not equal annual income allocated to preferred shareholders as quarter-to-date and year-to-date amounts are calculated independently. (3) The sum of quarterly earnings per share information may not equal annual earnings per share due to the issuance of shares and conversion of preferred shares throughout the year. See FirstEnergy's Consolidated Statements of Stockholders' Equity and Note 6, "Stock-Based Compensation Plans," for additional information. (4) Prior year numbers have been re-casted for discontinued operations.

Organization and Basis of Pre_3

Organization and Basis of Presentation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Regulatory assets on the Balance Sheets
Regulatory Assets	$ 91	$ 40
Regulatory Liability	(2,498)	(2,720)
Net Regulatory Liabilities included on the Consolidated Balance Sheets	(2,407)	(2,680)
Change	273
Regulatory transition costs
Regulatory assets on the Balance Sheets
Regulatory Assets	49	46
Change	3
Customer payables for future income taxes
Regulatory assets on the Balance Sheets
Regulatory Assets	(2,725)	(2,765)
Change	40
Nuclear decommissioning and spent fuel disposal costs
Regulatory assets on the Balance Sheets
Regulatory Liability	(148)	(323)
Change	175
Asset removal costs
Regulatory assets on the Balance Sheets
Regulatory Liability	(787)	(774)
Change	(13)
Deferred transmission costs
Regulatory assets on the Balance Sheets
Regulatory Assets	170	187
Change	(17)
Deferred generation costs
Regulatory assets on the Balance Sheets
Regulatory Assets	202	198
Change	4
Deferred distribution costs
Regulatory assets on the Balance Sheets
Regulatory Assets	208	258
Change	(50)
Contract valuations
Regulatory assets on the Balance Sheets
Regulatory Assets	62	118
Change	(56)
Storm-related costs
Regulatory assets on the Balance Sheets
Regulatory Assets	500	329
Change	171
Other
Regulatory assets on the Balance Sheets
Regulatory Assets	62	$ 46
Change	$ 16

Organization and Basis of Pre_4

Organization and Basis of Presentation (Details 1) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Receivables from customers
Customers	$ 1,221	$ 1,282
Billed
Receivables from customers
Customers	686	754
Unbilled
Receivables from customers
Customers	$ 535	$ 528

Organization and Basis of Pre_5

Organization and Basis of Presentation (Details 2) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	Jan. 31, 2018	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Amount of beneficial conversion	$ 296									$ 296	$ 0	$ 0
EPS of Common Stock
Income (loss) from continuing operations		$ 182	$ 387	$ 288	$ 165	$ (1,061)	$ 301	$ 220	$ 251	1,022	(289)	551
Less: Preferred dividends										(71)	0	0
Less: Amortization of beneficial conversion feature										(296)	0	0
Less: Undistributed earnings allocated to preferred shareholders										0	0	0
Income from continuing operations available to common stockholders										655	(289)	551
Discontinued operations, net of tax										326	(1,435)	(6,728)
Less: Undistributed earnings allocated to preferred shareholders										0	0	0
Income (loss) from discontinued operations available to common stockholders										326	(1,435)	(6,728)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS		$ 128	$ (512)	$ 134	$ 1,213	$ (2,499)	$ 396	$ 174	$ 205	$ 981	$ (1,724)	$ (6,177)
Share Count information:
Weighted average number of basic shares outstanding (in shares)										492	444	426
Assumed exercise of dilutive stock options and awards (in shares)										2	0	0
Weighted average number of diluted shares outstanding										494	444	426
Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic (in dollars per share)		$ 0.34	$ 0.66	$ 0.27	$ 0.01	$ (2.39)	$ 0.68	$ 0.49	$ 0.57	$ 1.33	$ (0.65)	$ 1.29
Discontinued operations, basic (in dollars per share)		(0.09)	(1.68)	0.01	2.54	(3.23)	0.21	(0.10)	(0.11)	0.66	(3.23)	(15.78)
Basic - Net Income (Loss) Attributable to Common Stockholders, in dollars per share		0.25	(1.02)	0.28	2.55	(5.62)	0.89	0.39	0.46	1.99	(3.88)	(14.49)
Income from continuing operations, diluted (in dollars per share)		0.34	0.66	0.27	0.01	(2.39)	0.68	0.49	0.57	1.33	(0.65)	1.29
Discontinued operations, diluted (in dollars per share)		(0.09)	(1.68)	0.01	2.53	(3.23)	0.21	(0.10)	(0.11)	0.66	(3.23)	(15.78)
Diluted - Net Income (Loss) Attributable to Common Stockholders, in dollars per share		$ 0.25	$ (1.02)	$ 0.28	$ 2.54	$ (5.62)	$ 0.89	$ 0.39	$ 0.46	$ 1.99	$ (3.88)	$ (14.49)
Stock Options
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from the calculation of diluted shares outstanding, in shares										1	3	3
Preferred Stock
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Shares excluded from the calculation of diluted shares outstanding, in shares										26

Organization and Basis of Pre_6

Organization and Basis of Presentation (Details 3) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment
In Service	$ 39,469	$ 37,113
Accumulated Depreciation	(10,793)	(10,011)
Property, plant and equipment in service net of accumulated provision for depreciation	28,676	27,102
Construction Work in Progress	1,235	999
Total net property, plant and equipment	29,911	28,101
Capital leased assets	173	190
Regulated Distribution
Property, Plant and Equipment
In Service	27,520	25,950
Accumulated Depreciation	(8,132)	(7,503)
Property, plant and equipment in service net of accumulated provision for depreciation	19,388	18,447
Construction Work in Progress	628	469
Total net property, plant and equipment	20,016	18,916
Regulated Transmission
Property, Plant and Equipment
In Service	11,041	10,102
Accumulated Depreciation	(2,210)	(2,055)
Property, plant and equipment in service net of accumulated provision for depreciation	8,831	8,047
Construction Work in Progress	545	480
Total net property, plant and equipment	9,376	8,527
Corporate/Other
Property, Plant and Equipment
In Service	908	1,061
Accumulated Depreciation	(451)	(453)
Property, plant and equipment in service net of accumulated provision for depreciation	457	608
Construction Work in Progress	62	50
Total net property, plant and equipment	$ 519	$ 658

Organization and Basis of Pre_7

Organization and Basis of Presentation (Details 4) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 5,618	$ 5,618	$ 5,618
Regulated Distribution
Goodwill [Line Items]
Goodwill	5,004
Regulated Transmission
Goodwill [Line Items]
Goodwill	$ 614

Organization and Basis of Pre_8

Organization and Basis of Presentation (Details Textuals) mi² in Thousands, customer in Millions	Jan. 01, 2019USD ($)	Feb. 18, 2018USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2016USD ($)	Dec. 31, 2018USD ($)mi²transmission_centercompanyMW	Dec. 31, 2018USD ($)mi²customertransmission_centercompanyMW	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Sep. 26, 2018USD ($)	Mar. 31, 2018USD ($)	Jan. 01, 2018USD ($)	Aug. 31, 2017MW	Mar. 06, 2017MW
Regulatory Assets [Line Items]
Number of regional transmission centers | transmission_center							2	2
Amount paid to settle claims											$ 225,000,000
Regulatory assets that do not earn a current return				$ 223,000,000			$ 503,000,000	$ 503,000,000	$ 223,000,000
Regulatory assets based on prior precedent or anticipated recovery based on rate making premises with specific order							141,000,000	$ 141,000,000
Annual Composite Depreciation Rate (percent)								2.60%	2.40%	2.30%
Capitalized financing costs								$ 46,000,000	$ 35,000,000	$ 37,000,000
Interest costs capitalized								19,000,000	17,000,000	18,000,000
Property, plant and equipment				28,101,000,000			$ 29,911,000,000	29,911,000,000	28,101,000,000
Impairments of long-lived assets								0	2,399,000,000	10,665,000,000
Share-based compensation accounting change				(6,000,000)					(6,000,000)
Net cash used for financing activities								1,394,000,000	(702,000,000)	(34,000,000)
Impact of adopting new accounting pronouncements								$ 35,000,000
Regulated Distribution
Regulatory Assets [Line Items]
Number of existing utility operating companies | company							10	10
Number of customers served by utility operating companies | customer								6
Service Area | mi²							65	65
Plant generation capacity (in MW's) | MW							3,790	3,790
Property, plant and equipment, net							$ 2,000,000,000	$ 2,000,000,000
Property, plant and equipment				18,916,000,000			$ 20,016,000,000	$ 20,016,000,000	18,916,000,000
Regulated Transmission
Regulatory Assets [Line Items]
Service Area | mi²							25	25
Property, plant and equipment				8,527,000,000			$ 9,376,000,000	$ 9,376,000,000	8,527,000,000
Bath County, Virginia
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW							3,003	3,003
MAIT
Regulatory Assets [Line Items]
Impairments of long-lived assets					$ 13,000,000
AE Supply
Regulatory Assets [Line Items]
Amount of damages awarded to other party		$ 93,000,000
Virginia Electric and Power Company | Bath County, Virginia
Regulatory Assets [Line Items]
Proportionate ownership share (percent)							60.00%	60.00%
AGC | Bath County, Virginia
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW							487	487
Proportionate ownership share (percent)							16.00%	16.00%
Property, plant and equipment							$ 188,000,000	$ 188,000,000
OVEC | AE Supply
Regulatory Assets [Line Items]
Impairments of long-lived assets										43,000,000
Connecting Transmission Facilities | AGC | Bath County, Virginia
Regulatory Assets [Line Items]
Proportionate ownership share (percent)							40.00%	40.00%
Pleasants Power Station
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW															1,300
Purchase Agreement with Subsidiary of LS Power
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW														1,615
Purchase Agreement with Subsidiary of LS Power | Pleasants Power Station | AE Supply
Regulatory Assets [Line Items]
Plant generation capacity (in MW's) | MW							1,300	1,300
Utilization of Accelerated Useful Life
Regulatory Assets [Line Items]
Out-of period adjustment						$ 21,000,000			19,000,000
Accounting Standards Update 2016-09
Regulatory Assets [Line Items]
Net cash used for financing activities									8,000,000
Accounting Standards Update 2016-02 | Forecast | Operating Lease Assets
Regulatory Assets [Line Items]
Impact of adopting new accounting pronouncements	$ 190
Accounting Standards Update 2016-02 | Forecast | Operating Lease Obligations
Regulatory Assets [Line Items]
Impact of adopting new accounting pronouncements	$ 190
Retained Earnings (Accumulated Deficit)
Regulatory Assets [Line Items]
Share-based compensation accounting change				(6,000,000)					(6,000,000)
Impact of adopting new accounting pronouncements								$ 35,000,000
Retained Earnings (Accumulated Deficit) | Accounting Standards Update 2016-09
Regulatory Assets [Line Items]
Share-based compensation accounting change				22,000,000					22,000,000
Retained Earnings (Accumulated Deficit) | Accounting Standards Update 2016-01
Regulatory Assets [Line Items]
Share-based compensation accounting change													$ 57,000,000
Other Nonoperating Income (Expense) | Accounting Standards Update 2017-07
Regulatory Assets [Line Items]
Reclassification of non-service costs									27,000,000	6,000,000
Other Operating Income (Expense) | Accounting Standards Update 2017-07
Regulatory Assets [Line Items]
Reclassification of non-service costs									$ (27,000,000)	$ (6,000,000)
Line of Credit | Secured Credit Facility | FES
Regulatory Assets [Line Items]
Maximum amount borrowed under revolving credit facility											500,000,000
Line of Credit | Credit Agreement | FES
Regulatory Assets [Line Items]
Maximum amount borrowed under revolving credit facility											200,000,000
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Regulatory Assets [Line Items]
Investments in subsidiaries												$ 0
Amount of damages awarded to other party								66,000,000
Income taxes paid								$ 52,000,000
Loss from discontinued operations			$ 877,000,000
Intercompany Income Tax Allocation Agreement | Loans Payable | FES
Regulatory Assets [Line Items]
Face amount of loan											628,000,000
McElroy's Run Impoundment Site | Pleasants Power Station
Regulatory Assets [Line Items]
Increase in asset retirement obligation			43,000,000
Regulation of Waste Disposal | McElroy's Run Impoundment Site | Pleasants Power Station | AE Supply
Regulatory Assets [Line Items]
Increase in asset retirement obligation			$ 43,000,000
Affiliated companies | Services Agreements | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC | FES
Regulatory Assets [Line Items]
Amounts of transaction							$ 112,500,000
2017 | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Regulatory Assets [Line Items]
Overpayment of NOL's reversed											71,000,000
2018 | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Regulatory Assets [Line Items]
Overpayment of NOL's reversed											$ 88,000,000
FERC | JCP&L
Regulatory Assets [Line Items]
Impairments of long-lived assets				$ 28,000,000

Discontinued Operations - Narra

Discontinued Operations - Narrative (Details) $ in Millions

May 03, 2018USD ($)

Apr. 06, 2018USD ($)

Mar. 16, 2018USD ($)

Mar. 09, 2018USD ($)MW

Feb. 18, 2018USD ($)

