Document

Provision for depreciation

^[1]

$ 3,064

$ 2,910

$ 8,551

$ 8,247

OPERATING EXPENSES:

Fuel

137

126

404

396

Purchased power

876

774

2,393

2,215

Other operating expenses

739

652

2,363

1,958

283

261

843

765

113

(188)

274

General taxes

252

238

746

703

Miscellaneous income, net

Total operating expenses

2,354

2,177

6,561

6,324

OPERATING INCOME

710

733

1,990

1,923

OTHER INCOME (EXPENSE):

164

Capitalized financing costs

(255)

(262)

(858)

(751)

Total other expense

(190)

(230)

(647)

(668)

INCOME BEFORE INCOME TAXES

520

503

1,343

1,255

INCOME TAXES

133

202

503

483

INCOME FROM CONTINUING OPERATIONS

387

301

840

772

Discontinued operations (Note 3)(2)

^[2]

(845)

370

NET INCOME (LOSS)

(458)

396

1,210

775

INCOME ALLOCATED TO PREFERRED STOCKHOLDERS (Note 4)

357

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS

$ (512)

$ 396

$ 853

$ 775

EARNINGS PER SHARE OF COMMON STOCK (Note 4):

Basic - Continuing Operations (in dollars per share)

$ 0.66

$ 0.68

$ 1.00

$ 1.74

Basic - Discontinued Operations (in dollars per share)

(1.68)

0.21

0.76

0.01

Basic - Net Income Attributable to Common Stockholders (in dollars per share)

(1.02)

0.89

1.76

1.75

Diluted - Continuing Operations (in dollars per share)

0.66

0.68

0.99

1.73

Diluted - Discontinued Operations (in dollars per share)

(1.68)

0.21

0.76

0.01

Diluted - Net Income Attributable to Common Stockholders (in dollars per share)

$ (1.02)

$ 0.89

$ 1.75

$ 1.74

WEIGHTED AVERAGE NUMBER OF COMMON SHARES OUTSTANDING:

Basic, in shares

503

444

485

444

Diluted, in shares

505

446

487

445

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK, in dollars per share

$ 0.72

$ 1.44

Excise taxes collected

$ 104

$ 102

$ 293

Income tax expense (benefit)

(354)

(1,300)

(1)

Distribution Services and Retail Generation [Member]

REVENUES:

2,463

2,334

6,807

6,558

Transmission [Member]

REVENUES:

341

337

996

968

Other [Member]

REVENUES:

Organization, Consolidation and Presentation of Financial Statements [Abstract]

$ 260

$ 239

$ 748

$ 721

[1]	Includes excise tax collections of $104 million and $102 million in the three months ended September 30, 2018 and 2017, respectively, and $293 million in the nine months ended September 30, 2018 and 2017.
[2]	Net of income tax expense (benefit) of $(354) million and $37 million for the three months ended September 30, 2018 and 2017, respectively, and income tax benefits of $(1.3) billion and $(1) million for the nine months ended September 30, 2018 and 2017, respectively.

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Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
NET INCOME (LOSS)	$ (458)	$ 396	$ 1,210	$ 775
OTHER COMPREHENSIVE INCOME (LOSS):
Pension and OPEB prior service costs	(18)	(19)	(55)	(55)
Amortized losses on derivative hedges	2	4	19	8
Change in unrealized gains on available-for-sale securities	0	(6)	(106)	8
Other comprehensive loss	(16)	(21)	(142)	(39)
Income tax benefits on other comprehensive loss	(4)	(9)	(61)	(16)
Other comprehensive loss, net of tax	(12)	(12)	(81)	(23)
COMPREHENSIVE INCOME (LOSS)	$ (470)	$ 384	$ 1,129	$ 752

XML 14 R4.htm IDEA: XBRL DOCUMENT

Consolidated Balance Sheets - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
CURRENT ASSETS:
Cash and cash equivalents	$ 436	$ 588
Restricted cash	51	51
Receivables-
Customers, net of allowance for uncollectible accounts of $49 in 2018 and 2017	1,317	1,282
Other, net of allowance for uncollectible accounts of $2 in 2018 and $1 in 2017	299	170
Materials and supplies, at average cost	240	236
Prepaid taxes and other	236	151
Current assets - discontinued operations	17	632
Total current assets	2,596	3,110
PROPERTY, PLANT AND EQUIPMENT:
In service	38,585	37,113
Less — Accumulated provision for depreciation	10,468	10,011
Property, plant and equipment in service net of accumulated provision for depreciation	28,117	27,102
Construction work in progress	1,290	999
Total net property, plant and equipment	29,407	28,101
PROPERTY, PLANT AND EQUIPMENT, NET - DISCONTINUED OPERATIONS	0	1,132
INVESTMENTS:
Nuclear plant decommissioning trusts	822	822
Nuclear fuel disposal trust	253	251
Other	254	255
Investments - discontinued operations	0	1,875
Total other property and investments	1,329	3,203
DEFERRED CHARGES AND OTHER ASSETS:
Goodwill	5,618	5,618
Regulatory assets	80	40
Other	413	697
Deferred charges and other assets - discontinued operations	0	356
Total deferred charges and other assets	6,111	6,711
Total assets	39,443	42,257
CURRENT LIABILITIES:
Currently payable long-term debt	1,128	558
Short-term borrowings	1,700	300
Accounts payable	997	827
Accrued taxes	529	533
Accrued compensation and benefits	300	257
Collateral	27	39
Other	1,012	621
Current liabilities - discontinued operations	0	978
Total current liabilities	5,800	4,113
Stockholders’ equity-
Common stock, $0.10 par value, authorized 700,000,000 shares - 511,445,350 and 445,334,111 shares outstanding as of September 30, 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 September 30, 2018	70	0
Other paid-in capital	11,708	10,001
Accumulated other comprehensive income	61	142
Accumulated deficit	(5,017)	(6,262)
Total stockholders’ equity	6,873	3,925
Long-term debt and other long-term obligations	16,608	18,687
Total capitalization	23,481	22,612
NONCURRENT LIABILITIES:
Accumulated deferred income taxes	2,427	3,171
Retirement benefits	2,742	3,975
Regulatory liabilities	2,673	2,720
Asset retirement obligations	630	570
Adverse power contract liability	99	130
Other	1,591	1,438
Noncurrent liabilities - discontinued operations	0	3,528
Total noncurrent liabilities	10,162	15,532
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Note 11)
Total liabilities and capitalization	39,443	42,257
Affiliated Companies
CURRENT LIABILITIES:
Accounts payable	$ 107	$ 0

XML 15 R5.htm IDEA: XBRL DOCUMENT

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Sep. 30, 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	511,445,350	445,334,111
Par Value, in dollars per share	$ 100
Preferred stock, shares authorized	5,000,000
Customer
Receivables-
Allowance for uncollectible accounts	$ 49	$ 49
Other
Receivables-
Allowance for uncollectible accounts	$ 2	$ 1
Series A Convertible Preferred Stock
Stockholders’ equity-
Preferred stock shares issued	1,616,000
Preferred stock shares outstanding	704,589

XML 16 R6.htm IDEA: XBRL DOCUMENT

Consolidated Statements of Cash Flows - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$ 1,210	$ 775
Adjustments to reconcile net income to net cash from operating activities-
Gain on disposal, net of tax (Note 3)	(405)	0
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	1,003	1,307
Deferred income taxes and investment tax credits, net	462	453
Impairment of assets and related charges	0	162
Retirement benefits, net of payments	(113)	28
Pension trust contributions	(1,250)	0
Unrealized (gain) loss on derivative transactions	(5)	64
Changes in current assets and liabilities-
Receivables	(254)	73
Materials and supplies	43	(6)
Prepaid taxes and other	(114)	(41)
Accounts payable	125	(22)
Accrued taxes	(125)	(161)
Accrued compensation and benefits	(19)	(54)
Other current liabilities	(140)	13
Collateral, net	(21)	19
Other	161	152
Net cash provided from operating activities	558	2,762
New Financing-
Long-term debt	624	4,050
Short-term borrowings, net	1,400	0
Preferred stock issuance	1,616	0
Common stock issuance	850	0
Redemptions and Repayments-
Long-term debt	(2,278)	(1,711)
Short-term borrowings, net	0	(2,175)
Make-whole premiums paid on debt redemptions	(89)	0
Preferred stock dividend payments	(52)	0
Common stock dividend payments	(527)	(478)
Other	(21)	(67)
Net cash provided from (used for) financing activities	1,523	(381)
CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(1,942)	(1,847)
Nuclear fuel	0	(156)
Proceeds from asset sales	419	0
Sales of investment securities held in trusts	736	1,923
Purchases of investment securities held in trusts	(780)	(1,995)
Notes receivable from affiliated companies	(500)	0
Asset removal costs	(171)	(130)
Other	1	(1)
Net cash used for investing activities	(2,237)	(2,206)
Net change in cash and cash equivalents and restricted cash	(156)	175
Cash, cash equivalents and restricted cash at beginning of period	643	260
Cash, cash equivalents and restricted cash at end of period	487	435
SUPPLEMENTAL CASH FLOW INFORMATION:
Non-cash transaction, beneficial conversion feature (Note 4)	296	0
Non-cash transaction, deemed dividend preferred stock (Note 4)	$ (296)	$ 0

XML 17 R7.htm IDEA: XBRL DOCUMENT

Organization and Basis of Presentation

9 Months Ended

Sep. 30, 2018

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.

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

•


•	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.

•


•	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, 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.

•

Capitalized Financing Costs

Restricted Cash

Goodwill

New Accounting Pronouncements

Recently Adopted Pronouncements

XML 18 R8.htm IDEA: XBRL DOCUMENT

Revenue

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Revenue

REVENUE

FirstEnergy’s revenues are primarily derived from electric service provided by its Utilities and transmission (ATSI, TrAIL and MAIT) subsidiaries.

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



	For the Three Months Ended September 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total
	(In millions)
Distribution services⁽²⁾	$	1,440	$	—	$	(22	)	$	1,418
Retail generation	1,059		—		(14		)	1,045
Wholesale sales⁽²⁾	133		—		6			139
Transmission⁽²⁾	—		341		—			341
Other	43		—		—			43
Total revenues from contracts with customers	$	2,675	$	341	$	(30	)	$	2,986
ARP	66		—		—			66
Other non-customer revenue	25		5		(18		)	12
Total revenues	$	2,766	$	346	$	(48	)	$	3,064

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



	For the Nine Months Ended September 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments⁽¹⁾			Total
	(In millions)
Distribution services⁽²⁾	$	3,949	$	—	$	(81	)	$	3,868
Retail generation	2,981		—		(42		)	2,939
Wholesale sales⁽²⁾	377		—		16			393
Transmission⁽²⁾	—		996		—			996
Other	113		—		4			117
Total revenues from contracts with customers	$	7,420	$	996	$	(103	)	$	8,313
ARP	190		—		—			190
Other non-customer revenue	84		14		(50		)	48
Total revenues	$	7,694	$	1,010	$	(153	)	$	8,551

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

Other non-customer revenue includes revenue from derivatives of $4 million and $18 million for the three and nine months ended September 30, 2018, respectively.

Regulated Distribution



	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
Revenues by Customer Class	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(In millions)
Residential	$	1,572	$	4,290
Commercial	628		1,778
Industrial	276		792
Other	23		70
Total Revenues	$	2,499	$	6,930

Regulated Transmission

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



	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
Revenues from Contracts with Customers by Transmission Asset Owner	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(In millions)
ATSI	$	167	$	492
TrAIL	60		183
MAIT	43		106
Other	71		215
Total Revenues	$	341	$	996

XML 19 R9.htm IDEA: XBRL DOCUMENT

Discontinued Operations

9 Months Ended

Sep. 30, 2018

Discontinued Operations and Disposal Groups [Abstract]

Discontinued Operations

DISCONTINUED OPERATIONS

FES and FENOC Chapter 11 Filing

FES Borrowings from FE

Services Agreements

Pursuant to the 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 September 30, 2018, approximately $110 million has been incurred and credited for shared services provided to the FES Debtors, which has been recognized by FE in loss from discontinued operations.

Benefit Obligations

Guarantees provided by FE

Purchase Power

Tax Allocation Agreement

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

Summarized Results of Discontinued Operations

Summarized results of discontinued operations for the three and nine months ended September 30, 2018 and 2017, were as follows:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017

Revenues	$	83		$	788		$	934		$	2,299
Fuel	(52		)	(237		)	(269		)	(671		)
Purchased power	—			(66		)	(85		)	(189		)
Other operating expenses	(24		)	(290		)	(414		)	(1,097		)
Provision for depreciation	(18		)	(28		)	(96		)	(80		)
General taxes	(4		)	(15		)	(32		)	(74		)
Impairment of assets	—			(18		)	—			(149		)
Other expense, net	(1		)	(2		)	(82		)	(37		)
Income (Loss) from discontinued operations, before tax	(16		)	132			(44		)	2
Income tax expense (benefit)⁽¹⁾	(5		)	37			(9		)	(1		)
Income (Loss) from discontinued operations, net of tax	(11		)	95			(35		)	3
Gain (Loss) on disposal of FES and FENOC, net of tax	(834		)	—			405			—
Income (Loss) from discontinued operations	$	(845	)	$	95		$	370		$	3

The gain (loss) on disposal that was recognized in the three and nine months ended September 30, 2018, consisted of the following:



(In millions)	For the Three Months Ended September 30, 2018			For the Nine Months Ended September 30, 2018
Removal of investment in FES and FENOC	$	—		$	2,193
Assumption of benefit obligations retained at FE	—			(820		)
Guarantees and credit support provided by FE	—			(139		)
Reserve on receivables and allocated Pension/OPEB mark-to-market	—			(914		)
Settlement Consideration and Services Credit	(1,183		)	(1,183		)
Loss on disposal of FES and FENOC, before tax	(1,183		)	(863		)
Income tax benefit, including estimated worthless stock deduction	349			1,268
Gain (Loss) on disposal of FES and FENOC, net of tax	$	(834	)	$	405

The following table summarizes the major classes of assets and liabilities as discontinued operations as of September 30, 2018, and December 31, 2017:



(In millions)	September 30, 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	17		227
Prepaid taxes and other	—		199
Total current assets	17		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	$	17	$	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.



	For the Nine Months Ended September 30,
(In millions)	2018			2017

CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations	$	370		$	3
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	110			245
Unrealized (gain) loss on derivative transactions	(15		)	64

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27		)	(233		)
Nuclear fuel	—			(156		)
Sales of investment securities held in trusts	109			834
Purchases of investment securities held in trusts	(122		)	(878		)

XML 20 R10.htm IDEA: XBRL DOCUMENT

Earnings Per Share Of Common Stock

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

EARNINGS PER SHARE OF COMMON STOCK


•	preferred share 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 shares and the participating securities (convertible Preferred Stock) based on their respective rights to receive dividends.

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



	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
Reconciliation of Basic and Diluted EPS of Common Stock	2018			2017		2018			2017

(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	387		$	301	$	840		$	772
Less: Preferred dividends	(19		)	—		(61		)	—
Less: Amortization of beneficial conversion feature	(35		)	—		(296		)	—
Less: Undistributed earnings allocated to preferred stockholders⁽¹⁾	—			—		—			—
Income from continuing operations available to common stockholders	333			301		483			772
Discontinued operations, net of tax	(845		)	95		370			3
Less: Undistributed earnings allocated to preferred stockholders ⁽¹⁾	—			—		—			—
Income (loss) from discontinued operations available to common stockholders	(845		)	95		370			3

Income (loss) available to common stockholders, basic and diluted	$	(512	)	$	396	$	853		$	775

Share Count information:
Weighted average number of basic shares outstanding	503			444		485			444
Assumed exercise of dilutive stock options and awards	2			2		2			1
Weighted average number of diluted shares outstanding	505			446		487			445

Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic	$	0.66		$	0.68	$	1.00		$	1.74
Discontinued operations, basic	(1.68		)	0.21		0.76			0.01
Income (loss) available to common stockholders, basic	$	(1.02	)	$	0.89	$	1.76		$	1.75

Income from continuing operations, diluted	$	0.66		$	0.68	$	0.99		$	1.73
Discontinued operations, diluted	(1.68		)	0.21		0.76			0.01
Income (loss) available to common stockholders, diluted	$	(1.02	)	$	0.89	$	1.75		$	1.74


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

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Pension and Other Postemployment Benefits

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

PENSIONS AND OTHER POSTEMPLOYMENT BENEFITS

PENSION AND OTHER POSTEMPLOYMENT BENEFITS

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



Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended September 30,	2018			2017			2018			2017
	(In millions)
Service costs	$	56		$	52		$	1		$	1
Interest costs	93			97			6			7
Expected return on plan assets	(144		)	(112		)	(7		)	(7		)
Amortization of prior service costs (credits)	2			2			(20		)	(20		)
Special termination costs	21			—			6			—
Net periodic costs (credits), including amounts capitalized	$	28		$	39		$	(14	)	$	(19	)
Net periodic costs (credits), recognized in earnings	$	5		$	30		$	(15	)	$	(14	)


Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Nine Months Ended September 30,	2018			2017			2018			2017
	(In millions)
Service costs	$	168		$	156		$	3		$	3
Interest costs	279			291			18			21
Expected return on plan assets	(432		)	(336		)	(22		)	(22		)
Amortization of prior service costs (credits)	6			6			(60		)	(60		)
Special termination costs	21			—			6			—
Net periodic costs (credits), including amounts capitalized	$	42		$	117		$	(55	)	$	(58	)
Net periodic costs (credits), recognized in earnings	$	(27	)	$	89		$	(57	)	$	(43	)