Aug. 31, 2017Natural_gas_plantMW

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2018USD ($)MW

Dec. 31, 2018USD ($)MW

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)

May 11, 2018USD ($)

Mar. 06, 2017MW

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Short-term borrowings

$ 300

$ 1,250

$ 1,250

$ 300

Interest expense

$ 1,116

1,005

$ 973

Purchase Agreement with Subsidiary of LS Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Plant generation capacity (in MW's) | MW

1,615

AE Supply

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amount of damages awarded to other party

$ 93

AE Supply | Purchase Agreement with Subsidiary of LS Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Number of gas generating plants | Natural_gas_plant

4

Make-whole premiums

$ 89

AGC | Purchase Agreement with Subsidiary of LS Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Ownership percentage

59.00%

59.00%

Pleasants Power Station

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Plant generation capacity (in MW's) | MW

1,300

Pleasants Power Station | AE Supply | Purchase Agreement with Subsidiary of LS Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Plant generation capacity (in MW's) | MW

1,300

1,300

Bay Shore Unit 1 | Asset Purchase Agreement with Walleye Energy, LLC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Plant capacity (in MW's) | MW

136

Promissory Notes | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Interest expense

$ 24

Promissory Notes | AE Supply | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Outstanding borrowings

$ 102

$ 102

PCRB | AE Supply | Purchase Agreement with Subsidiary of LS Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Long-term debt and other long-term obligations

$ 142

Senior Notes | Ae Supply and Allegheny Generating Company [Member] | Purchase Agreement with Subsidiary of LS Power

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Long-term debt and other long-term obligations

$ 405

Revolving Credit Facility | Line of Credit | FES

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Line of credit outstanding

$ 500

$ 500

500

Loan reserves

500

Money Pool | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amount added to debt

88

Short-term borrowings

$ 92

Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Investments in subsidiaries

0

Gain on deconsolidation, net of tax

435

0

0

Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP)

(820)

820

Settlement payments

$ 72

Amount of damages awarded to other party

66

Income taxes paid

52

Worthless stock deduction

4,800

Worthless stock deduction, net of tax

1,000

Tax consequence of outside basis difference

418

418

Nondeductible portion of interest expense

60

27

Tax benefit from excess deferred tax liabilities

$ 32

Impairment of assets

0

2,358

$ 10,622

Discontinued Operations, Disposed of by Means Other than Sale | Competitive Asset Generation Sale

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Impairment of assets

$ 193

Discontinued Operations, Disposed of by Means Other than Sale | Pleasants Power Station | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Impairment of assets

$ 120

Other Current Liabilities | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Indemnification obligation

$ 58

Service Agreements and Beyond | Affiliated companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amounts of transaction

169

Services Agreements | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amount repaid

1

Services Agreements | Affiliated companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Amounts of transaction

112.5

Power Purchase Agreements | Affiliated companies | Discontinued Operations, Disposed of by Means Other than Sale | FES | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Due from related parties

27

27

Purchases from related party

318

Tax Allocation Agreement | Affiliated companies | Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Due from related parties

$ 88

$ 88

FE | Promissory Notes | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Loan reserves

102

FE | Unregulated Money Pool [Member] | FES and FENOC

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Loan reserves

$ 92

Revenue (Details)

Revenue (Details) $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018USD ($)companyMW

Sep. 30, 2018USD ($)

Jun. 30, 2018USD ($)

Mar. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Sep. 30, 2017USD ($)

Jun. 30, 2017USD ($)

Mar. 31, 2017USD ($)

Dec. 31, 2018USD ($)companyMW

Dec. 31, 2017USD ($)

[1]

Dec. 31, 2016USD ($)

[1]

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

$ 10,944

ARP

254

Other

63

Total revenues

$ 2,710

$ 3,064

$ 2,625

$ 2,862

$ 2,681

$ 2,910

$ 2,561

$ 2,776

$ 11,261

[1]

$ 10,928

$ 10,700

Utility customer payment period

30 days

Other Non-Customer Revenue

Disaggregation of Revenue [Line Items]

Late payment charges

$ 39

Distribution services

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

5,055

Retail generation

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

3,882

Wholesale sales

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

524

Transmission

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

1,335

Other

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

148

Derivative Revenue | Other Non-Customer Revenue

Disaggregation of Revenue [Line Items]

Total revenues

18

Regulated Distribution

Disaggregation of Revenue [Line Items]

Reduction in revenue

$ 131

Number of existing utility operating companies | company

10

10

Megawatts of net demonstrated capacity of competitive segment (in MW's) | MW

3,790

3,790

Regulated Distribution | Retail generation

Disaggregation of Revenue [Line Items]

Total revenues

$ 9,095

Regulated Distribution | Retail generation | Residential

Disaggregation of Revenue [Line Items]

Total revenues

5,598

Regulated Distribution | Retail generation | Commercial

Disaggregation of Revenue [Line Items]

Total revenues

2,350

Regulated Distribution | Retail generation | Industrial

Disaggregation of Revenue [Line Items]

Total revenues

1,056

Regulated Distribution | Retail generation | Other

Disaggregation of Revenue [Line Items]

Total revenues

91

Regulated Transmission

Disaggregation of Revenue [Line Items]

Total revenues

1,335

Reduction in revenue

16

Regulated Transmission | JCP&L | FERC

Disaggregation of Revenue [Line Items]

Annual revenue requirement

155

Regulated Transmission | ATSI

Disaggregation of Revenue [Line Items]

Total revenues

664

Regulated Transmission | TrAIL

Disaggregation of Revenue [Line Items]

Total revenues

237

Regulated Transmission | MAIT

Disaggregation of Revenue [Line Items]

Total revenues

150

Regulated Transmission | Other

Disaggregation of Revenue [Line Items]

Total revenues

284

Operating Segments | Customer

Disaggregation of Revenue [Line Items]

Reduction in revenue

147

Operating Segments | Regulated Distribution

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

9,741

ARP

254

Other

108

Total revenues

10,103

Operating Segments | Regulated Distribution | Distribution services

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

5,159

Operating Segments | Regulated Distribution | Retail generation

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

3,936

Operating Segments | Regulated Distribution | Wholesale sales

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

502

Operating Segments | Regulated Distribution | Transmission

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

0

Operating Segments | Regulated Distribution | Other

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

144

Operating Segments | Regulated Transmission

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

1,335

ARP

0

Other

18

Total revenues

1,353

Operating Segments | Regulated Transmission | Distribution services

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

0

Operating Segments | Regulated Transmission | Retail generation

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

0

Operating Segments | Regulated Transmission | Wholesale sales

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

0

Operating Segments | Regulated Transmission | Transmission

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

1,335

Operating Segments | Regulated Transmission | Other

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

Reconciling Adjustments

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

(132)

ARP

0

Other

(63)

Total revenues

(195)

Reconciling Adjustments | Distribution services

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

(104)

Reconciling Adjustments | Retail generation

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

(54)

Reconciling Adjustments | Wholesale sales

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

22

Reconciling Adjustments | Transmission

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

0

Reconciling Adjustments | Other

Disaggregation of Revenue [Line Items]

Total revenues from contracts with customers

$ 4

[1]

Includes excise and gross receipts tax collections of $386 million, $370 million and $378 million in 2018, 2017 and 2016, respectively.

Discontinued Operations - Summa

Discontinued Operations - Summarized Results of Discontinued Operations (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Income tax expense (benefit)									$ 1,251	$ 820	$ 3,582
Discontinued operations (Note 3)	$ (44)	$ (845)	$ 11	$ 1,204	$ (1,438)	$ 95	$ (46)	$ (46)
Income (loss) from discontinued operations									326	(1,435)	(6,728)
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									989	3,055	3,794
Fuel									(304)	(879)	(1,073)
Purchased power									(84)	(268)	(533)
Other operating expenses									(435)	(1,499)	(1,263)
Provision for depreciation									(96)	(109)	(378)
General taxes									(35)	(103)	(129)
Impairment of assets									0	(2,358)	(10,622)
Other expense, net									(83)	(94)	(106)
Income (Loss) from discontinued operations, before tax									(48)	(2,255)	(10,310)
Income tax expense (benefit)									61	(820)	(3,582)
Discontinued operations (Note 3)									(109)	(1,435)	(6,728)
Gain on deconsolidation, net of tax									435	0	0
Income (loss) from discontinued operations									326	(1,435)	$ (6,728)
Tax benefit from excess deferred tax liabilities			$ 32
Nondeductible portion of interest expense									$ 60	27
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | Pleasants Power Station
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of assets					$ (120)
Competitive Asset Generation Sale | Discontinued Operations, Disposed of by Means Other than Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Impairment of assets										$ (193)

Discontinued Operations - Gain

Discontinued Operations - Gain on Deconsolidation (Details) - FES and FENOC - Discontinued Operations, Disposed of by Means Other than Sale - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Removal of investment in FES and FENOC		$ 2,193
Assumption of benefit obligations retained at FE	$ 820	(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		(1,197)
Loss on disposal of FES and FENOC, before tax		(877)
Income tax benefit, including estimated worthless stock deduction		1,312
Gain on disposal of FES and FENOC, net of tax		$ 435	$ 0	$ 0

Discontinued Operations - Major

Discontinued Operations - Major Classes of Assets and Liabilities as Discontinued Operations (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets	$ 25	$ 632
Property, plant and equipment	0	1,132
Total current liabilities	0	978
Total noncurrent liabilities	0	3,528
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]
Cash	0	1
Restricted cash	0	3
Receivables	0	202
Materials and supplies	25	227
Other current assets	0	199
Total current assets	25	632
Property, plant and equipment	0	1,132
Investments	0	1,875
Other non-current assets	0	356
Total non-current assets	0	3,363
Total assets included in discontinued operations	25	3,995
Currently payable long-term debt	0	524
Accounts payable	0	200
Accrued taxes	0	38
Accrued compensation and benefits	0	79
Other current liabilities	0	137
Total current liabilities	0	978
Long-term debt and other long-term obligations	0	2,428
Accumulated deferred income taxes	0	(1,812)
Asset retirement obligations	0	1,945
Deferred gain on sale and leaseback transaction	0	723
Other non-current liabilities	0	244
Total noncurrent liabilities	0	3,528
Total liabilities included in discontinued operations	$ 0	$ 4,506

Discontinued Operations - Maj_2

Discontinued Operations - Major Classes of Cash Flow Items from Discontinued Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	$ 326	$ (1,435)	$ (6,728)
Gain on disposal, net of tax (Note 3)	(435)	0	0
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	1,384	1,700	1,974
Deferred income taxes and investment tax credits, net	485	839	(3,063)
Unrealized (gain) loss on derivative transactions	(5)	81	9
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(2,675)	(2,587)	(2,835)
Nuclear fuel	0	(254)	(232)
Sales of investment securities held in trusts	909	2,170	1,678
Purchases of investment securities held in trusts	(963)	(2,268)	(1,789)
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
CASH FLOWS FROM OPERATING ACTIVITIES:
Income (loss) from discontinued operations	326	(1,435)	(6,728)
Gain on disposal, net of tax (Note 3)	435	0	0
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	110	333	669
Deferred income taxes and investment tax credits, net	61	(842)	(3,582)
Unrealized (gain) loss on derivative transactions	(10)	81	9
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27)	(317)	(615)
Nuclear fuel	0	(254)	(232)
Sales of investment securities held in trusts	109	940	717
Purchases of investment securities held in trusts	$ (122)	$ (999)	$ (783)

Accumulated Other Comprehensi_3

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	$ 3,925	$ 6,241	$ 12,421
Other comprehensive income (loss)	(168)	(53)	4
Income taxes (benefits) on other comprehensive income (loss)	(67)	(21)	1
Other comprehensive income (loss), net of tax	(101)	(32)	3
Ending Balance	6,814	3,925	6,241
Accumulated Other Comprehensive Income
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	142	174	171
Other comprehensive income before reclassifications	(106)	74	119
Amounts reclassified from AOCI	(67)	(127)	(115)
Deconsolidation of FES and FENOC	5
Other comprehensive income (loss)	(168)	(53)	4
Income taxes (benefits) on other comprehensive income (loss)	(67)	(21)	1
Other comprehensive income (loss), net of tax	(101)	(32)	3
Ending Balance	41	142	174
Gains & Losses on Cash Flow Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	(22)	(28)	(33)
Other comprehensive income before reclassifications	0	0	0
Amounts reclassified from AOCI	8	10	8
Deconsolidation of FES and FENOC	13
Other comprehensive income (loss)	21	10	8
Income taxes (benefits) on other comprehensive income (loss)	10	4	3
Other comprehensive income (loss), net of tax	11	6	5
Ending Balance	(11)	(22)	(28)
Unrealized Gains on AFS Securities
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	67	52	18
Other comprehensive income before reclassifications	(97)	85	106
Amounts reclassified from AOCI	(1)	(63)	(51)
Deconsolidation of FES and FENOC	(8)
Other comprehensive income (loss)	(106)	22	55
Income taxes (benefits) on other comprehensive income (loss)	(39)	7	21
Other comprehensive income (loss), net of tax	(67)	15	34
Ending Balance	0	67	52
Defined Benefit Pension & OPEB Plans
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	97	150	186
Other comprehensive income before reclassifications	(9)	(11)	13
Amounts reclassified from AOCI	(74)	(74)	(72)
Deconsolidation of FES and FENOC	0
Other comprehensive income (loss)	(83)	(85)	(59)
Income taxes (benefits) on other comprehensive income (loss)	(38)	(32)	(23)
Other comprehensive income (loss), net of tax	(45)	(53)	(36)
Ending Balance	$ 52	$ 97	$ 150