XML 22 R12.htm IDEA: XBRL DOCUMENT

Accumulated Other Comprehensive Income

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

ACCUMULATED OTHER COMPREHENSIVE INCOME

The changes in AOCI, net of tax, in the three and nine months ended September 30, 2018 and 2017, for FirstEnergy are included in the following tables:



	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI balance as of July 1, 2018	$	(14	)	$	—		$	87		$	73

Amounts reclassified from AOCI^{(1) (2)}	2			—			(18		)	(16		)
Other comprehensive income (loss)	2			—			(18		)	(16		)
Income tax benefits on other comprehensive income (loss)	—			—			(4		)	(4		)
Other comprehensive income (loss), net of tax	2			—			(14		)	(12		)

AOCI Balance as of September 30, 2018	$	(12	)	$	—		$	73		$	61

AOCI balance as of July 1, 2017	$	(26	)	$	61		$	128		$	163

Other comprehensive income before reclassifications	—			27			—			27
Amounts reclassified from AOCI^{(1) (2)}	4			(33		)	(19		)	(48		)
Other comprehensive income (loss)	4			(6		)	(19		)	(21		)
Income taxes (benefits) on other comprehensive income (loss)	1			(3		)	(7		)	(9		)
Other comprehensive income (loss), net of tax	3			(3		)	(12		)	(12		)

AOCI Balance as of September 30, 2017	$	(23	)	$	58		$	116		$	151

	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2018	$	(22	)	$	67		$	97		$	142

Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI^{(1) (2) (3)}	6			(1		)	(55		)	(50		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	19			(106		)	(55		)	(142		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(31		)	(61		)
Other comprehensive income (loss), net of tax	10			(67		)	(24		)	(81		)

AOCI Balance as of September 30, 2018	$	(12	)	$	—		$	73		$	61

AOCI Balance as of January 1, 2017	$	(28	)	$	52		$	150		$	174

Other comprehensive income before reclassifications	—			63			—			63
Amounts reclassified from AOCI^{(1) (2)}	8			(55		)	(55		)	(102		)
Other comprehensive income (loss)	8			8			(55		)	(39		)
Income taxes (benefits) on other comprehensive income (loss)	3			2			(21		)	(16		)
Other comprehensive income (loss), net of tax	5			6			(34		)	(23		)

AOCI Balance as of September 30, 2017	$	(23	)	$	58		$	116		$	151

⁽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".

The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2018 and 2017:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						Affected Line Item in the Consolidated Statements of Income (Loss)
Reclassifications from AOCI⁽¹⁾	2018			2017			2018 ⁽³⁾			2017
	(In millions)
Gains & losses on cash flow hedges
Long-term debt	$	2		$	4		$	6		$	8		Interest expense
	—			(1		)	(1		)	(3		)	Income taxes
	$	2		$	3		$	5		$	5		Net of tax

Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	(21	)	$	(1	)	$	(35	)	Discontinued Operations

Defined benefit pension and OPEB plans
Prior-service costs	$	(18	)	$	(19	)	$	(55	)	$	(55	)	⁽²⁾
	5			7			14			21			Income taxes
	$	(13	)	$	(12	)	$	(41	)	$	(34	)	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".

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Income Taxes	9 Months Ended
Income Taxes	Sep. 30, 2018
Income Tax Disclosure [Abstract]
INCOME TAXES	INCOME TAXES FirstEnergy’s interim effective tax rates reflect the estimated annual effective tax rates for 2018 and 2017. These tax rates are affected by estimated annual permanent items, such as AFUDC equity and other flow-through items, as well as discrete items that may occur in any given period, but are not consistent from period to period. FirstEnergy’s effective tax rate on continuing operations for the three months ended September 30, 2018 and 2017, was 25.6% and 40.2%, respectively. The decrease in effective tax rate is primarily due to the Tax Act that decreased the corporate federal income tax rate from 35% to 21%, which became effective January 1, 2018. FirstEnergy's effective tax rate for the nine months ended September 30, 2018 and 2017 was 37.5% and 38.5%, respectively. The decrease in effective tax rate is primarily due to the Tax Act, discussed above, offset by the impact of the legal and financial separation of FES and FENOC from FirstEnergy in the first quarter of 2018. This separation officially eroded the ties between FES, FENOC and other FirstEnergy 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 re-measurement in state deferred taxes. See Note 3, "Discontinued Operations" for other tax matters relating to the FES Bankruptcy that were recognized in discontinued operations. At December 31, 2017, FirstEnergy recorded provisional income tax amounts in its accounting for certain effects of the provisions of the Tax Act as allowed under SAB 118. In addition, SAB 118 allowed for a measurement period for companies to finalize the provisional amounts recorded as of December 31, 2017, not to exceed one year. During the third quarter of 2018, the IRS provided additional guidance regarding the Tax Act, however, the adjustments to the provisional amounts recorded as of December 31, 2017, were immaterial. FirstEnergy expects to complete its assessment and record any final adjustments to the provisional amounts in the fourth quarter of 2018. FirstEnergy's assessment of accounting for the Tax Act is based upon management's current understanding of the Tax Act. However, it is also expected that further guidance will be issued during the fourth quarter of 2018, which may result in adjustments that could have a material impact to FirstEnergy's future results of operations, cash flows, or financial position. On July 1, 2018, the Governor of New Jersey signed budget legislation that, among other things, enacted unitary combined reporting, imposed a temporary surtax on top of the 9% corporate tax rate, imposed a one-time surtax on certain dividends, required market-based sourcing for sales of services, and selectively adopted certain aspects of the Tax Act. FirstEnergy expects the impact of this legislation to be immaterial to the financial statements. As of September 30, 2018, it was reasonably possible that approximately $2 million of unrecognized tax benefits, unrelated to FES and FENOC, may be resolved within the next twelve months as a result of the statute of limitations expiring, none of which would affect FirstEnergy's 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 unconstitutional 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 court declined to further hear any arguments related to the matter and, as a result, FirstEnergy withdrew its protective refund claims from the Commonwealth 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. 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.

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Variable Interest Entities

9 Months Ended

Sep. 30, 2018

Variable Interest Entities [Abstract]

VARIABLE INTEREST ENTITIES

Consolidated VIEs

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

•

Unconsolidated VIEs

FirstEnergy is not the primary beneficiary of the following VIEs:

•

Global Holding - FEV holds a 33-1/3% equity ownership in Global Holding, the holding company for a joint venture in the Signal Peak mining and coal transportation operations with coal sales in U.S. and international markets. FEV is not the primary beneficiary of the joint venture, as it does not have control over the significant activities affecting the joint venture's economic performance. FEV's ownership interest is subject to the equity method of accounting. In 2015, FirstEnergy fully impaired the value of its investment in Global Holding.

•


•	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.

•

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Fair Value Measurements

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

FAIR VALUE MEASUREMENTS

RECURRING FAIR VALUE MEASUREMENTS



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



Level 3	-	Valuation inputs are unobservable and significant to the fair value measurement




	September 30, 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	—		—		10			10			—		—		3			3
Equity securities⁽¹⁾	329		—		—			329			297		—		—			297
Foreign government debt securities	—		12		—			12			—		23		—			23
U.S. government debt securities	—		22		—			22			—		21		—			21
U.S. state debt securities	—		251		—			251			—		247		—			247
Other⁽²⁾	436		106		—			542			588		38		—			626
Total assets	$	765	$	796	$	10		$	1,571		$	885	$	805	$	3		$	1,693

Liabilities
Derivative liabilities - FTRs	$	—	$	—	$	(1	)	$	(1	)	$	—	$	—	$	—		$	—
Derivative liabilities - NUG contracts⁽³⁾	—		—		(52		)	(52		)	—		—		(79		)	(79		)
Total liabilities	$	—	$	—	$	(53	)	$	(53	)	$	—	$	—	$	(79	)	$	(79	)

Net assets (liabilities)⁽⁴⁾	$	765	$	796	$	(43	)	$	1,518		$	885	$	805	$	(76	)	$	1,614


⁽¹⁾	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.


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


⁽³⁾	NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.


⁽⁴⁾	Excludes $(33) million and $(11) million as of September 30, 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



	NUG Contracts⁽¹⁾									FTRs
	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			7			2			9
Purchases	—			—			—			5			(5		)	—
Settlements	—			25			25			(5		)	2			(3		)
September 30, 2018 Balance	$	—		$	(52	)	$	(52	)	$	10		$	(1	)	$	9

(1)NUG 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 September 30, 2018:

Fair Value, Net (In millions)

Valuation
Technique

Significant Input

Range

Weighted Average

Units

FTRs

Model

RTO auction clearing prices

$(0.40) to $8.60

$1.40

Dollars/MWH

NUG Contracts

(52

)

Model

Generation

400 to 1,437,000

293,000

MWH

Regional electricity prices

$30.60 to $32.70

$31.60

Dollars/MWH

INVESTMENTS

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.



	September 30, 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	$	712	$	2	$	(23	)	$	691	$	774	$	11	$	(17	)	$	768
Equity securities	$	286	$	42	$	(1	)	$	327	$	254	$	40	$	—		$	294

⁽¹⁾ Excludes short-term cash investments of $57 million and $11 million in 2018 and 2017, respectively



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions)
Sale Proceeds	$	261		$	269		$	627		$	1,089
Realized Gains	3			20			31			70
Realized Losses	(7		)	(11		)	(34		)	(55		)
Interest and Dividend Income	11			9			31			28

Other Investments

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS



	September 30, 2018		December 31, 2017
	(In millions)
Carrying Value	$	17,796	$	19,296
Fair Value	$	18,761	$	21,412

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

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Derivative Instruments

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

DERIVATIVE INSTRUMENTS

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.

FirstEnergy has contractual derivative agreements through 2020.

Cash Flow Hedges

Refer to Note 6, "Accumulated Other Comprehensive Income," for reclassifications from AOCI during the three and nine months ended September 30, 2018 and 2017.

As of September 30, 2018, and December 31, 2017, no commodity or interest rate derivatives were designated as cash flow hedges.

Fair Value Hedges

NUGs

FTRs

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Capitalization	9 Months Ended
Capitalization	Sep. 30, 2018
Regulated Operations [Abstract]
CAPITALIZATION	CAPITALIZATION Stock Issuance On January 22, 2018, FirstEnergy entered into agreements for the private placement of its equity securities representing an approximately $2.5 billion investment in FE. FE entered into a Preferred Stock Purchase Agreement (the Preferred SPA) for the private placement of 1,616,000 shares of mandatorily convertible preferred stock, designated as the Series A Convertible Preferred Stock, par value $100 per share, representing an investment of nearly $1.62 billion ($162 million of mandatorily convertible preferred stock and $1.46 billion of OPIC). FE also entered into a Common Stock Purchase Agreement for the private placement of 30,120,482 shares of FE’s common stock, par value $0.10 per share, representing an investment of $850 million ($3 million of Common Stock and $847 million of OPIC). The Preferred Stock participates in dividends on the Common Stock on an as-converted basis based on the number of shares of Common Stock a holder of Preferred Stock would receive if its shares of Preferred Stock were converted on the dividend record date at the conversion price in effect at that time. Such dividends are paid at the same time that the dividends on Common Stock are paid. 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 September 30, 2018, the Conversion Price in effect remained $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 September 30, 2018, 911,411 preferred shares have been converted into 33,238,910 common shares at the option of the holders. 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 the Company 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 identified in the Preferred SPA 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.

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Asset Retirement Obligations	9 Months Ended
Asset Retirement Obligations	Sep. 30, 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. 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 the plants. 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. The aggregate ARO liabilities for FirstEnergy are approximately $630 million and $570 million as of September 30, 2018 and December 31, 2017, respectively. 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, effective October 12, 2018. 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.