Accumulated Other Comprehensi_4

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses	$ (770)	$ (739)	$ (684)	$ (940)	$ (803)	$ (651)	$ (657)	$ (650)	$ (3,133)	$ (2,761)	$ (2,579)
Interest expense - other									(1,116)	(1,005)	(973)
Total before taxes									1,512	1,426	1,078
Income taxes (benefits)	13	(133)	(121)	(249)	(1,232)	(202)	(132)	(149)	(490)	(1,715)	(527)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS	$ 128	$ (512)	$ 134	$ 1,213	$ (2,499)	$ 396	$ 174	$ 205	981	(1,724)	(6,177)
Reclassifications from AOCI | Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Total before taxes									8	10	8
Income taxes (benefits)									(2)	(4)	(3)
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS									6	6	5
Reclassifications from AOCI | Gains & losses on cash flow hedges | Commodity contracts
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Other operating expenses									1	2	0
Reclassifications from AOCI | Gains & losses on cash flow hedges | Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense - other									7	8	8
Reclassifications from AOCI | Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Investment income									(1)	(40)	(32)
Reclassifications from AOCI | Defined benefit pension and OPEB plans
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Prior-service costs									(74)	(74)	(72)
Income taxes (benefits)									19	28	27
NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS									$ (55)	$ (46)	$ (45)

Stock-Based Compensation Plan_2

Stock-Based Compensation Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	$ 143	$ 98	$ 105
Stock-based compensation costs capitalized	60	37	37
Incentive Plans | Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	102	49	62
Incentive Plans | Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	1	1	2
Incentive Plans | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	0	0	(3)
401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	33	42	39
EDCP & DCPD
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation costs	$ 7	$ 6	$ 5

Stock-Based Compensation Plan_3

Stock-Based Compensation Plans (Details 1) - Restricted Stock Units (RSUs) - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Shares (in millions)
Nonvested, Beginning balance (shares)	3,300
Granted (shares)	2,000
Forfeited (shares)	(100)
Vested (shares)	(1,900)
Nonvested, Ending balance (shares)	3,300	3,300
Weighted-Average Grant Date Fair Value (per share)
Beginning balance (in dollars per share)	$ 33.24
Granted (in dollars per share)	36.78	$ 31.71	$ 34.77
Forfeited (in dollars per share)	33.77
Vested (in dollars per share)	32.49
Ending balance (in dollars per share)	$ 33.78	$ 33.24
Dividend shares earned during period, number of shares	143

Stock-Based Compensation Plan_4

Stock-Based Compensation Plans (Details 2) shares in Millions	12 Months Ended
	Dec. 31, 2018$ / sharesshares
Number of Shares (in millions)
Beginning option balance (shares) | shares	1.4
Options exercised (in shares) | shares	(0.3)
Options forfeited (in shares) | shares	(0.3)
Ending option balance (shares) | shares	0.8
Weighted Average Exercise Price (per share)
Beginning balance (in dollars per share) | $ / shares	$ 44.41
Options exercised (in dollars per share) | $ / shares	35.45
Options forfeited (in dollars per share) | $ / shares	79.99
Ending balance (in dollars per share) | $ / shares	$ 37.37

Stock-Based Compensation Plan_5

Stock-Based Compensation Plans (Details Textuals) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	3 years
Realized tax benefits	$ 15,000,000	$ 15,000,000	$ 13,000,000
Tax benefit associated with stock-based compensation expense	$ 18,000,000	10,000,000	$ 14,000,000
Stock option expiration period	10 years
Stock options granted in period (shares)	0
Cash received from stock options exercised	$ 12,000,000	0
Weighted-average remaining contractual term of options outstanding	1 year 4 months 6 days
Share-based liabilities paid		0
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	$ 9,000,000	$ 8,000,000
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%
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	3 years
Liability recognized	$ 56,000,000
Share-based compensation expense	$ 30,000,000
Granted (in dollars per share)	$ 36.78	$ 31.71	$ 34.77
Fair value of restricted stock units vested	$ 62,000,000	$ 42,000,000	$ 36,000,000
Unrecognized cost	$ 30,000,000
Unrecognized cost, period for recognition	3 years
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	3 years
Share-based liabilities paid	$ 0		$ 2,000,000
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	1 year
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation award vesting period	10 years
ICP 2,007
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Maximum limit of total stock awards (in shares)	29,000,000
Stock-based compensation award number of shares available for future	0
ICP 2,015
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	4,700,000
401(k) Savings Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance	1,260,189	1,300,000

Pension and Other Postemploym_3

Pension and Other Postemployment Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Amounts Recognized on the Balance Sheet:
Noncurrent liabilities	$ (2,906)	$ (3,975)
Pension
Change in benefit obligation:
Benefit obligation as of January 1	10,167	9,426
Service cost	224	208	$ 191
Interest cost	372	390	398
Plan participants’ contributions	0	0
Plan amendments	5	11
Special termination benefits	31	0
Medicare retiree drug subsidy	0	0
Annuity purchase	(129)	0
Actuarial (gain) loss	(710)	610
Benefits paid	(498)	(478)
Benefit obligation as of December 31	9,462	10,167	9,426
Change in fair value of plan assets:
Fair value of plan assets as of January 1	6,704	6,213
Actual return on plan assets	(363)	950
Annuity purchase	(129)	0
Company contributions	1,270	18
Plan participants’ contributions	0	0
Benefits paid	(498)	(477)
Fair value of plan assets as of December 31	6,984	6,704	6,213
Funded Status:
Funded Status	(2,478)	(3,463)
Accumulated benefit obligation	8,951	9,583
Amounts Recognized on the Balance Sheet:
Noncurrent assets	14	0
Current liabilities	(20)	(19)
Noncurrent liabilities	(2,472)	(3,444)
Net liability as of December 31	(2,478)	(3,463)
Amounts Recognized in AOCI:
Prior service cost (credit)	$ 30	$ 32
Assumptions Used to Determine Benefit Obligations
Discount rate	4.44%	3.75%
Rate of compensation increase	4.10%	4.20%
Cash balance weighted average interest crediting rate	3.34%	2.88%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.50%	4.50%
Allocation of Plan Assets
Asset Allocation	100.00%	100.00%
Pension | Equity securities
Allocation of Plan Assets
Asset Allocation	36.00%	42.00%
Pension | Bonds
Allocation of Plan Assets
Asset Allocation	34.00%	32.00%
Pension | Absolute return strategies
Allocation of Plan Assets
Asset Allocation	11.00%	10.00%
Pension | Real estate
Allocation of Plan Assets
Asset Allocation	10.00%	9.00%
Pension | Derivatives
Allocation of Plan Assets
Asset Allocation	2.00%	0.00%
Pension | Private equity funds
Allocation of Plan Assets
Asset Allocation	2.00%	1.00%
Pension | Cash and short-term securities
Allocation of Plan Assets
Asset Allocation	5.00%	6.00%
Pension | Pre Medicare
Assumptions Used to Determine Benefit Obligations
Health care cost trend rate assumed (pre/post-Medicare)	6.00%	6.00%
Pension | Post Medicare
Assumptions Used to Determine Benefit Obligations
Health care cost trend rate assumed (pre/post-Medicare)	5.50%	5.50%
Pension | Qualified plan
Funded Status:
Funded Status	$ (2,093)	$ (3,043)
Pension | Non-qualified plans
Funded Status:
Funded Status	(385)	(420)
OPEB
Change in benefit obligation:
Benefit obligation as of January 1	731	711
Service cost	5	5	5
Interest cost	25	27	30
Plan participants’ contributions	3	4
Plan amendments	5	0
Special termination benefits	8	0
Medicare retiree drug subsidy	1	1
Annuity purchase	0	0
Actuarial (gain) loss	(121)	32
Benefits paid	(49)	(49)
Benefit obligation as of December 31	608	731	711
Change in fair value of plan assets:
Fair value of plan assets as of January 1	439	420
Actual return on plan assets	(8)	49
Annuity purchase	0	0
Company contributions	22	16
Plan participants’ contributions	3	4
Benefits paid	(48)	(50)
Fair value of plan assets as of December 31	408	439	$ 420
Funded Status:
Funded Status	(200)	(292)
Accumulated benefit obligation	0	0
Amounts Recognized on the Balance Sheet:
Noncurrent assets	0	0
Current liabilities	0	0
Noncurrent liabilities	(200)	(292)
Net liability as of December 31	(200)	(292)
Amounts Recognized in AOCI:
Prior service cost (credit)	$ (121)	$ (206)
Assumptions Used to Determine Benefit Obligations
Discount rate	4.30%	3.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate)	4.50%	4.50%
Allocation of Plan Assets
Asset Allocation	100.00%	100.00%
OPEB | Equity securities
Allocation of Plan Assets
Asset Allocation	48.00%	50.00%
OPEB | Bonds
Allocation of Plan Assets
Asset Allocation	35.00%	33.00%
OPEB | Absolute return strategies
Allocation of Plan Assets
Asset Allocation	0.00%	0.00%
OPEB | Real estate
Allocation of Plan Assets
Asset Allocation	0.00%	0.00%
OPEB | Derivatives
Allocation of Plan Assets
Asset Allocation	0.00%	0.00%
OPEB | Private equity funds
Allocation of Plan Assets
Asset Allocation	0.00%	0.00%
OPEB | Cash and short-term securities
Allocation of Plan Assets
Asset Allocation	17.00%	17.00%
OPEB | Pre Medicare
Assumptions Used to Determine Benefit Obligations
Health care cost trend rate assumed (pre/post-Medicare)	6.00%	6.00%
OPEB | Post Medicare
Assumptions Used to Determine Benefit Obligations
Health care cost trend rate assumed (pre/post-Medicare)	5.50%	5.50%
OPEB | Qualified plan
Funded Status:
Funded Status	$ 0	$ 0
OPEB | Non-qualified plans
Funded Status:
Funded Status	$ 0	$ 0

Taxes (Details)

Taxes (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Currently payable (receivable)-
Federal									$ (16)	$ 14	$ (1)
State									17	20	9
Currently payable (receivable) Total									1	34	8
Deferred, net-
Federal									252	1,647	317
State									243	40	208
Deferred Tax Total									495	1,687	525
Investment tax credit amortization									(6)	(6)	(6)
Total income taxes	$ (13)	$ 133	$ 121	$ 249	$ 1,232	$ 202	$ 132	$ 149	490	$ 1,715	$ 527
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Currently payable (receivable)-
State									1
Deferred, net-
Federal									1,300
State									$ 12

Pension and Other Postemploym_4

Pension and Other Postemployment Benefits (Details 1) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	$ 224	$ 208	$ 191
Interest cost	372	390	398
Expected return on plan assets	(574)	(448)	(399)
Amortization of prior service cost (credit)	7	7	8
Special termination costs	31	0	0
Pension & OPEB mark-to-market adjustment	227	108	179
Net periodic benefit cost (credit)	287	265	377
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service cost	5	5	5
Interest cost	25	27	30
Expected return on plan assets	(31)	(30)	(30)
Amortization of prior service cost (credit)	(81)	(81)	(80)
Special termination costs	8	0	0
Pension & OPEB mark-to-market adjustment	(82)	13	15
Net periodic benefit cost (credit)	$ (156)	$ (66)	$ (60)

Taxes (Details 1)

Taxes (Details 1) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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									$ 1,512	$ 1,426	$ 1,078
Federal income tax expense at statutory rate (21%, 35%, and 35% for 2018, 2017, and 2016, respectively)									318	499	377
Increases (reductions) in taxes resulting from-
State income taxes, net of federal tax benefit									90	40	16
AFUDC equity and other flow-through									(31)	(15)	(13)
Amortization of investment tax credits									(5)	(6)	(6)
ESOP dividend									(3)	(5)	(4)
Remeasurement of deferred taxes									24	1,193	0
WV unitary group remeasurement									126	0	0
Excess deferred tax amortization due to the Tax Act									(60)	0	0
Uncertain tax positions									2	(3)	(8)
Valuation allowances									21	11	160
Other, net									8	1	5
Total income taxes	$ (13)	$ 133	$ 121	$ 249	$ 1,232	$ 202	$ 132	$ 149	$ 490	$ 1,715	$ 527
Effective income tax rate (percent)									32.40%	120.30%	49.00%

Pension and Other Postemploym_5

Pension and Other Postemployment Benefits (Details 2)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate	3.75%	4.25%	4.50%
Expected long-term return on plan assets	7.50%	7.50%	7.50%
Rate of compensation increase	4.20%	4.20%	4.20%
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Weighted-average discount rate	3.50%	4.00%	4.25%
Expected long-term return on plan assets	7.50%	7.50%	7.50%

Taxes (Details 2)