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Regulatory Matters	9 Months Ended
Regulatory Matters	Sep. 30, 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. In addition, 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. Following the adoption of the Tax Act, various state regulatory proceedings have been initiated to investigate the impact of the Tax Act on the Utilities’ rates and charges. State proceedings that have arisen are discussed below. The Utilities continue to monitor and investigate the impact of state regulatory proceedings resulting from the Tax Act. MARYLAND PE provides SOS pursuant to a combination of settlement agreements, MDPSC orders and regulations, and statutory provisions. SOS supply is competitively procured in the form of rolling contracts of varying lengths through periodic auctions that are overseen by the MDPSC and a third-party monitor. Although settlements with respect to SOS supply for PE customers have expired, service continues in the same manner until changed by order of the MDPSC. PE recovers its costs plus a return for providing SOS. The Maryland legislature adopted a statute in 2008 codifying the EmPOWER Maryland goals to reduce electric consumption and demand and requiring each electric utility to file a plan every three years. On July 16, 2015, the MDPSC issued an order setting new incremental energy savings goals for 2017 and beyond, beginning with the goal of 0.97% savings achieved under PE's plan for 2016, and increasing 0.2% per year thereafter to reach 2%. The Maryland legislature in April 2017 adopted a statute requiring the same 0.2% per year increase, up to the ultimate goal of 2% annual savings, for the duration of the 2018-2020 and 2021-2023 EmPOWER Maryland program cycles, to the extent the MDPSC determines that cost-effective programs and services are available. PE's approved 2018-2020 EmPOWER Maryland plan continues and expands upon prior years' programs, and adds new programs, for a projected total cost of $116 million over the three-year period. On December 22, 2017, the MDPSC issued an order approving the 2018-2020 plan with various modifications. PE recovers program costs subject to a five-year amortization. Maryland law only allows for the utility to recover lost distribution revenue attributable to energy efficiency or demand reduction programs through a base rate case proceeding, and to date, such recovery has not been sought or obtained by PE. On February 27, 2013, the MDPSC issued an order requiring the Maryland electric utilities to submit analyses relating to the costs and benefits of making further system and staffing enhancements in order to attempt to reduce storm outage durations. PE's responsive filings discussed the steps needed to harden the utility's system in order to attempt to achieve various levels of storm response speed described in the February 2013 Order, and projected that it would require 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 the February 2013 Order. On July 1, 2014, the Staff of the MDPSC issued a set of reports that recommended the imposition of extensive additional requirements in the areas of storm response, feeder performance, estimates of restoration times, and regulatory reporting, as well as the imposition of penalties, including customer rebates, for a utility's failure or inability to comply with the escalating standards of storm restoration speed proposed by the Staff of the MDPSC. In addition, the Staff of the MDPSC proposed that Maryland utilities be required to develop and implement system hardening plans, up to a rate impact cap on cost. The MDPSC conducted a hearing September 15-18, 2014, to consider certain of these matters, and has not yet issued a ruling on any of those matters. On September 26, 2016, the MDPSC initiated a new 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. Comments were filed, and a hearing was held in late 2016. On January 31, 2017, the MDPSC issued a notice establishing five working groups to address these issues over the following eighteen months, and also directed the retention of an outside consultant to prepare a report on costs and benefits of distributed solar generation in Maryland. 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. If approved, PE will launch an electric vehicle charging infrastructure program on January 1, 2019, offering up to 2,000 rebates for electric vehicle charging equipment to residential customers, and deploying up to 259 chargers at non-residential customer service locations at a projected total cost of $12 million. PE is proposing to recover program costs subject to a five-year amortization. On February 6, 2018, the MDPSC opened a new proceeding to consider the petition and numerous parties filed comments on the petition on March 27, 2018. The MDPSC held hearings on the petition in May and September, 2018, after which parties filed final comments. 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 was required to 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 to PE's February 15, 2018 filing, in which reply the Staff recommended that the MDPSC 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 that PE further be directed to 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 PE estimates will be 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 requests an annual increase in base distribution rates of $19.7 million, plus creation of an Electric Distribution Investment surcharge to fund four enhanced service reliability programs. The increase is $7.3 million less than it otherwise would have been due to savings resulting from the recent federal tax law changes. The evidentiary hearing will commence on January 22, 2019, and a final order is expected by March 23, 2019. NEW JERSEY JCP&L currently provides BGS for retail customers who do not choose a third-party EGS and for customers of third-party EGSs that fail to provide the contracted service. The supply for BGS is comprised of two components, procured through separate, annually held descending clock auctions, the results of which are approved by the NJBPU. One BGS component reflects hourly real time energy prices and is available for larger commercial and industrial customers. The second BGS component provides a fixed price service and is intended for smaller commercial and residential customers. All New Jersey EDCs participate in this competitive BGS procurement process and recover BGS costs directly from customers as a charge separate from base rates. JCP&L currently operates under rates that were approved by the NJBPU on December 12, 2016, effective as of January 1, 2017. These rates provide an annual increase in operating revenues of approximately $80 million from those previously in place and are intended to improve service and benefit customers by supporting equipment maintenance, tree trimming, and inspections of lines, poles and substations, while also compensating for other business and operating expenses. 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. Pursuant to the NJBPU's March 26, 2015, final order in JCP&L's 2012 rate case proceeding directing that certain studies be completed, on July 22, 2015, the NJBPU approved the NJBPU staff's recommendation to implement such studies, which included operational and financial components. The independent consultant conducting the review issued a final report on July 27, 2016, recognizing that JCP&L is meeting the NJBPU requirements and making various operational and financial recommendations. The NJBPU issued an Order on August 24, 2016, that accepted the independent consultant’s final report and directed JCP&L, the Division of Rate Counsel and other interested parties to address the recommendations. In an Order issued October 22, 2014, in a generic proceeding to review its policies with respect to the use of a CTA in base rate cases, the NJBPU stated that it would continue to apply its current CTA policy in base rate cases, subject to incorporating the following modifications: (i) calculating savings using a five-year look back from the beginning of the test year; (ii) allocating savings with 75% retained by the company and 25% allocated to rate payers; and (iii) excluding transmission assets of electric distribution companies in the savings calculation. On November 5, 2014, the Division of Rate Counsel appealed the NJBPU Order regarding the generic CTA proceeding to the Superior Court of New Jersey Appellate Division and JCP&L filed to participate as a respondent in that proceeding supporting the order. On September 18, 2017, the Superior Court of New Jersey Appellate Division reversed the NJBPU's Order on the basis that the NJBPU's modification of its CTA methodology did not comply with the procedures of the NJAPA. JCP&L's existing rates are not expected to be impacted by this order. On December 19, 2017, the NJBPU approved the issuance of proposed rules to modify the CTA methodology consistent with its October 22, 2014, Generic Order, which were published in the NJ Register on January 16, 2018, and republished on February 6, 2018, to correct an error. JCP&L filed comments supporting the proposed rulemaking on April 6, 2018. At the December 19, 2017, NJBPU public meeting, 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. JCP&L requested that the NJBPU issue a final order in December 2018. On August 29, 2018, the NJBPU retained the petition for hearing. 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, but may be addressed at a later date. OHIO The Ohio Companies currently operate under ESP IV which commenced June 1, 2016 and expires May 31, 2024. The material terms of ESP IV, as approved in the PUCO’s Opinion and Order issued on March 31, 2016 and Fifth Entry on Rehearing on October 12, 2016, include 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. Rider DMR will be 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. 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 from June 1, 2016 through May 31, 2019; $20 million per year from June 1, 2019 through May 31, 2022; and $15 million per year from June 1, 2022 through May 31, 2024. Other material terms of ESP IV include: (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 filing was made on February 29, 2016, and remains pending); (3) a goal across FirstEnergy to reduce CO₂ emissions by 90% below 2005 levels by 2045; (4) contributions, totaling $51 million to: (a) fund energy conservation programs, economic development and job retention in the Ohio Companies’ service territories; (b) establish a fuel-fund in each of the Ohio Companies’ service territories to assist low-income customers; and (c) establish a Customer Advisory Agency 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 was made on April 3, 2017, and which 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. The Ohio Companies’ application for rehearing challenged, among other things, the PUCO’s failure to adopt the Ohio Companies’ suggested modifications to Rider DMR. The Ohio Companies had previously suggested that a properly designed Rider DMR would be valued at $558 million annually for eight years, and include an additional amount that recognizes the value of the economic impact of FirstEnergy maintaining its headquarters in Ohio. Other parties’ applications for rehearing argued, among other things, that the PUCO’s adoption of Rider DMR is not supported by law or sufficient evidence. 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. On September 15, 2017, the Ohio Companies 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. On October 11, 2017, the PUCO denied the Ohio Companies' application for rehearing on both issues. On October 16, 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. On November 16, 2017, the Ohio Companies intervened in the appeal. Additional parties subsequently filed notices of appeal with the Supreme Court of Ohio challenging various PUCO entries on their applications for rehearing. On February 26, 2018, appellants filed their briefs. Briefs of the PUCO and the Ohio Companies were filed on May 29, 2018. On July 9, 2018, appellants filed their reply briefs. 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 is scheduled for January 9, 2019. Under ORC 4928.66, the Ohio Companies are required to implement energy efficiency programs that achieve certain annual energy savings and total peak demand reductions. Starting in 2017, ORC 4928.66 requires the energy savings benchmark to increase by 1% and the peak demand reduction benchmark to increase by 0.75% annually thereafter through 2020 and the energy savings benchmark to increase by 2% annually from 2021 through 2027, with a cumulative benchmark of 22.2% by 2027. On April 15, 2016, the Ohio Companies filed an application for approval of their three-year energy efficiency portfolio plans for the period from January 1, 2017 through December 31, 2019. The plans as proposed comply with benchmarks contemplated by ORC 4928.66 and provisions of the ESP IV, and include a portfolio of energy efficiency programs targeted to a variety of customer segments, including residential customers, low income customers, small commercial customers, large commercial and industrial customers and governmental entities. On December 9, 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 filed Stipulation and Recommendation 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 as reported on 2015 FERC Form 1. On December 21, 2017, the Ohio Companies filed an application for rehearing challenging the PUCO’s modification of the Stipulation and Recommendation to include the 4% cost cap, which was denied by the PUCO on January 10, 2018. On March 12, 2018, the Ohio Companies filed a Notice of Appeal with the Supreme Court of Ohio challenging the PUCO’s imposition of a 4% cost cap. Various other parties also filed Notices of Appeal challenging various PUCO entries on their applications for rehearing. The Ohio Companies filed their brief on May 21, 2018. The PUCO filed its brief on July 30, 2018, and the Ohio Companies filed their reply brief on September 10, 2018. 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 amount through 2026, except that in 2014 SB310 froze 2015 and 2016 requirements at the 2014 level (2.5%), pushing back scheduled increases, which resumed in 2017 (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. The PUCO issued an Opinion and Order on August 7, 2013, approving the Ohio Companies' acquisition process and their purchases of RECs to meet statutory mandates in all instances except for certain purchases arising from one auction and directed the Ohio Companies to credit non-shopping customers in the amount of $43.4 million, plus interest, on the basis that the Ohio Companies did not prove such purchases were prudent. On December 24, 2013, following the denial of their application for rehearing, the Ohio Companies filed a Notice of Appeal and a motion for stay of the PUCO's order with the Supreme Court of Ohio, which was granted. The OCC and the ELPC also filed appeals of the PUCO's order. On January 24, 2018, the Supreme Court of Ohio reversed the PUCO order finding that the order violated the rule against retroactive ratemaking. On February 5, 2018, the OCC and ELPC filed a motion for reconsideration, to which the Ohio Companies responded in opposition on February 15, 2018. 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. The Ohio Companies have requested that the PUCO issue an order approving the DPM Plan and associated cost recovery so that the Ohio Companies can expeditiously commence the DPM Plan and customers can begin to realize the associated benefits. 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. The Ohio Companies filed reply comments on March 7, 2018. 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. PENNSYLVANIA 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. On December 11, 2017, the Pennsylvania Companies filed DSPs for the June 1, 2019 through May 31, 2023 delivery period. Under the 2019-2023 DSPs, the supply is proposed to 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 as proposed also include modifications to the Pennsylvania Companies’ POR programs in order to continue their clawback pilot program as a long-term, permanent program. The 2019-2023 DSPs also introduce a retail market enhancement rate mechanism designed to stimulate residential customer shopping, 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. A hearing was held on April 10, 2018, and the ALJ issued a recommended decision dated May 31, 2018. The decision recommended approval of the Pennsylvania Companies' DSPs as originally proposed with two exceptions: it recommended rejecting the proposed retail market enhancement rate mechanism, and establishing limitations on customer assistance program customers' shopping. Exceptions were filed by two parties on June 28, 2018, to which the Pennsylvania Companies filed reply exceptions on July 9, 2018. On September 4, 2018, the PPUC issued an order approving the Pennsylvania Companies' DSPs and 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. The Pennsylvania Companies and two other parties filed petitions for reconsideration to that order on the limited issue of timing and scope of the working group discussion related to customer assistance program shopping limitations, which are pending PPUC review at this time. The Pennsylvania Companies operate under rates that were approved by the PPUC on January 19, 2017, effective as of January 27, 2017. These rates provide annual increases in operating revenues of approximately $96 million at ME, $100 million at PN, $29 million at Penn, and $66 million at WP, and are intended to benefit customers by modernizing the grid with smart technologies, increasing vegetation management activities, and continuing other customer service enhancements. 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. On June 19, 2015, the PPUC issued a Phase III Final Implementation Order setting: demand reduction targets, relative to each Pennsylvania Companies' 2007-2008 peak demand (in MW), at 1.8% for ME, 1.7% for Penn, 1.8% for WP, and 0% for PN; and energy consumption reduction targets, as a percentage of each Pennsylvania Companies’ historic 2010 forecasts (in MWH), at 4.0% for ME, 3.9% for PN, 3.3% for Penn, and 2.6% for WP. 