Taxes (Details 2) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Accumulated deferred income taxes
Property basis differences	$ 4,737	$ 4,354
Pension and OPEB	(629)	(708)
TMI-2 nuclear decommissioning	82	37
AROs	(215)	(157)
Regulatory asset/liability	414	416
Deferred compensation	(170)	(149)
Estimated worthless stock deduction	(1,004)	0
Loss carryforwards and AMT credits	(899)	(863)
Valuation reserve	394	312
All other	(208)	(71)
Net deferred income tax liability	$ 2,502	$ 3,171

Pension and Other Postemploym_6

Pension and Other Postemployment Benefits (Details 3) - Pension - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 6,916	$ 6,714
Asset Allocation	100.00%	100.00%
Investments Excluding in Investments at NAV [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 6,665	$ 6,657
Asset Allocation	96.00%	99.00%
Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 342	$ 379
Asset Allocation	5.00%	6.00%
Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 845	$ 722
Asset Allocation	12.00%	11.00%
International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,624	$ 2,083
Asset Allocation	22.00%	31.00%
Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 59	$ 251
Asset Allocation	1.00%	4.00%
Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,674	$ 1,237
Asset Allocation	23.00%	18.00%
High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 667	$ 689
Asset Allocation	10.00%	10.00%
Mortgage-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value		$ 31
Asset Allocation		0.00%
Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 681	$ 635
Asset Allocation	11.00%	10.00%
Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 108	$ (1)
Asset Allocation	2.00%	0.00%
Real Estate Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 665	$ 631
Asset Allocation	10.00%	9.00%
Private Equity Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative investments measured at fair value	$ 143	$ 57
Asset Allocation	2.00%	1.00%
Investment-linked securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Alternative investments measured at fair value	$ 108
Asset Allocation	2.00%
Level 1 | Investments Excluding in Investments at NAV [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 1,223	$ 1,209
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
Level 1 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	723	695
Level 1 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	392	514
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
Level 1 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
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
Level 1 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	108	0
Level 1 | Real Estate Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 2 | Investments Excluding in Investments at NAV [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	4,777	4,817
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	342	379
Level 2 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	122	27
Level 2 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1,232	1,569
Level 2 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	59	251
Level 2 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	1,674	1,237
Level 2 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	667	689
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		31
Level 2 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	681	635
Level 2 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	(1)
Level 2 | Real Estate Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Investments Excluding in Investments at NAV [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	665	631
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
Level 3 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | International
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
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
Level 3 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | High yield debt
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
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
Level 3 | Hedge funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Derivatives
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Real Estate Funds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 665	$ 631	$ 615

Taxes (Details 3)

Taxes (Details 3) $ in Millions	Dec. 31, 2018USD ($)
State
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	$ 6,038
State | 2019-2023
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,583
State | 2024-2028
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,526
State | 2029-2033
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,862
State | 2034-2038
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,067
Local
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,581
Local | 2019-2023
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	1,581
Local | 2024-2028
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local | 2029-2033
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	0
Local | 2034-2038
Pre-tax net operating loss expiration period
Pre-tax net operating loss carryforwards for state and local income tax purposes	$ 0

Pension and Other Postemploym_7

Pension and Other Postemployment Benefits (Details 4) - Pension - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Reconciliation of changes in the fair value of pension investments
Beginning balance	$ 6,714
Actual return on plan assets:
Ending balance	6,916	$ 6,714
Real Estate Funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	631
Actual return on plan assets:
Ending balance	665	631
Level 3 | Real Estate Funds
Reconciliation of changes in the fair value of pension investments
Beginning balance	631	615
Actual return on plan assets:
Unrealized gains	102	3
Realized gains (losses)	(65)	10
Transfers in (out)	(3)	3
Ending balance	$ 665	$ 631

Taxes (Details 4)

Taxes (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Changes in unrecognized tax benefits
Beginning balance	$ 80	$ 84	$ 26
Current year increases	125	2	2
Prior years increases			69
Prior years decreases	(45)		(13)
Decrease for lapse in statute	(2)	(6)
Ending balance	$ 158	$ 80	$ 84

Pension and Other Postemploym_8

Pension and Other Postemployment Benefits (Details 5) - OPEB - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 410	$ 441
Asset Allocation	100.00%	100.00%
Cash and short-term securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 71	$ 75
Asset Allocation	17.00%	17.00%
Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 196	$ 220
Asset Allocation	48.00%	50.00%
Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 107	$ 109
Asset Allocation	26.00%	24.00%
Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 32	$ 34
Asset Allocation	8.00%	8.00%
Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 4	$ 3
Asset Allocation	1.00%	1.00%
Level 1
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	$ 196	$ 220
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
Level 1 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	196	220
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
Level 1 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 1 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value
Level 2
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	214	221
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	71	75
Level 2 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 2 | Government bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	107	109
Level 2 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	32	34
Level 2 | Mortgaged-backed securities (non-government)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	4	3
Level 3
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
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
Level 3 | Domestic
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
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
Level 3 | Corporate bonds
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension investments measured at fair value	0	0
Level 3 | Mortgaged-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

Taxes (Details 5)

Taxes (Details 5) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
General Taxes
KWH excise	$ 198	$ 188	$ 196
State gross receipts	192	184	184
Real and personal property	478	452	421
Social security and unemployment	103	96	91
Other	22	20	21
Total general taxes	$ 993	$ 940	$ 913

Pension and Other Postemploym_9

Pension and Other Postemployment Benefits (Details 6)	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	100.00%
Equities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	38.00%
Fixed income
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	30.00%
Absolute return strategies
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	8.00%
Real estate
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	10.00%
Alternative investments
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	8.00%
Cash
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target Asset Allocations, Percent	6.00%

Taxes (Details Textuals)

Taxes (Details Textuals) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes (Textuals) [Abstract]
Valuation allowances		$ 21	$ 11	$ 160
Effective income tax rate (percent)		32.40%	120.30%	49.00%
Effective income tax rate excluding effect of deferred taxes, (percent)			43.30%
Unrecognized tax benefits		$ 158	$ 80	$ 84	$ 26
Increase resulting from nondeductible interest		27
Increase in worthless stock deduction reserve		88
Unrecognized tax benefits that would impact future tax rates		142
Decrease in unrecognized tax benefits is reasonably possible	$ 45
Unrecognized tax benefits, portion expected to be resolved in the next fiscal year		6
Unrecognized tax benefits that would impact effective tax rate		2
Federal
Income Taxes (Textuals) [Abstract]
Operating loss carryforwards, not subject to expiration		18
Federal | Begin To Expire in 2031
Income Taxes (Textuals) [Abstract]
Pre-tax net operating loss carryforwards		2,400
Operating loss carryforwards, subject to expiration		493
State and Local
Income Taxes (Textuals) [Abstract]
Pre-tax net operating loss carryforwards		7,600
Operating loss carryforwards, subject to expiration		365
Pre-tax net operating loss carryforwards expected to utilized		2,000
Operating loss carryforwards expected to utilized, net of tax		100
Tax deferred expense, net of tax		59
West Virginia | State and Local
Income Taxes (Textuals) [Abstract]
Valuation allowances	$ 126
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Income Taxes (Textuals) [Abstract]
Valuation allowances		60
Nondeductible portion of interest expense		$ 60	$ 27

Pension and Other Postemploy_10

Pension and Other Postemployment Benefits (Details 7) $ in Millions	Dec. 31, 2018USD ($)
Pension
Estimated Future Benefit Payments
2,019	$ 509
2,020	533
2,021	554
2,022	566
2,023	580
2024-2028	3,047
OPEB
Estimated Future Benefit Payments
2,019	57
2,020	48
2,021	48
2,022	47
2,023	46
2024-2028	213
Subsidy Receipts
2,019	(1)
2,020	(1)
2,021	(1)
2,022	(1)
2,023	(1)
Years 2024-2028	$ (3)

Pension and Other Postemploy_11

Pension and Other Postemployment Benefits (Details Textuals) $ in Millions	Feb. 01, 2019USD ($)	Dec. 13, 2016USD ($)	Jan. 31, 2018USD ($)	Sep. 30, 2018USD ($)	Dec. 31, 2018USD ($)employee	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Increase in Discount Rate					0.69%
Mark-to-market adjustment, net of capitalized amounts					$ 145	$ 141	$ 147
Funding contributions made for current and future years			$ 750				882
Pension contributions		$ 500			1,250	0	382
Pensions and OPEB
Defined Benefit Plan Disclosure [Line Items]
Actual return on plan assets					$ (371)	$ 999	$ 472
Actual return on plan assets (percent)					(4.00%)	15.10%	8.20%
Expected return on plan assets					$ 605	$ 478	$ 429
Pension
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)					287	265	$ 377
Company contributions					1,270	18
Actual return on plan assets					$ (363)	$ 950
Expected long-term return on plan assets					7.50%	7.50%	7.50%
Expected return on plan assets					$ 574	$ 448	$ 399
Increase in benefit obligation due to RP2014 mortality table					16
Excluded from total investments					68	(10)
OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)					(156)	(66)	$ (60)
Company contributions					22	16
Actual return on plan assets					$ (8)	$ 49
Expected long-term return on plan assets					7.50%	7.50%	7.50%
Expected return on plan assets					$ 31	$ 30	$ 30
Excluded from total investments					(2)	(2)
Minimum
Defined Benefit Plan Disclosure [Line Items]
Company contributions			$ 500				382
FES
Defined Benefit Plan Disclosure [Line Items]
Pension contributions							138
Subsequent Event
Defined Benefit Plan Disclosure [Line Items]
Company contributions	$ 500
Discontinued Operations
Defined Benefit Plan Disclosure [Line Items]
Mark-to-market adjustment, net of capitalized amounts					$ 1	39	$ 45
FE Tomorrow Initiative
Defined Benefit Plan Disclosure [Line Items]
Restructuring and Related Cost, Number of Positions Eliminated, Period Percent					80.00%
Restructuring and Related Cost, Number of Positions Eliminated | employee					500
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plan Disclosure [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party				$ 42
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | Pension
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)					$ 64	60
FES and FENOC | Discontinued Operations, Disposed of by Means Other than Sale | OPEB
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)					$ (25)	$ (17)

Leases (Details)

Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Leases [Abstract]
Operating leases	$ 48	$ 53	$ 62

Leases (Details 1)

Leases (Details 1) $ in Millions	Dec. 31, 2018USD ($)
Leases [Abstract]
2,019	$ 24
2,020	19
2,021	16
2,022	13
2,023	8
Years thereafter	16
Total minimum lease payments	96
Interest portion	(23)
Present value of net minimum lease payments	73
Less current portion	18
Noncurrent portion	$ 55

Leases (Details 2)

Leases (Details 2) $ in Millions	Dec. 31, 2018USD ($)
Leases [Abstract]
2,019	$ 34
2,020	36
2,021	34
2,022	30
2,023	28
Years thereafter	127
Total minimum lease payments	$ 289

Intangible Assets (Details)

Intangible Assets (Details) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross	$ 234
Intangible Assets, Accumulated Amortization	141
Intangible Assets, Net	93
Amortization Expense
Actual, 2018	8
Estimated, 2019	9
Estimated, 2020	7
Estimated, 2021	5
Estimated, 2022	5
Estimated, 2023	6
Estimated, Thereafter	61
NUG contracts
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross	124
Intangible Assets, Accumulated Amortization	41
Intangible Assets, Net	83
Amortization Expense
Actual, 2018	5
Estimated, 2019	5
Estimated, 2020	5
Estimated, 2021	5
Estimated, 2022	5
Estimated, 2023	5
Estimated, Thereafter	58
OVEC
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross	8
Intangible Assets, Accumulated Amortization	3
Intangible Assets, Net	5
Amortization Expense
Actual, 2018	0
Estimated, 2019	1
Estimated, 2020	0
Estimated, 2021	0
Estimated, 2022	0
Estimated, 2023	1
Estimated, Thereafter	3
Coal contracts
Intangible Assets (Textuals) [Abstract]
Intangible Assets, Gross	102
Intangible Assets, Accumulated Amortization	97
Intangible Assets, Net	5
Amortization Expense
Actual, 2018	3
Estimated, 2019	3
Estimated, 2020	2
Estimated, 2021	0
Estimated, 2022	0
Estimated, 2023	0
Estimated, Thereafter	$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details Textuals)	12 Months Ended
	Dec. 31, 2018USD ($)agreemententity	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2013USD ($)
Variable Interest Entities (Textuals) [Abstract]
Transition bond outstanding	$ 41,000,000	$ 56,000,000
Environmental control bonds outstanding	$ 358,000,000	383,000,000
Number of contracts that may contain variable interest | entity	1
Purchased power	$ 3,109,000,000	2,926,000,000	$ 3,310,000,000
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities | agreement	11
Path-WV
Variable Interest Entities (Textuals) [Abstract]
Equity method investments	$ 17,000,000
Percentage of high-voltage transmission line project owned by subsidiary of AE on the Allegheny Series	100.00%
Percentage of high-voltage transmission line project owned by subsidiary of AE on the West Virginia Series	50.00%
FEV
Variable Interest Entities (Textuals) [Abstract]
Equity method investments	$ 7,000,000
Other FE subsidiaries
Variable Interest Entities (Textuals) [Abstract]
Ownership interest (percent)	0.00%
Other FE subsidiaries | Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 108,000,000	112,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Aggregate annual servicing fees receivable for phase-in recovery bonds	$ 445,000
Global Holding | FEV | Signal Peak
Variable Interest Entities (Textuals) [Abstract]
Ownership interest (percent)	33.33%
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 292,000,000	$ 315,000,000
Phase In Recovery Bonds | Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Face amount of loan					$ 445,000,000
Senior Loans | Senior Secured Term Loan | Global Holding
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	190,000,000
Term Loan Facility Due March 2020 | Line of Credit | Global Holding
Variable Interest Entities (Textuals) [Abstract]
Face amount of loan	$ 300,000,000			$ 300,000,000