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. Pursuant to Act 11 of 2012, Pennsylvania EDCs may establish a DSIC to recover costs of infrastructure improvements and costs related to highway relocation projects with PPUC approval. Pennsylvania EDCs must file LTIIPs outlining infrastructure improvement plans for PPUC review and approval prior to approval of a DSIC. On February 11, 2016, the PPUC approved LTIIPs for each of the Pennsylvania Companies. 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. The LTIIPs estimated costs for the remaining period of 2018 to 2020 are: WP $50.1 million; PN $44.8 million; Penn $33.2 million; and ME $51.3 million. On April 10, 2018, the PPUC notified each of the Pennsylvania Companies that the PPUC was initiating a review of the LTIIPs as required by regulation once every five years, and soliciting comments from interested parties. On May 10, 2018, the Pennsylvania Companies each filed comments explaining that their LTIIPs are effective and that changes to the respective LTIIPs are not necessary. No parties other than the Pennsylvania Companies filed comments. On September 20, 2018, 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. The PPUC directed the Pennsylvania Companies to file modified or new LTIIPs within 60 days of the Order; however, on October 17, 2018, the Pennsylvania Companies requested a 60-day extension to file the new or modified LTIIPs. On February 16, 2016, the Pennsylvania Companies filed riders for PPUC approval for quarterly cost recovery, which were approved by the PPUC on June 9, 2016, and went into effect July 1, 2016, subject to hearings and refund or reallocation among customer classes. On January 19, 2017, in the PPUC’s 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 August 31, 2017, the ALJ issued a decision recommending that the complaint of the Pennsylvania OCA be granted by the PPUC such that the Pennsylvania Companies reflect all federal and state income tax deductions related to DSIC-eligible property in the currently effective DSIC rates. On April 19, 2018, the PPUC approved the Joint Settlement without modification and reversed the ALJ's 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 Commonwealth Court. 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 June1, 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 is expected to return to customers $19 million for ME, $20 million for PN, $5 million for Penn, and $15 million for WP. WEST VIRGINIA MP and PE provide electric service to all customers through traditional cost-based, regulated utility ratemaking. MP and PE recover net power supply costs, including fuel costs, purchased power costs and related expenses, net of related market sales revenue through the ENEC. MP's and PE's ENEC rate is updated annually. 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 includes 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 includes 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. Hearings before the WVPSC are scheduled for November 27 and 28, 2018. 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. FERC MATTERS 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, AE Supply, ATSI, MAIT and TrAIL. NERC is the ERO designated by FERC to establish and enforce these reliability standards, although NERC has delegated day-to-day implementation and enforcement of these reliability standards 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 extensive electric utility systems and facilities, FirstEnergy occasionally learns of isolated facts or circumstances that could be interpreted as excursions from the reliability standards. If and when such occurrences are found, FirstEnergy develops information about the occurrence and develops a remedial response to the specific circumstances, including in appropriate cases “self-reporting” an occurrence to RFC. Moreover, it is clear that NERC, RFC and FERC will continue to refine existing reliability standards as well as to develop and adopt new reliability standards. Any inability on FirstEnergy's part to comply with the reliability standards for its bulk electric system could result in the imposition of financial penalties, or obligations to upgrade or build transmission facilities, that could have a material adverse effect on its financial condition, results of operations and cash flows. PJM Transmission Rates PJM and its stakeholders have been debating the proper method to allocate costs for a certain class of new transmission facilities since 2005. While FirstEnergy and other parties advocate for a traditional "beneficiary pays" (or usage based) approach, others advocate for “socializing” the costs on a load-ratio share basis, where each customer in the zone would pay based on its total usage of energy within PJM. This question has been the subject of extensive litigation before FERC and the appellate courts, including before the Seventh Circuit. On June 25, 2014, a divided three-judge panel of the Seventh Circuit ruled that FERC had not quantified the benefits that western PJM utilities would derive from certain new 500 kV or higher lines and thus had not adequately supported its decision to socialize the costs of these lines. The majority found that eastern PJM utilities are the primary beneficiaries of the lines, while western PJM utilities are only incidental beneficiaries, and that, while incidental beneficiaries should pay some share of the costs of the lines, that share should be proportionate to the benefit they derive from the lines, and not on load-ratio share in PJM as a whole. The court remanded the case to FERC, which issued an order setting the issue of cost allocation for hearing and settlement proceedings. On June 15, 2016, various parties, including ATSI and the Utilities, filed a settlement agreement at FERC agreeing to apply a combined usage based/socialization approach to cost allocation for charges to transmission customers in the PJM Region for transmission projects operating at or above 500 kV. For historical transmission costs prior to January 1, 2016, the settlement agreement provides a “black-box” schedule of credits to and payments from customers across PJM’s transmission zones. From January 1, 2016 forward, PJM will collect a charge for the revenue requirement associated with each transmission enhancement through a “50/50” calculation, with 50% based on a load-ratio share and the other 50% solution-based distribution factor (DFAX) hybrid method. On May 31, 2018, FERC approved the settlement agreement as filed, without conditions. As a result of the settlement, FirstEnergy recorded a pre-tax benefit of approximately $73 million and $42 million during the second and third quarters, respectively (within the Other operating expenses line on the Consolidated Statement of Income), relating to the amount of refund the Ohio Companies will receive and retain from PJM for the period prior to January 1, 2016. PJM implemented the settlement for transmission service purchased in July 2018 in customer bills beginning in August 2018. FirstEnergy does not expect a material impact from implementation of the settlement agreement going forward. Requests for rehearing or clarification of FERC's May 31, 2018, orders and related responses remain pending before FERC. RTO Realignment On June 1, 2011, ATSI and the ATSI zone transferred from MISO to PJM. While many of the matters involved with the move have been resolved, FERC denied recovery under ATSI's transmission rate for certain charges that collectively can be described as "exit fees" and certain other transmission cost allocation charges totaling approximately $78.8 million until such time as ATSI submits a cost/benefit analysis demonstrating net benefits to customers from the transfer to PJM. Subsequently, FERC rejected a proposed settlement agreement to resolve the exit fee and transmission cost allocation issues, stating that its action is without prejudice to ATSI submitting a cost/benefit analysis demonstrating that the benefits of the RTO realignment decisions outweigh the exit fee and transmission cost allocation charges. On March 17, 2016, FERC denied FirstEnergy's request for rehearing of FERC's earlier order rejecting the settlement agreement and affirmed its prior ruling that ATSI must submit the cost/benefit analysis. Separately, FirstEnergy joined certain other PJM TOs in a protest of MISO's proposal to allocate MVP costs to energy transactions that cross MISO's borders into the PJM Region. On July 13, 2016, FERC issued its order finding it appropriate for MISO to assess an MVP usage charge for power withdrawals from MISO to PJM. Various parties, including FirstEnergy and the PJM TOs, requested rehearing or clarification of FERC’s order. On September 20, 2018, FERC issued an order denying rehearing and affirming and clarifying its prior decision that MISO may allocate MVP costs to PJM customers for power withdrawals from MISO to PJM as such exports occur. The outcome of the proceedings that address the remaining open issues related to MVP costs cannot be predicted at this time. PATH Transmission Project In 2012, the PJM Board of Managers canceled the PATH project, a proposed transmission line from West Virginia through Virginia and into Maryland. As a result of PJM canceling the project, approximately $62 million and approximately $59 million in costs incurred by PATH-Allegheny and PATH-WV, respectively, were reclassified from net property, plant and equipment to a regulatory asset for future recovery. PATH-Allegheny and PATH-WV requested authorization from FERC to recover the costs with a proposed ROE of 10.9% (10.4% base plus 0.5% for RTO membership) from PJM customers over five years. FERC issued an order denying the 0.5% ROE adder for RTO membership and allowing the tariff changes enabling recovery of these costs to become effective on December 1, 2012, subject to hearing and settlement procedures. On January 19, 2017, FERC issued an order reducing the PATH formula rate ROE from 10.4% to 8.11% effective January 19, 2017 and allowing recovery of certain related costs. On February 21, 2017, PATH filed a request for rehearing with FERC seeking recovery of disallowed costs and requesting that the ROE be reset to 10.4% for the entire amortization period. The Edison Electric Institute submitted an amicus curiae request for reconsideration in support of PATH. On March 20, 2017, PATH also submitted a compliance filing implementing the January 19, 2017 order. Certain affected ratepayers challenged the compliance filing, and FERC Staff requested additional information on, and edits to, the compliance filing, as directed by the January 19, 2017 order. PATH responded to comments and Staff’s request. FERC orders on PATH's requests for rehearing and compliance filing remain pending. FERC Actions on Tax Act On March 15, 2018, FERC took action to address the impact of the Tax Act on FERC-jurisdictional rates, including transmission and electric wholesale rates. FERC directed MP, PE and WP to either submit a joint filing to adjust the transmission rate for the Allegheny Power transmission zone in the PJM Region to address the impact of the Tax Act changes in effective tax rate, or to “show cause” as to why such action is not required. FERC established a refund effective date of March 21, 2018 for any refunds as a result of the change in tax rate. On May 14, 2018, MP, PE and WP submitted revisions to their joint stated transmission rate to reflect the reduction in the federal corporate income tax rate. The revisions reduce the rate by 6.70%. There were no comments submitted in response to the proposed revisions, and the matter is now before FERC for further action. FERC is not at this time requiring other FirstEnergy FERC-jurisdictional companies to make changes to their transmission or wholesale rates. However, these rates may be affected by a related FERC "Notice of Inquiry" assessing the impact of the Tax Act on certain rate components. Also, on March 15, 2018, FERC issued a Notice of Inquiry seeking information regarding whether and how FERC should address possible changes to accumulated deferred income taxes and bonus depreciation as a result of the Tax Act. Such possible changes could impact FERC-jurisdictional rates, including wholesale rates. Various entities submitted responses to the Notice of Inquiry. FESC, on behalf of its transmission-owning affiliates, participated in the development of separate comments submitted by Edison Electric Institute and certain PJM TOs. The matter is now before FERC for further action. PJM Markets: Grid Reliability and Resiliency On September 28, 2017, the Secretary of Energy released a NOPR requesting FERC to issue rules directing RTOs, including PJM, to incorporate pricing for defined “eligible grid reliability and resiliency resources” into wholesale energy markets. FERC established a docket requesting comments, and issued an order on January 8, 2018 terminating the NOPR proceeding, finding that the NOPR did not satisfy the statutory threshold requirements under the FPA for requiring changes to RTO/ISO tariffs to address resilience concerns. FERC in its order instituted a new administrative proceeding to gather additional information regarding resilience issues. Each RTO/ISO responded to a provided list of questions and various entities submitted comments. The matter is now before FERC for further action. In the event FERC orders resiliency payments in wholesale energy markets, such charges may be levied against LSEs in the PJM Region, including the Utilities. There is no deadline or requirement for FERC to act in this new proceeding and as such the outcome of the proceeding and its impact on the Utilities, if any, cannot be predicted at this time. PJM Markets: Capacity Pricing Reform In March 2016, a number of generation owners filed with FERC a complaint against PJM requesting that FERC expand the MOPR in the PJM Tariff to prevent the alleged artificial suppression of prices in PJM capacity markets by state-subsidized generation. However, FERC took no action at that time. In April 2018, PJM filed with FERC two alternative proposals to modify the PJM Tariff to address concerns that state-authorized subsidies to certain generators within PJM may affect market prices. On June 29, 2018, FERC issued an order granting in part and denying in part the March 2016 complaint and rejecting both of PJM's April 2018 proposals, agreeing with the complaint that PJM's current MOPR is unjust and unreasonable and finding that none of the proposed solutions to MOPR reform were just and reasonable and not unduly discriminatory. FERC established a new FPA Section 206 proceeding to develop a solution to the MOPR construct. FERC's directives in the new proceeding are to revise the MOPR so that it (i) applies to both existing and new resources that receive out-of-market subsidies with very limited exemptions; and (ii) accommodates state policies by allowing a new FRR-like alternative that would remove resources that receive out-of-market subsidies from the capacity market if the unit could be paired with a commensurate amount of load. Resources receiving out-of-market revenues could opt to stay in the capacity market but would be subject to the revised MOPR, or under the FRR-like alternative they could exit the market. FERC established a timeline for comments and expects to issue an order by January 4, 2019, so that the reformed MOPR can be implemented for the 2019 BRA. FERC instituted a refund effective date of July 11, 2018, for the new Section 206 proceeding. On July 30, 2018 FESC, on behalf of the Utilities, submitted a request for clarification or, in the alternative, rehearing of FERC's June 29, 2018 order. Specifically, FESC requested clarification regarding the applicability of FERC's directed MOPR reform to vertically-integrated resources. Various other parties also submitted requests for rehearing or clarification. FERC's order on rehearing remains pending. On October 2, 2018, FESC on behalf of the Utilities submitted comments demonstrating that while MOPR reform may be an interim step, FERC needs to address fundamental flaws in the PJM capacity market. On August 13, 2018, PJM filed a request for a waiver of certain provisions of the PJM Tariff to delay the 2019 BRA for the 2022/2023 Delivery Year from May 2019 to August 14, 2019 if FERC delays its order in the above Section 206 proceeding as requested by certain parties. PJM also requested waiver of certain deadlines associated with the 2019 BRA, including the posting of planning parameters and submission of a preliminary exception request for deactivating generation resources. FERC issued an order on August 30, 2018 granting the waiver as requested. Separately, on May 31, 2018, certain merchant generators filed a complaint with FERC against PJM seeking an order finding that PJM's existing MOPR mechanism is unjust and unreasonable, and implementing instead a so-called "Clean" MOPR that would apply to existing and new generation resources of all fuel types and all ownership arrangements, including regulated generation resources such as MP's and JCP&L's existing generation, that receive or have any form of "out-of-market" support, including recovery of generation costs in retail rates. The complainants request a FERC order by May 2019, so that the proposed "Clean" MOPR could be implemented in PJM's 2019 BRA. FESC, on behalf of its affiliates and jointly with EKPC, submitted a protest of the complaint. FESC and EKPC requested FERC reject PJM's proposals, maintain the existing PJM market rules, and direct PJM to develop a holistic solution to the fundamental issues facing its market. Various other entities also submitted protests and comments. FERC did not address the Clean MOPR Complaint in its June 29, 2018 order, which remains pending before FERC. The outcome of FERC's Section 206 proceeding and the Clean MOPR Complaint, and their impact on the Utilities and FirstEnergy's regulated generation sources, if any, cannot be predicted at this time but are not expected to be material.