Fair Value Measurements (Detail

Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Assets
Fair value, assets	$ 1,438	$ 1,693
Liabilities
Fair value, liabilities	(45)	(79)
Net assets (liabilities)	1,393	1,614
FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(1)	0
NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(44)	(79)
Corporate debt securities
Assets
Fair value, assets	405	476
FTRs | Derivative Assets
Assets
Fair value, assets	10	3
Equity securities
Assets
Fair value, assets	339	297
Foreign government debt securities
Assets
Fair value, assets	13	23
U.S. government debt securities
Assets
Fair value, assets	20	21
U.S. state debt securities
Assets
Fair value, assets	250	247
Other
Assets
Fair value, assets	401	626
Level 1
Assets
Fair value, assets	706	885
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	706	885
Level 1 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 1 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 1 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 1 | Equity securities
Assets
Fair value, assets	339	297
Level 1 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 1 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 1 | Other
Assets
Fair value, assets	367	588
Level 2
Assets
Fair value, assets	722	805
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	722	805
Level 2 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	0	0
Level 2 | Corporate debt securities
Assets
Fair value, assets	405	476
Level 2 | FTRs | Derivative Assets
Assets
Fair value, assets	0	0
Level 2 | Equity securities
Assets
Fair value, assets	0	0
Level 2 | Foreign government debt securities
Assets
Fair value, assets	13	23
Level 2 | U.S. government debt securities
Assets
Fair value, assets	20	21
Level 2 | U.S. state debt securities
Assets
Fair value, assets	250	247
Level 2 | Other
Assets
Fair value, assets	34	38
Level 3
Assets
Fair value, assets	10	3
Liabilities
Fair value, liabilities	(45)	(79)
Net assets (liabilities)	(35)	(76)
Level 3 | FTRs | Derivative Liabilities
Liabilities
Fair value, liabilities	(1)	0
Level 3 | NUG contracts | Derivative Liabilities
Liabilities
Fair value, liabilities	(44)	(79)
Level 3 | Corporate debt securities
Assets
Fair value, assets	0	0
Level 3 | FTRs | Derivative Assets
Assets
Fair value, assets	10	3
Level 3 | Equity securities
Assets
Fair value, assets	0	0
Level 3 | Foreign government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. government debt securities
Assets
Fair value, assets	0	0
Level 3 | U.S. state debt securities
Assets
Fair value, assets	0	0
Level 3 | Other
Assets
Fair value, assets	$ 0	$ 0

Fair Value Measurements (Deta_2

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
NUG contracts
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	$ 0	$ 1
Beginning Balance, Derivative Liabilities	(79)	(108)
Beginning Balance, Net	(79)	(107)
Unrealized gain (loss), Derivative Assets	0	0
Unrealized gain (loss), Derivative Liabilities	2	(10)
Unrealized gain (loss), Net	2	(10)
Purchases, Derivative Assets	0	0
Purchases, Derivative Liabilities	0	0
Purchases, Net	0	0
Settlements, Derivative Assets	0	(1)
Settlements, Derivative Liabilities	33	39
Settlements, Net	33	38
Ending Balance, Derivative Assets	0	0
Ending Balance, Derivative Liabilities	(44)	(79)
Ending Balance, Net	(44)	(79)
FTRs
Reconciliation of changes in the fair value of NUG contracts
Beginning Balance, Derivative Assets	3	3
Beginning Balance, Derivative Liabilities	0	(1)
Beginning Balance, Net	3	2
Unrealized gain (loss), Derivative Assets	8	1
Unrealized gain (loss), Derivative Liabilities	1	(1)
Unrealized gain (loss), Net	9	0
Purchases, Derivative Assets	5	3
Purchases, Derivative Liabilities	(5)	0
Purchases, Net	0	3
Settlements, Derivative Assets	(6)	(4)
Settlements, Derivative Liabilities	3	2
Settlements, Net	(3)	(2)
Ending Balance, Derivative Assets	10	3
Ending Balance, Derivative Liabilities	(1)	0
Ending Balance, Net	$ 9	$ 3

Fair Value Measurements (Deta_3

Fair Value Measurements (Details 2) - Level 3 $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)MWh$ / MWh	Dec. 31, 2017USD ($)	Dec. 31, 2016USD ($)
FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ 9	$ 3	$ 2
NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	(44)	$ (79)	$ (107)
Model | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	9
Model | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value | $	$ (44)
Model | Minimum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
RTO auction clearing prices (in dollars per unit)	0.20
Model | Minimum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Power (in dollars per MWH) | MWh	400
Power, Regional prices (in dollars per unit)	31.40
Model | Maximum | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
RTO auction clearing prices (in dollars per unit)	6.10
Model | Maximum | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Power (in dollars per MWH) | MWh	1,214,000
Power, Regional prices (in dollars per unit)	33.60
Model | Weighted Average | FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
RTO auction clearing prices (in dollars per unit)	1.80
Model | Weighted Average | NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Power (in dollars per MWH) | MWh	249,000
Power, Regional prices (in dollars per unit)	32.60

Fair Value Measurements (Deta_4

Fair Value Measurements (Details 3) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Equity securities
Debt Securities, Available-for-sale [Abstract]
Cost Basis	$ 339	$ 254
Unrealized Gains	15	40
Unrealized Losses	(16)	0
Fair Value	338	294
Debt securities
Debt Securities, Available-for-sale [Line Items]
Cost Basis	714	774
Unrealized Gains	2	11
Unrealized Losses	(28)	(17)
Fair Value	$ 688	$ 768

Fair Value Measurements (Deta_5

Fair Value Measurements (Details 4) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Sale Proceeds	$ 800	$ 1,230	$ 961
Realized Gains	41	74	53
Realized Losses	(48)	(58)	(52)
OTTI	0	0	2
Interest and Dividend Income	$ 41	$ 39	$ 44

Fair Value Measurements (Deta_6

Fair Value Measurements (Details 5) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Carrying Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 18,315	$ 19,296
Fair Value
Fair value and related carrying amounts of long-term debt and other long-term obligations
Long-term debt and other long-term obligations	$ 19,266	$ 21,412

Fair Value Measurements (Deta_7

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment excludes receivables, payables and accrued income	$ 4	$ (11)
Cash balance excluded from available for sale securities	20	11
Investments not required to be disclosed	$ 253	$ 255
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

Derivative Instruments (Details

Derivative Instruments (Details Textuals) $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)agreement	Dec. 31, 2017USD ($)agreement
Derivative [Line Items]
Unamortized gains included in long term debt associated with prior fixed for floating interest rate swap agreements	$ 2	$ 3
NUGs
Derivative [Line Items]
Net liability position	44	79
Settlements	33
Unrealized gain (loss)	2
FTRs
Derivative [Line Items]
Settlements	3
Unrealized gain (loss)	9
Net asset position	9	3
Cash Flow Hedges
Derivative [Line Items]
Unamortized losses associated with prior interest rate hedges	15	$ 22
Gains (losses) to be amortized to interest expenses during next twelve months	$ (2)
Number of forward starting swap agreements accounted for as a cash flow hedge outstanding | agreement	0	0
Fair Value Hedging
Derivative [Line Items]
Number of fixed-for-floating interest rate swap agreements outstanding | agreement	0	0

Capitalization (Details)

Capitalization (Details) - $ / shares	Dec. 31, 2018	Jan. 22, 2018
Preferred stock and preference stock authorizations
Shares Authorized	5,000,000
Par Value, in dollars per share	$ 100	$ 100
Penn
Preferred stock and preference stock authorizations
Shares Authorized	1,200,000
Par Value, in dollars per share	$ 100
CEI
Preferred stock and preference stock authorizations
Shares Authorized	4,000,000
JCP&L
Preferred stock and preference stock authorizations
Shares Authorized	15,600,000
ME
Preferred stock and preference stock authorizations
Shares Authorized	10,000,000
PN
Preferred stock and preference stock authorizations
Shares Authorized	11,435,000
PE
Preferred stock and preference stock authorizations
Shares Authorized	10,000,000
Par Value, in dollars per share	$ 0.01
WP
Preferred stock and preference stock authorizations
Shares Authorized	32,000,000
Preferred Stock With Par Value $100 | OE
Preferred stock and preference stock authorizations
Shares Authorized	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	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	940,000
Par Value, in dollars per share	$ 100
Preferred Stock With Par Value $25 | OE
Preferred stock and preference stock authorizations
Shares Authorized	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	12,000,000
Par Value, in dollars per share	$ 25
Preference Stock | OE
Preferred stock and preference stock authorizations
Preference Stock Shares Authorized	8,000,000
Preference Stock | CEI
Preferred stock and preference stock authorizations
Preference Stock Shares Authorized	3,000,000
Preference Stock | TE
Preferred stock and preference stock authorizations
Preference Stock Shares Authorized	5,000,000
Preference Stock Par Value, in dollars per share	$ 25

Capitalization (Details 1)

Capitalization (Details 1) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Schedule of Capitalization [Line Items]
Capital lease obligations	$ 73	$ 89
Unamortized debt premiums (discounts)	(39)	(41)
Unamortized debt issuance costs	(95)	(99)
Unamortized fair value adjustments	10	(1)
Currently payable long-term debt	(503)	(558)
Total long-term debt and other long-term obligations	17,751	18,687
FMBs and secured notes - fixed rate
Schedule of Capitalization [Line Items]
FMBs and secured notes - fixed rate	$ 4,355	4,692
FMBs and secured notes - fixed rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	1.726%
FMBs and secured notes - fixed rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	9.74%
Unsecured notes - fixed rate
Schedule of Capitalization [Line Items]
Unsecured debt	$ 13,450	13,155
Unsecured notes - fixed rate | Minimum
Schedule of Capitalization [Line Items]
Interest rate (percent)	2.85%
Unsecured notes - fixed rate | Maximum
Schedule of Capitalization [Line Items]
Interest rate (percent)	7.70%
Unsecured notes - variable rate
Schedule of Capitalization [Line Items]
Interest rate (percent)	3.27%
Unsecured debt	$ 500	$ 1,450

Capitalization (Details 2)

Capitalization (Details 2) $ in Millions	Dec. 31, 2018USD ($)
Capitalization, Long-term Debt and Equity [Abstract]
2,019	$ 489
2,020	864
2,021	132
2,022	1,143
2,023	$ 1,194

Capitalization (Details 3)

Capitalization (Details 3) $ in Millions	Dec. 31, 2018USD ($)
Outstanding PCRBs
2,019	$ 489
2,020	864
2,021	132
2,022	1,143
2,023	1,194
PCRB
Outstanding PCRBs
2,019	0
2,020	0
2,021	74
2,022	0
2,023	$ 0

Capitalization (Details Textual

Capitalization (Details Textuals)

Nov. 09, 2018$ / shares

Nov. 02, 2018USD ($)

Oct. 15, 2018USD ($)

Jun. 15, 2018USD ($)

Jun. 11, 2018USD ($)

Jun. 04, 2018USD ($)

May 03, 2018USD ($)

Jan. 22, 2018USD ($)employeeagreement$ / sharesshares

Dec. 13, 2016USD ($)shares

Jan. 31, 2019shares

Dec. 31, 2017USD ($)$ / sharesshares

Sep. 30, 2017$ / shares

Jun. 30, 2017$ / shares

Mar. 31, 2017$ / shares

Dec. 31, 2016$ / shares

Sep. 30, 2016$ / shares

Jun. 30, 2016$ / shares

Mar. 31, 2016$ / shares

Dec. 31, 2018USD ($)subsidiary$ / sharesshares

Dec. 31, 2017USD ($)$ / sharesshares

Dec. 31, 2016USD ($)$ / sharesshares

Feb. 08, 2019USD ($)

Jan. 10, 2019USD ($)

Oct. 19, 2018USD ($)

Oct. 03, 2018USD ($)

Sep. 27, 2018USD ($)

Jul. 10, 2018USD ($)

May 10, 2018USD ($)

Jun. 30, 2013USD ($)

Debt Instrument [Line Items]

Proceeds from issuance of stock

$ 2,500,000,000

Retained earnings (accumulated deficit)

$ (6,262,000,000)

$ (4,879,000,000)

$ (6,262,000,000)

Dividends declared, in dollars per share | $ / shares

$ 0.38

$ 1.82

$ 1.44

$ 1.44

Common stock dividends per share paid, in dollars per share | $ / shares

$ 0.36

$ 0.36

$ 0.36

$ 0.36

$ 0.36

$ 0.36

$ 0.36

$ 0.36

FERC-defined equity to total capitalization ratio

35.00%

Stock Investment Plan and certain share-based benefit plans

$ 62,000,000

$ 56,000,000

$ 56,000,000

Preferred shares shares outstanding | shares

0

0

0

Preference shares outstanding | shares

0

0

0

Repayments of debt

$ 2,608,000,000

$ 2,291,000,000

$ 2,331,000,000

Number of subsidiaries that issued environmental control bonds | subsidiary

2

Environmental control bonds outstanding

$ 383,000,000

$ 358,000,000

383,000,000

Transition bond outstanding

$ 56,000,000

41,000,000

$ 56,000,000

Principal default amount specified in debt covenants

$ 100,000,000

Amount of private placement shares | shares

30,120,482

Common stock, par value (in dollars per share) | $ / shares

$ 0.10

$ 0.1

$ 0.1

$ 0.1

Amount of private placement

$ 850,000,000

Preferred stock, par value, in dollars per share | $ / shares

$ 100

$ 100

Liquidation preference value

$ 1,000

Conversion price (in dollars per share) | $ / shares

$ 27.42

Common stock share cap (in shares) | shares

58,964,222

Conversion threshold of Preferred Stock (in shares) | shares

323,200

Number of shares to be converted in the next two years | shares

0

RWG number of board members | employee

2

Phase In Recovery Bonds

Debt Instrument [Line Items]

Long-term debt and other long-term obligations

$ 315,000,000

$ 292,000,000

$ 315,000,000

Term Loan

Debt Instrument [Line Items]

Face amount of loan

$ 125,000,000

Number of loans | agreement

2

AGC | Senior Notes | 5.06% Senior Notes Due 2021

Debt Instrument [Line Items]

Interest rate (percent)

5.06%

Make-whole premiums

$ 5,700,000

Repayments of debt

$ 100,000,000

MAIT | Senior Notes | 4.1% Senior Notes Due 2028

Debt Instrument [Line Items]

Face amount of loan

$ 450,000,000

Interest rate (percent)

4.10%

AE Supply | PCRB

Debt Instrument [Line Items]

Interest rate (percent)

5.25%

Repayments of debt

$ 142,000,000

AE Supply | Senior Notes | 5.75% Senior Notes Due 2019

Debt Instrument [Line Items]

Interest rate (percent)

5.75%

Repayments of debt

$ 155,000,000

AE Supply | Senior Notes | 6.75% Senior Notes Due 2039

Debt Instrument [Line Items]

Interest rate (percent)

6.75%

Make-whole premiums

$ 83,300,000

Repayments of debt

$ 150,000,000

AE Supply and MP | PCRB | 5.5% Pollution Control Revenue Bond Due 2037

Debt Instrument [Line Items]

Interest rate (percent)

5.50%

Repayments of debt

$ 73,500,000

OE | FMBs | $25M First Mortgage Bonds, 8.25% Due 2018

Debt Instrument [Line Items]

Interest rate (percent)

8.25%

Repayments of debt

$ 25,000,000

AGC

Debt Instrument [Line Items]

FERC-defined equity to total capitalization ratio

45.00%

MP | PCRB | 3% PCRB Due 2021

Debt Instrument [Line Items]

Face amount of loan

$ 73,500,000

Interest rate (percent)

3.00%

JCP&L | Senior Notes | 4.8% Senior Notes Due 2018

Debt Instrument [Line Items]

Interest rate (percent)

4.80%

Repayments of debt

$ 150,000,000

ATSI | Senior Notes | 4.32% Senior Notes Due 2030

Debt Instrument [Line Items]

Face amount of loan

$ 100,000,000

Interest rate (percent)

4.32%

Penn

Debt Instrument [Line Items]

Preferred stock, par value, in dollars per share | $ / shares

$ 100

Penn | FMBs | $50M First Mortgage Bonds, 4.37% Due 2048

Debt Instrument [Line Items]

Face amount of loan

$ 50,000,000

Interest rate (percent)

4.37%

CEI | FMBs | $300M FMB's, 8.88% Due 2018

Debt Instrument [Line Items]

Interest rate (percent)

8.875%

Repayments of debt

$ 300,000,000

CEI | Senior Notes | 4.55% Senior Unsecured Notes Due 2030

Debt Instrument [Line Items]

Face amount of loan

$ 300,000,000

Interest rate (percent)

4.55%

Ohio Funding Companies | Phase In Recovery Bonds

Debt Instrument [Line Items]

Face amount of loan

$ 445,000,000

Common Stock

Debt Instrument [Line Items]

Stock issuance - employee benefits, shares | shares

3,200,000

3,000,000

2,700,000

Stock Investment Plan and certain share-based benefit plans

$ 1,000,000

Amount of private placement

$ 3,000,000

Number of shares issued | shares

33,238,910

Other Paid-In Capital

Debt Instrument [Line Items]

Stock Investment Plan and certain share-based benefit plans

$ 61,000,000

$ 56,000,000

$ 56,000,000

Amount of private placement

$ 847,000,000

Preferred Stock

Debt Instrument [Line Items]

Number of shares converted | shares

911,411

Pension

Debt Instrument [Line Items]

Stock issuance - employee benefits, shares | shares

16,097,875

Stock Investment Plan and certain share-based benefit plans

$ 500,000,000

Subsequent Event

Debt Instrument [Line Items]

Preferred shares shares outstanding | shares

209,822

Subsequent Event | JCP&L | Senior Notes

Debt Instrument [Line Items]

Face amount of loan

$ 400,000,000

Subsequent Event | JCP&L | Senior Notes | 4.30% Senior Notes Due 2026

Debt Instrument [Line Items]

Interest rate (percent)

4.30%

Subsequent Event | JCP&L | Senior Notes | 7.35% Senior Notes Due 2019

Debt Instrument [Line Items]

Interest rate (percent)

7.35%

Subsequent Event | ME | Senior Notes | 4.30% Senior Notes Due 2029

Debt Instrument [Line Items]

Face amount of loan

$ 500,000,000

Interest rate (percent)

4.30%

Subsequent Event | ME | Senior Notes | 7.70% Senior Notes Due 2019

Debt Instrument [Line Items]

Interest rate (percent)

7.70%

Subsequent Event | Common Stock

Debt Instrument [Line Items]

Number of shares issued | shares

18,044,018

Subsequent Event | Preferred Stock

Debt Instrument [Line Items]

Number of shares converted | shares

494,767

Series A Convertible Preferred Stock

Debt Instrument [Line Items]

Preferred stock shares issued | shares

1,616,000

Preferred shares shares outstanding | shares

704,589

Amount of preferred stock investment

$ 1,620,000,000

Series A Convertible Preferred Stock | Other Paid-In Capital

Debt Instrument [Line Items]

Amount of preferred stock investment

1,460,000,000

Series A Convertible Preferred Stock | Preferred Stock

Debt Instrument [Line Items]

Amount of preferred stock investment

$ 162,000,000

FE

Debt Instrument [Line Items]

RWG number of board members | employee

3

FE | Term Loan | Term Loan Due 2020

Debt Instrument [Line Items]

Face amount of loan

$ 1,250,000,000

Debt term

364 days

FE | Variable Rate Term Loan

Debt Instrument [Line Items]

Repayments of debt

$ 1,200,000,000

FE | Variable Rate Term Loan | Variable Rate Term Loan Due 2020

Debt Instrument [Line Items]

Face amount of loan

$ 500,000,000

Debt term

2 years

Short-Term Borrowings and Ban_3

Short-Term Borrowings and Bank Lines of Credit (Details) - USD ($) $ in Millions	Feb. 18, 2019	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Cash		$ 367		$ 588
Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	$ 3,500
Cash	0
Available Liquidity	3,490
Cash, Available Liquidity	156
Total Available Liquidity	3,646
FET | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Available Liquidity	1,000
Revolving Credit Facility | Line of Credit
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility			$ 5,000
Revolving Credit Facility | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	3,500
Revolving Credit Facility | FET | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	1,000
FE | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Available Liquidity	2,490
FE | Revolving Credit Facility | Line of Credit | Subsequent Event
Short-term Debt [Line Items]
Maximum amount borrowed under revolving credit facility	$ 2,500

Short-Term Borrowings and Ban_4

Short-Term Borrowings and Bank Lines of Credit (Details 1) - USD ($)	Feb. 18, 2019	Jan. 31, 2019	Oct. 19, 2018
FET | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits			$ 1,000,000,000
FE | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits			$ 3,500,000,000
Subsequent Event
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits	$ 3,500,000,000
Subsequent Event | FET
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		$ 0
Subsequent Event | OE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		500,000,000
Subsequent Event | CEI
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		500,000,000
Subsequent Event | TE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		300,000,000
Subsequent Event | JCP&L
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		500,000,000
Subsequent Event | ME
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		500,000,000
Subsequent Event | PN
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		300,000,000
Subsequent Event | WP
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		200,000,000
Subsequent Event | MP
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		500,000,000
Subsequent Event | PE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		150,000,000
Subsequent Event | ATSI
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		500,000,000
Subsequent Event | Penn
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		100,000,000
Subsequent Event | TrAIL
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		400,000,000
Subsequent Event | MAIT
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		400,000,000
Subsequent Event | FE
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Regulatory and Other Short-Term Debt Limitations		0
Subsequent Event | FE | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		2,500,000,000
Subsequent Event | FE | FET | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		0
Subsequent Event | FE | OE | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		500,000,000
Subsequent Event | FE | CEI | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		500,000,000
Subsequent Event | FE | TE | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		300,000,000
Subsequent Event | FE | JCP&L | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		500,000,000
Subsequent Event | FE | ME | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		500,000,000
Subsequent Event | FE | PN | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		300,000,000
Subsequent Event | FE | WP | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		200,000,000
Subsequent Event | FE | MP | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		500,000,000
Subsequent Event | FE | PE | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		150,000,000
Subsequent Event | FE | ATSI | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		0
Subsequent Event | FE | Penn | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		100,000,000
Subsequent Event | FE | TrAIL | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		0
Subsequent Event | FE | MAIT | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		0
Subsequent Event | FET Sub-limits | FET | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		1,000,000,000
Subsequent Event | FET Sub-limits | ATSI | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		500,000,000
Subsequent Event | FET Sub-limits | TrAIL | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		400,000,000
Subsequent Event | FET Sub-limits | MAIT | Line of Credit | Revolving Credit Facility
Borrowing sub-limits for each borrower and limitations on short-term indebtedness
Revolving Credit Facility Sub-Limits		$ 400,000,000

Short-Term Borrowings and Ban_5

Short-Term Borrowings and Bank Lines of Credit (Details Textuals)	Feb. 01, 2019USD ($)	Oct. 19, 2018USD ($)agreement	Jan. 31, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2016USD ($)	Feb. 18, 2019USD ($)	Jan. 31, 2019USD ($)	Sep. 30, 2018USD ($)	Jan. 22, 2018USD ($)agreement	Dec. 31, 2017USD ($)
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Short-term borrowings				$ 1,250,000,000						$ 300,000,000
Average interest rate for borrowings				3.07%						3.24%
Minimum
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Company contributions			$ 500,000,000		$ 382,000,000
Maximum | Affiliates
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility				364 days
Term Loan
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Number of agreements | agreement									2
Face amount of loan									$ 125,000,000
Outstanding borrowings		$ 1,750,000,000
Term Loan | Federal Funds Rate
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Spread on variable rate		0.50%
Term Loan | LIBOR
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Spread on variable rate		1.00%
Term Loan | $1.25B Term Loan
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Number of agreements | agreement		2
Term of revolving credit facility		364 days
Face amount of loan		$ 1,250,000,000
Term Loan | $500M Term Loan
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Term of revolving credit facility		2 years
Face amount of loan		$ 500,000,000,000
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
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]
Maximum amount borrowed under revolving credit facility		$ 1,000,000,000
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
Line of Credit | Revolving Credit Facility
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility								$ 5,000,000,000
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
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				2.26%
Money Pool | Unregulated Companies
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Average interest rate for borrowings				2.96%
FE | Revolving Credit Facility | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility		3,500,000,000
Available Liquidity		$ 2,500,000,000
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
Subsequent Event
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility						$ 3,500,000,000
Available Liquidity						3,490,000,000
Company contributions	$ 500,000,000
Subsequent Event | Line of Credit | FE and the Utilities
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Available Liquidity						10,000,000
Subsequent Event | Line of Credit | FET
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Available Liquidity						1,000,000,000
Subsequent Event | Line of Credit | Revolving Credit Facility
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility						3,500,000,000
Subsequent Event | Line of Credit | Revolving Credit Facility | FET
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility						1,000,000,000
Subsequent Event | 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
Subsequent Event | FE | Revolving Credit Facility | FET | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility							$ 0
Subsequent Event | FE | Line of Credit
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Available Liquidity						2,490,000,000
Subsequent Event | FE | Line of Credit | Revolving Credit Facility
Short-Term Borrowings and Bank Lines of Credit (Textuals) [Abstract]
Maximum amount borrowed under revolving credit facility						$ 2,500,000,000