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Commitments, Guarantees and Contingencies

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

COMMITMENTS, GUARANTEES AND CONTINGENCIES

GUARANTEES AND OTHER ASSURANCES

COLLATERAL AND CONTINGENT-RELATED FEATURES



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		—		54		—		54
Surety Bonds (Collateralized Amount)		1		60		246		307
Total Exposure from Contractual Obligations		$	2	$	114	$	246	$	362

OTHER COMMITMENTS AND CONTINGENCIES

ENVIRONMENTAL MATTERS

Clean Air Act

Climate Change

Clean Water Act

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

OTHER LEGAL PROCEEDINGS

Nuclear Plant Matters

FES Bankruptcy

Other Legal Matters

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Segment Information

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

SEGMENT INFORMATION

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

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

Financial information for each of FirstEnergy's reportable segments is presented in the tables below.

Segment Financial Information



For the Three Months Ended	Regulated Distribution			Regulated Transmission		Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)

September 30, 2018
Revenues	$	2,766		$	346	$	6		$	(54	)	$	3,064
Depreciation	202			64		1			16			283
Amortization of regulatory assets, net	65			2		—			—			67
Miscellaneous income (expense), net	34			4		19			(8		)	49
Interest expense	127			43		93			(8		)	255
Income taxes (benefits)	126			34		(27		)	—			133
Income (loss) from continuing operations	416			99		(128		)	—			387
Total assets	28,530			10,017		896			—			39,443
Total goodwill	5,004			614		—			—			5,618
Property additions	356			262		5			12			635

September 30, 2017
Revenues	$	2,609		$	341	$	10		$	(50	)	$	2,910
Depreciation	183			59		2			17			261
Amortization of regulatory assets, net	107			6		—			—			113
Impairment of assets	—			13		—			—			13
Miscellaneous income (expense), net	16			1		15			(13		)	19
Interest expense	133			38		104			(13		)	262
Income taxes (benefits)	183			49		(30		)	—			202
Income (loss) from continuing operations	314			84		(97		)	—			301
Total assets	27,866			9,356		938			5,489			43,649
Total goodwill	5,004			614		—			—			5,618
Property additions	286			248		14			45			593

For the Nine Months Ended

September 30, 2018
Revenues	$	7,694		$	1,010	$	28		$	(181	)	$	8,551
Depreciation	598			187		6			52			843
Amortization (deferral) of regulatory assets, net	(194		)	6		—			—			(188		)
Miscellaneous income (expense), net	146			11		34			(27		)	164
Interest expense	384			124		377			(27		)	858
Income taxes	357			104		42			—			503
Income (loss) from continuing operations	1,115			302		(577		)	—			840
Property additions	1,011			836		68			27			1,942

September 30, 2017
Revenues	$	7,380		$	981	$	37		$	(151	)	$	8,247
Depreciation	540			164		9			52			765
Amortization of regulatory assets, net	263			11		—			—			274
Impairment of assets	—			13		—			—			13
Miscellaneous income (expense), net	45			1		31			(33		)	44
Interest expense	405			116		263			(33		)	751
Income taxes (benefits)	442			154		(113		)	—			483
Income (loss) from continuing operations	756			264		(248		)	—			772
Property additions	854			717		43			233			1,847

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Organization and Basis of Presentation (Policies)

9 Months Ended

Sep. 30, 2018

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Accounting

Consolidation Policy

New Accounting Pronouncements

Recently Adopted Pronouncements

Earnings Per Share


•	preferred share 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 shares and the participating securities (convertible Preferred Stock) based on their respective rights to receive dividends.