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended			12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2017	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligations [Line Items]
Nuclear plant decommissioning trusts	$ 790			$ 790	$ 822
Changes to the asset retirement obligations
Beginning Balance				570	581
Transfer of BV-2 liability to NG					(49)
Changes in timing and amount of estimated cash flows				203
Liabilities settled				(1)	(1)
Accretion				40	39
Ending Balance	812			$ 812	$ 570
Pleasants Power Station | McElroy's Run Impoundment Site
Changes to the asset retirement obligations
Increase in asset retirement obligation		$ 43
Beaver Valley Unit 2
Changes to the asset retirement obligations
Transfer of BV-2 liability to NG			$ 49
TMI2
Changes to the asset retirement obligations
Increase in asset retirement obligation	$ 172

Regulatory Matters - Distributi

Regulatory Matters - Distribution Rate Orders (Details)	1 Months Ended	12 Months Ended
	Jan. 31, 2019	Dec. 31, 2018
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		55.00%
Allowed Equity		45.00%
Approved ROE		9.60%
OE
Public Utilities, General Disclosures [Line Items]
Allowed Debt		51.00%
Allowed Equity		49.00%
Approved ROE		10.50%
PN
Public Utilities, General Disclosures [Line Items]
Allowed Debt		47.40%
Allowed Equity		52.60%
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		48.00%
Allowed Equity		52.00%
Approved ROE		11.90%
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%
ATSI | Regulated Transmission
Public Utilities, General Disclosures [Line Items]
Approved ROE		10.38%
MAIT | Regulated Transmission
Public Utilities, General Disclosures [Line Items]
Allowed Debt		50.00%
Allowed Equity		50.00%
Approved ROE		10.30%
TrAIL | Regulated Transmission | TrAIL the Line and Black Oak SVC
Public Utilities, General Disclosures [Line Items]
Approved ROE		12.70%
TrAIL | Regulated Transmission | All Other Projects
Public Utilities, General Disclosures [Line Items]
Approved ROE		11.70%
Subsequent Event | MAIT | Regulated Transmission
Public Utilities, General Disclosures [Line Items]
Allowed Debt	60.00%

Regulatory Matters - Maryland a

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions

Dec. 17, 2018USD ($)

Nov. 20, 2018USD ($)

Oct. 22, 2018USD ($)

Oct. 05, 2018USD ($)

Aug. 24, 2018USD ($)program

Aug. 17, 2018USD ($)

Jul. 13, 2018USD ($)

Mar. 02, 2018USD ($)

Jan. 19, 2018USD ($)

Jul. 16, 2015

Feb. 27, 2013USD ($)

Dec. 31, 2018

Dec. 31, 2020USD ($)

Feb. 15, 2018USD ($)

Maryland

Regulatory Matters [Line Items]

Expected infrastructure investments

$ 2,700

Expected infrastructure investments, period

15 years

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%

Incremental energy savings goal in the next 12 months (percent)

0.97%

Amortization period for expenditures for cost recovery program

5 years

PE | Maryland | MDPSC

Regulatory Matters [Line Items]

Requested increase (decrease) in revenues

$ (5)

$ (6.5)

Requested rate increase (decrease)

$ 19.7

Number of enhanced service reliability programs | program

4,000,000

Revised requested rate increase

$ 17.6

Revised rate increase

$ 12.9

$ 7.3

Recommended decrease due to jobs act

$ 11.1

PE | Maryland | MDPSC | Minimum

Regulatory Matters [Line Items]

Impact on base rate due to Tax Act

$ 7

PE | Maryland | MDPSC | Maximum

Regulatory Matters [Line Items]

Impact on base rate due to Tax Act

$ 8

JCP&L

Regulatory Matters [Line Items]

Approved ROE

9.60%

JCP&L | New Jersey | NJBPU

Regulatory Matters [Line Items]

Requested increase (decrease) in revenues

$ (28.6)

Approved rate increase due to changes in deferred taxes

$ 1.3

Forecast | PE | Maryland

Regulatory Matters [Line Items]

Recovery period for expenditures for cost recovery program

3 years

Expenditures for cost recovery program

$ 116

JCP&L Reliability Plus | JCP&L | NJBPU

Regulatory Matters [Line Items]

Requested rate increase (decrease)

$ 386.8

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

Regulatory Matters [Line Items]

Requested increase (decrease) in revenues

$ 97

Infrastructure investment period

4 years

Approved ROE

8.75%

Cost of debt

5.38%

Regulatory Matters - Ohio (Deta

Regulatory Matters - Ohio (Details) $ in Millions	Nov. 09, 2018USD ($)	Apr. 25, 2018USD ($)	Mar. 12, 2018	Dec. 01, 2017USD ($)	Oct. 12, 2016USD ($)	Aug. 07, 2013USD ($)auction	Dec. 31, 2018	Sep. 30, 2018USD ($)	Feb. 15, 2018USD ($)
Regulatory Matters [Line Items]
Proposed reduction in power plants carbon pollution (percent)							90.00%
Ohio
Regulatory Matters [Line Items]
Portfolio plan estimated cost								$ 268
Credit to non-shopping customers						$ 43.4
Ohio | PUCO
Regulatory Matters [Line Items]
Proposed reduction in power plants carbon pollution (percent)					90.00%
Requested removal of cost cap			4.00%
Number of renewable energy auctions | auction						1,000,000
Gain related to litigation settlement		$ 72
Ohio | PUCO | Distribution Modernization Rider
Regulatory Matters [Line Items]
Annual revenue cap for rider					$ 132.5
Cost recovery period					3 years
Possible extension period					2 years
Approved annual revenue cap amount for rider					$ 168
Excessive earnings test cost recovery exclusion period					3 years
Potential extension period for excessive earnings test cost recovery					2 years
Ohio | PUCO | DCR Rider
Regulatory Matters [Line Items]
Increased annual revenue cap for rider					$ 30
Revenue cap for Rider for years 3-6					20
Revenue cap for Rider for years 6-8					15
Ohio | PUCO | DPM Plan
Regulatory Matters [Line Items]
Requested rate increase (decrease)				$ 450
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 | Ohio | PUCO
Regulatory Matters [Line Items]
Impact on base rate due to Tax Act									$ 40

Regulatory Matters - Pennsylvan

Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Thousands	Jan. 18, 2019USD ($)	Aug. 31, 2018USD ($)	May 30, 2018USD ($)	Mar. 09, 2018USD ($)	Dec. 11, 2017proposalMW	Mar. 31, 2016USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)	Dec. 31, 2018proposal	Mar. 06, 2017MW	Sep. 30, 2016program
Pennsylvania
Regulatory Matters [Line Items]
Project term									2 years
Number of RFP's | proposal									1
Pennsylvania | 12 Month Period
Regulatory Matters [Line Items]
Energy contract term									12 months
Pennsylvania | 24 Month Period
Regulatory Matters [Line Items]
Energy contract term									24 months
Pennsylvania | PPUC | Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Rate filing period									3 years
Pennsylvania | PPUC | ME
Regulatory Matters [Line Items]
Annual effect				$ 37,000
Pennsylvania | PPUC | ME | Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of rate increase							$ 12,000
Pennsylvania | PPUC | ME | Voluntary Surcharges
Regulatory Matters [Line Items]
Approved amount of rate increase								$ (22,000)
Pennsylvania | PPUC | Penn
Regulatory Matters [Line Items]
Annual effect				9,000
Pennsylvania | PPUC | Penn | Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of rate increase							3,000
Pennsylvania | PPUC | Penn | Voluntary Surcharges
Regulatory Matters [Line Items]
Approved amount of rate increase								(6,000)
Pennsylvania | PPUC | WP
Regulatory Matters [Line Items]
Annual effect				30,000
Pennsylvania | PPUC | WP | Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of rate increase							10,000
Pennsylvania | PPUC | WP | Voluntary Surcharges
Regulatory Matters [Line Items]
Approved amount of rate increase								(18,000)
Pennsylvania | PPUC | Pennsylvania Companies | DSP
Regulatory Matters [Line Items]
Project term					2 years
Number of RFP's | proposal					2
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						$ (390,000)
Pennsylvania | PPUC | PN
Regulatory Matters [Line Items]
Annual effect				$ 40,000
Pennsylvania | PPUC | PN | Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of rate increase							$ 13,000
Pennsylvania | PPUC | PN | Voluntary Surcharges
Regulatory Matters [Line Items]
Approved amount of rate increase								$ (23,000)
West Virginia | WVPSC | MP and PE
Regulatory Matters [Line Items]
Number of proposed efficient programs | program											3
Energy efficient reduction requirement (percent)											0.50%
Annual effect			$ 26,200
West Virginia | WVPSC | MP and PE | ENEC
Regulatory Matters [Line Items]
Requested rate increase (decrease)		$ 100,900
Annual effect		25,600
West Virginia | WVPSC | MP and PE | Elimination of Energy Efficiency Cost Rate Surcharge
Regulatory Matters [Line Items]
Requested rate increase (decrease)		$ 2,100
Requested rate increase (decrease) (percent)		7.20%
Pleasants Power Station
Regulatory Matters [Line Items]
Plant generation capacity (in MW's) | MW										1,300
Subsequent Event | Pennsylvania | ME
Regulatory Matters [Line Items]
Requested rate increase (decrease)	$ 44,520
Subsequent Event | Pennsylvania | Penn
Regulatory Matters [Line Items]
Requested rate increase (decrease)	26,060
Subsequent Event | Pennsylvania | WP
Regulatory Matters [Line Items]
Requested rate increase (decrease)	50,850
Subsequent Event | Pennsylvania | PN
Regulatory Matters [Line Items]
Requested rate increase (decrease)	$ 24,720

Regulatory Matters - Reliabilit

Regulatory Matters - Reliability and FERC Matters (Details) $ in Millions	May 21, 2018	May 20, 2018	May 14, 2018	Feb. 20, 2018USD ($)	Jun. 15, 2016kv	Aug. 04, 2014	Sep. 30, 2018USD ($)	Jun. 30, 2018USD ($)	Dec. 31, 2018USD ($)entity	Dec. 31, 2016	Dec. 31, 2015
Regulatory Matters [Line Items]
Regional enforcement entities | entity									8
FERC
Regulatory Matters [Line Items]
Power threshold for cost methodology (in KW) | kv					500
Denied recovery charges of exit fees									$ 78.8
FERC | PJM Transmission Rates
Regulatory Matters [Line Items]
Load-ratio share										100.00%	50.00%
Solution-based distribution factor											50.00%
Gain related to litigation settlement							$ 42	$ 73	$ 115
Ohio Companies | FERC | Unit Power Agreement
Regulatory Matters [Line Items]
Term of proposed purchase power agreement						8 years
MAIT | FERC
Regulatory Matters [Line Items]
Approved ROE	10.30%	11.00%
Approved capital structure	60.00%
JCP&L
Regulatory Matters [Line Items]
Approved ROE									9.60%
Approved capital structure									45.00%
JCP&L | FERC | Network Integration Transmission Service
Regulatory Matters [Line Items]
Annual revenue requirement				$ 135
JCP&L | FERC | PJM Tariff
Regulatory Matters [Line Items]
Annual revenue requirement				$ 20
Monogahela Power Company, Potomac Edison Company and West Penn Power Company | FERC
Regulatory Matters [Line Items]
Requested rate increase (decrease) (percent)			6.70%

Commitments, Guarantees and C_3

Commitments, Guarantees and Contingencies (Details) $ in Millions	Dec. 31, 2018USD ($)
Guarantor Obligations [Line Items]
Potential additional collateral obligations	$ 369
Regulated Distribution
Guarantor Obligations [Line Items]
Potential additional collateral obligations	121
FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	246
AE Supply
Guarantor Obligations [Line Items]
Potential additional collateral obligations	2
At Current Credit Rating
Guarantor Obligations [Line Items]
Potential additional collateral obligations	1
At Current Credit Rating | Regulated Distribution
Guarantor Obligations [Line Items]
Potential additional collateral obligations	0
At Current Credit Rating | FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	0
At Current Credit Rating | AE Supply
Guarantor Obligations [Line Items]
Potential additional collateral obligations	1
Upon Further Downgrade
Guarantor Obligations [Line Items]
Potential additional collateral obligations	62
Upon Further Downgrade | Regulated Distribution
Guarantor Obligations [Line Items]
Potential additional collateral obligations	62
Upon Further Downgrade | FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	0
Upon Further Downgrade | AE Supply
Guarantor Obligations [Line Items]
Potential additional collateral obligations	0
Surety Bond
Guarantor Obligations [Line Items]
Potential additional collateral obligations	306
Surety Bond | Regulated Distribution
Guarantor Obligations [Line Items]
Potential additional collateral obligations	59
Surety Bond | FE
Guarantor Obligations [Line Items]
Potential additional collateral obligations	246
Surety Bond | AE Supply
Guarantor Obligations [Line Items]
Potential additional collateral obligations	$ 1

Commitments, Guarantees and C_4

Commitments, Guarantees and Contingencies - Nuclear Insurance, Commitments and Collateral (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Jun. 30, 2018
Loss Contingencies [Line Items]
Coverage of decontamination costs	$ 150,000,000
Liability assessed with respect to single nuclear incident	560,000,000
Outstanding guarantees and other assurances aggregated	1,700,000,000
Potential additional collateral obligations	369,000,000
FE
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	345,000,000
Subsidiaries' Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	1,000,000,000
Other Guarantees
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	190,000,000
Other Assurances
Loss Contingencies [Line Items]
Outstanding guarantees and other assurances aggregated	140,000,000
Regulated Distribution
Loss Contingencies [Line Items]
Company posted collateral related to net liability positions	2,000,000
Potential additional collateral obligations	121,000,000
JCP& L, ME and PE
Loss Contingencies [Line Items]
Annual retrospective premium assessments	$ 1,200,000
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%
Global Holding | Senior Secured Term Loan | Senior Loans
Loss Contingencies [Line Items]
Long-term debt and other long-term obligations	$ 190,000,000
Global Holding | Signal Peak, Global Rail and Affiliates | Senior Secured Term Loan | Senior Loans
Loss Contingencies [Line Items]
Investment ownership percentage	69.99%
AE Supply
Loss Contingencies [Line Items]
Potential additional collateral obligations	$ 2,000,000
Surety Bond | Little Bull Run | Line of Credit
Loss Contingencies [Line Items]
Maximum amount borrowed under revolving credit facility	169,000,000
Surety Bond | Hatfield Ferry | Line of Credit
Loss Contingencies [Line Items]
Maximum amount borrowed under revolving credit facility	31,000,000
Term Loan Facility Due March 2020 | Line of Credit | Global Holding
Loss Contingencies [Line Items]
Face amount of loan	$ 300,000,000	$ 300,000,000

Commitments, Guarantees and C_5

Commitments, Guarantees and Contingencies - Clean Air Act and Climate Change (Details) T in Millions, $ in Millions	Apr. 06, 2018USD ($)	Feb. 18, 2018USD ($)	May 01, 2017installment	Oct. 01, 2015	Mar. 31, 2017USD ($)	Dec. 31, 2018USD ($)phaseT	Nov. 12, 2014
Loss Contingencies [Line Items]
Proposed reduction in power plants carbon pollution (percent)						90.00%
AE Supply
Loss Contingencies [Line Items]
Amount of damages awarded to other party		$ 93
National Ambient Air Quality Standards
Loss Contingencies [Line Items]
Capping of SO2 Emissions Under CSAPR | T						2.4
Capping of NOx emissions under CSAPR | T						1.2
National Ambient Air Quality Standards | CSAPR
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%
EPA | Caa Compliance
Loss Contingencies [Line Items]
Number of installment payments | installment			3
Period of time to implement plan				3 years
Settled Litigation | Caa Compliance
Loss Contingencies [Line Items]
Loss in period					$ 109
Discontinued Operations, Disposed of by Means Other than Sale | FES and FENOC
Loss Contingencies [Line Items]
Amount of damages awarded to other party						$ 66
Settlement payments	$ 72

Commitments, Guarantees and C_6

Commitments, Guarantees and Contingencies - Clean Water Act and Regulation of Waste Disposal (Details) - USD ($)	3 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2018
Loss Contingencies [Line Items]
Renewal cycle of waste water discharge permit		5 years
Regulation of Waste Disposal
Loss Contingencies [Line Items]
Bond closure and post closure period		45 years
Period of time to implement plan		12 years
Accrual for environmental loss contingencies		$ 121,000,000
Environmental liabilities former gas facilities		85,000,000
Minimum | Clean Water Act
Loss Contingencies [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits		150,000,000
Maximum | Clean Water Act
Loss Contingencies [Line Items]
Maximum capital investment required to install technology to meet TDS and Sulfate limits		300,000,000
Pleasants Power Station | McElroy's Run Impoundment Site
Loss Contingencies [Line Items]
Increase in asset retirement obligation	$ 43,000,000
Pleasants Power Station | AE Supply | McElroy's Run Impoundment Site | Regulation of Waste Disposal
Loss Contingencies [Line Items]
Increase in asset retirement obligation	$ 43,000,000
Line of Credit | Surety Bond | Little Bull Run
Loss Contingencies [Line Items]
Maximum amount borrowed under revolving credit facility		169,000,000
Line of Credit | Surety Bond | Hatfield Ferry
Loss Contingencies [Line Items]
Maximum amount borrowed under revolving credit facility		$ 31,000,000

Commitments, Guarantees and C_7

Commitments, Guarantees and Contingencies - Other Legal Proceedings (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Loss Contingencies [Line Items]
Nuclear plant decommissioning trusts	$ 790	$ 822
Nuclear Plant Matters
Loss Contingencies [Line Items]
Nuclear plant decommissioning trusts	$ 790

Segment Information (Details)

Segment Information (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Segment Financial Information
Total revenues	$ 2,710	$ 3,064	$ 2,625	$ 2,862	$ 2,681	$ 2,910	$ 2,561	$ 2,776	$ 11,261	[1]	$ 10,928	[1]	$ 10,700	[1]
Provision for depreciation	293	283	283	277	262	261	254	250	1,136		1,027		933
Amortization (deferral) of regulatory assets, net									(150)		308		297
Impairment of assets and related charges	0	0	0	0	28	13	0	0	0		41		43
Miscellaneous income, net									205		53		44
Interest expense									1,116		1,005		973
Income taxes	(13)	133	121	249	1,232	202	132	149	490		1,715		527
Income (loss) from continuing operations	182	$ 387	$ 288	$ 165	(1,061)	$ 301	$ 220	$ 251	1,022		(289)		551
Total assets	40,063				42,257				40,063		42,257		43,148
Total goodwill	5,618				5,618				5,618		5,618		5,618
Property additions									2,675		2,587		2,835
Regulated Distribution
Segment Financial Information
Total goodwill	5,004								5,004
Regulated Transmission
Segment Financial Information
Total revenues									1,335
Operating Segments | Regulated Distribution
Segment Financial Information
Total revenues									10,103		9,760		9,619
Provision for depreciation									812		724		676
Amortization (deferral) of regulatory assets, net									(163)		292		290
Impairment of assets and related charges											0		0
Miscellaneous income, net									192		57		85
Interest expense									514		535		586
Income taxes									422		580		375
Income (loss) from continuing operations									1,242		916		651
Total assets	28,690				27,730				28,690		27,730		27,702
Total goodwill	5,004				5,004				5,004		5,004		5,004
Property additions									1,411		1,191		1,063
Operating Segments | Regulated Transmission
Segment Financial Information
Total revenues									1,353		1,324		1,143
Provision for depreciation									252		224		187
Amortization (deferral) of regulatory assets, net									13		16		7
Impairment of assets and related charges											41		0
Miscellaneous income, net									14		1		(1)
Interest expense									167		156		158
Income taxes									122		205		187
Income (loss) from continuing operations									397		336		331
Total assets	10,404				9,525				10,404		9,525		8,755
Total goodwill	614				614				614		614		614
Property additions									1,104		1,030		1,101
Corporate/ Other
Segment Financial Information
Total revenues									34		43		140
Provision for depreciation									3		10		3
Amortization (deferral) of regulatory assets, net									0		0		0
Impairment of assets and related charges											0		43
Miscellaneous income, net									32		39		(17)
Interest expense									468		358		252
Income taxes									(54)		930		(35)
Income (loss) from continuing operations									(617)		(1,541)		(431)
Total assets	969				1,007				969		1,007		1,061
Total goodwill	0				0				0		0		0
Property additions									133		49		56
Reconciling Adjustments
Segment Financial Information
Total revenues									(229)		(199)		(202)
Provision for depreciation									69		69		67
Amortization (deferral) of regulatory assets, net									0		0		0
Impairment of assets and related charges											0		0
Miscellaneous income, net									(33)		(44)		(23)
Interest expense									(33)		(44)		(23)
Income taxes									0		0		0
Income (loss) from continuing operations									0		0		0
Total assets	0				3,995				0		3,995		5,630
Total goodwill	$ 0				$ 0				0		0		0
Property additions									$ 27		$ 317		$ 615
[1]	Includes excise and gross receipts tax collections of $386 million, $370 million and $378 million in 2018, 2017 and 2016, respectively.

Segment Information (Details Te

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2018USD ($)mi²customercompanyMW
Other/Corporate | OVEC
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment (in MW's)	70
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies | company	10
Number of customers served by utility operating companies | customer	6
Number of square miles in service area | mi²	65
Megawatts of net demonstrated capacity of competitive segment (in MW's)	3,790
FE | Other/Corporate
Segment Reporting Information [Line Items]
Long-term debt and other long-term obligations | $	$ 7,100

Summary of Quarterly Financia_3

Summary of Quarterly Financial Data (Unaudited) (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018		Dec. 31, 2017		Dec. 31, 2016
Quarterly Financial Data [Abstract]
Revenues	$ 2,710	$ 3,064	$ 2,625	$ 2,862	$ 2,681	$ 2,910	$ 2,561	$ 2,776	$ 11,261	[1]	$ 10,928	[1]	$ 10,700	[1]
Other operating expenses	770	739	684	940	803	651	657	650	3,133		2,761		2,579
Pension and OPEB mark-to-market adjustment	(144)	0	0	0	(102)	0	0	0	(144)		(102)		(102)
Provision for depreciation	293	283	283	277	262	261	254	250	1,136		1,027		933
Impairment of assets and related charges	0	0	0	0	28	13	0	0	0		41		43
Operating Income	512	710	700	580	505	733	574	616	2,502		2,428		2,054
Income before income taxes	169	520	409	414	171	503	352	400
Income taxes	(13)	133	121	249	1,232	202	132	149	490		1,715		527
Income (loss) from continuing operations	182	387	288	165	(1,061)	301	220	251	1,022		(289)		551
Discontinued operations (Note 3)	(44)	(845)	11	1,204	(1,438)	95	(46)	(46)
Net Income (Loss)	138	(458)	299	1,369	(2,499)	396	174	205	1,348		(1,724)		(6,177)
Income allocated to preferred shareholders (2)	10	54	165	156	0	0	0	0
Net income (loss) attributable to common shareholders	$ 128	$ (512)	$ 134	$ 1,213	$ (2,499)	$ 396	$ 174	$ 205	$ 981		$ (1,724)		$ (6,177)
Earnings (loss) per share of common stock-
Basic - Continuing Operations, in dollars per share	$ 0.34	$ 0.66	$ 0.27	$ 0.01	$ (2.39)	$ 0.68	$ 0.49	$ 0.57	$ 1.33		$ (0.65)		$ 1.29
Basic - Discontinued Operations, in dollars per share	(0.09)	(1.68)	0.01	2.54	(3.23)	0.21	(0.10)	(0.11)	0.66		(3.23)		(15.78)
Basic - Net Income (Loss) Attributable to Common Stockholders, in dollars per share	0.25	(1.02)	0.28	2.55	(5.62)	0.89	0.39	0.46	1.99		(3.88)		(14.49)
Diluted - Continuing Operations, in dollars per share	0.34	0.66	0.27	0.01	(2.39)	0.68	0.49	0.57	1.33		(0.65)		1.29
Diluted - Discontinued Operations, in dollars per share	(0.09)	(1.68)	0.01	2.53	(3.23)	0.21	(0.10)	(0.11)	0.66		(3.23)		(15.78)
Diluted - Net Income (Loss) Attributable to Common Stockholders, in dollars per share	$ 0.25	$ (1.02)	$ 0.28	$ 2.54	$ (5.62)	$ 0.89	$ 0.39	$ 0.46	$ 1.99		$ (3.88)		$ (14.49)
[1]	Includes excise and gross receipts tax collections of $386 million, $370 million and $378 million in 2018, 2017 and 2016, respectively.

Consolidated Valuation and Qu_2

Consolidated Valuation and Qualifying Accounts (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated provision for uncollectible accounts - customers
Consolidated Valuation and Qualifying Accounts
Beginning Balance	$ 48,937	$ 48,409	$ 60,309
Charged to Income	77,254	73,486	76,953
Charged to Other Accounts	60,307	49,728	15,222
Deductions	136,700	122,686	104,075
Ending Balance	49,798	48,937	48,409
Accumulated provision for uncollectible accounts - other
Consolidated Valuation and Qualifying Accounts
Beginning Balance	990	884	2,731
Charged to Income	12,487	6,461	13,597
Charged to Other Accounts	0	0	11,329
Deductions	11,699	6,355	26,773
Ending Balance	1,778	990	884
Accumulated provision for uncollectible accounts - affiliated companies
Consolidated Valuation and Qualifying Accounts
Beginning Balance	0
Deductions	919,851
Ending Balance	919,851	0
Valuation allowance on various DTAs (3)
Consolidated Valuation and Qualifying Accounts
Beginning Balance	312,135	240,289	146,589
Charged to Income	81,977	71,846	93,700
Charged to Other Accounts	0	0	0
Deductions	0	0	0
Ending Balance	$ 394,112	$ 312,135	$ 240,289