Variable Interest Entities

Investment Policy

Long-Term Debt and Other Long-Term Obligations

LONG-TERM DEBT AND OTHER LONG-TERM OBLIGATIONS

Derivatives Instruments Policy

FirstEnergy accounts for derivative instruments on its Consolidated Balance Sheets at fair value (unless they meet the normal purchases and normal sales criteria) as follows:


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


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


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

- Definition

Disclosure of accounting policy for investments in financial assets, including marketable securities (debt and equity securities with readily determinable fair values), investments accounted for under the equity method and cost method, securities borrowed and loaned, and repurchase and resale agreements. For marketable securities, the disclosure may include the entity's accounting treatment for transfers between investment categories and how the fair values for such securities are determined. Also, for all investments, an entity may describe its policy for assessing, recognizing and measuring impairment of the investment.

+ References + Details

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Revenue (Tables)

9 Months Ended

Sep. 30, 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 three and nine months ended September 30, 2018, by transmission owner:



	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
Revenues from Contracts with Customers by Transmission Asset Owner	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(In millions)
ATSI	$	167	$	492
TrAIL	60		183
MAIT	43		106
Other	71		215
Total Revenues	$	341	$	996



	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
Revenues by Customer Class	For the Three Months Ended September 30, 2018		For the Nine Months Ended September 30, 2018
	(In millions)
Residential	$	1,572	$	4,290
Commercial	628		1,778
Industrial	276		792
Other	23		70
Total Revenues	$	2,499	$	6,930

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



	For the Three Months Ended September 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments ⁽¹⁾			Total
	(In millions)
Distribution services⁽²⁾	$	1,440	$	—	$	(22	)	$	1,418
Retail generation	1,059		—		(14		)	1,045
Wholesale sales⁽²⁾	133		—		6			139
Transmission⁽²⁾	—		341		—			341
Other	43		—		—			43
Total revenues from contracts with customers	$	2,675	$	341	$	(30	)	$	2,986
ARP	66		—		—			66
Other non-customer revenue	25		5		(18		)	12
Total revenues	$	2,766	$	346	$	(48	)	$	3,064

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



	For the Nine Months Ended September 30, 2018
Revenues by Type of Service	Regulated Distribution		Regulated Transmission		Corporate/Other and Reconciling Adjustments⁽¹⁾			Total
	(In millions)
Distribution services⁽²⁾	$	3,949	$	—	$	(81	)	$	3,868
Retail generation	2,981		—		(42		)	2,939
Wholesale sales⁽²⁾	377		—		16			393
Transmission⁽²⁾	—		996		—			996
Other	113		—		4			117
Total revenues from contracts with customers	$	7,420	$	996	$	(103	)	$	8,313
ARP	190		—		—			190
Other non-customer revenue	84		14		(50		)	48
Total revenues	$	7,694	$	1,010	$	(153	)	$	8,551

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

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Discontinued Operations (Tables)

9 Months Ended

Sep. 30, 2018

Discontinued Operations and Disposal Groups [Abstract]

Disposal Groups, Including Discontinued Operations

Summarized results of discontinued operations for the three and nine months ended September 30, 2018 and 2017, were as follows:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
(In millions)	2018			2017			2018			2017

Revenues	$	83		$	788		$	934		$	2,299
Fuel	(52		)	(237		)	(269		)	(671		)
Purchased power	—			(66		)	(85		)	(189		)
Other operating expenses	(24		)	(290		)	(414		)	(1,097		)
Provision for depreciation	(18		)	(28		)	(96		)	(80		)
General taxes	(4		)	(15		)	(32		)	(74		)
Impairment of assets	—			(18		)	—			(149		)
Other expense, net	(1		)	(2		)	(82		)	(37		)
Income (Loss) from discontinued operations, before tax	(16		)	132			(44		)	2
Income tax expense (benefit)⁽¹⁾	(5		)	37			(9		)	(1		)
Income (Loss) from discontinued operations, net of tax	(11		)	95			(35		)	3
Gain (Loss) on disposal of FES and FENOC, net of tax	(834		)	—			405			—
Income (Loss) from discontinued operations	$	(845	)	$	95		$	370		$	3

The gain (loss) on disposal that was recognized in the three and nine months ended September 30, 2018, consisted of the following:



(In millions)	For the Three Months Ended September 30, 2018			For the Nine Months Ended September 30, 2018
Removal of investment in FES and FENOC	$	—		$	2,193
Assumption of benefit obligations retained at FE	—			(820		)
Guarantees and credit support provided by FE	—			(139		)
Reserve on receivables and allocated Pension/OPEB mark-to-market	—			(914		)
Settlement Consideration and Services Credit	(1,183		)	(1,183		)
Loss on disposal of FES and FENOC, before tax	(1,183		)	(863		)
Income tax benefit, including estimated worthless stock deduction	349			1,268
Gain (Loss) on disposal of FES and FENOC, net of tax	$	(834	)	$	405

The following table summarizes the major classes of assets and liabilities as discontinued operations as of September 30, 2018, and December 31, 2017:



(In millions)	September 30, 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	17		227
Prepaid taxes and other	—		199
Total current assets	17		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	$	17	$	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.



	For the Nine Months Ended September 30,
(In millions)	2018			2017

CASH FLOWS FROM OPERATING ACTIVITIES:
Income from discontinued operations	$	370		$	3
Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs	110			245
Unrealized (gain) loss on derivative transactions	(15		)	64

CASH FLOWS FROM INVESTING ACTIVITIES:
Property additions	(27		)	(233		)
Nuclear fuel	—			(156		)
Sales of investment securities held in trusts	109			834
Purchases of investment securities held in trusts	(122		)	(878		)

- Definition

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

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Earnings Per Share Of Common Stock (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Reconciliation of Basic and Diluted Earnings Per Share

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



	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
Reconciliation of Basic and Diluted EPS of Common Stock	2018			2017		2018			2017

(In millions, except per share amounts)
EPS of Common Stock
Income from continuing operations	$	387		$	301	$	840		$	772
Less: Preferred dividends	(19		)	—		(61		)	—
Less: Amortization of beneficial conversion feature	(35		)	—		(296		)	—
Less: Undistributed earnings allocated to preferred stockholders⁽¹⁾	—			—		—			—
Income from continuing operations available to common stockholders	333			301		483			772
Discontinued operations, net of tax	(845		)	95		370			3
Less: Undistributed earnings allocated to preferred stockholders ⁽¹⁾	—			—		—			—
Income (loss) from discontinued operations available to common stockholders	(845		)	95		370			3

Income (loss) available to common stockholders, basic and diluted	$	(512	)	$	396	$	853		$	775

Share Count information:
Weighted average number of basic shares outstanding	503			444		485			444
Assumed exercise of dilutive stock options and awards	2			2		2			1
Weighted average number of diluted shares outstanding	505			446		487			445

Income (loss) available to common stockholders, per common share:
Income from continuing operations, basic	$	0.66		$	0.68	$	1.00		$	1.74
Discontinued operations, basic	(1.68		)	0.21		0.76			0.01
Income (loss) available to common stockholders, basic	$	(1.02	)	$	0.89	$	1.76		$	1.75

Income from continuing operations, diluted	$	0.66		$	0.68	$	0.99		$	1.73
Discontinued operations, diluted	(1.68		)	0.21		0.76			0.01
Income (loss) available to common stockholders, diluted	$	(1.02	)	$	0.89	$	1.75		$	1.74


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

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Pension and Other Postemployment Benefits (Tables)

9 Months Ended

Sep. 30, 2018

Retirement Benefits [Abstract]

Components of Net Periodic Benefit Costs

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



Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Three Months Ended September 30,	2018			2017			2018			2017
	(In millions)
Service costs	$	56		$	52		$	1		$	1
Interest costs	93			97			6			7
Expected return on plan assets	(144		)	(112		)	(7		)	(7		)
Amortization of prior service costs (credits)	2			2			(20		)	(20		)
Special termination costs	21			—			6			—
Net periodic costs (credits), including amounts capitalized	$	28		$	39		$	(14	)	$	(19	)
Net periodic costs (credits), recognized in earnings	$	5		$	30		$	(15	)	$	(14	)


Components of Net Periodic Benefit Costs (Credits)	Pension						OPEB
For the Nine Months Ended September 30,	2018			2017			2018			2017
	(In millions)
Service costs	$	168		$	156		$	3		$	3
Interest costs	279			291			18			21
Expected return on plan assets	(432		)	(336		)	(22		)	(22		)
Amortization of prior service costs (credits)	6			6			(60		)	(60		)
Special termination costs	21			—			6			—
Net periodic costs (credits), including amounts capitalized	$	42		$	117		$	(55	)	$	(58	)
Net periodic costs (credits), recognized in earnings	$	(27	)	$	89		$	(57	)	$	(43	)

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Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income

The changes in AOCI, net of tax, in the three and nine months ended September 30, 2018 and 2017, for FirstEnergy are included in the following tables:



	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI balance as of July 1, 2018	$	(14	)	$	—		$	87		$	73

Amounts reclassified from AOCI^{(1) (2)}	2			—			(18		)	(16		)
Other comprehensive income (loss)	2			—			(18		)	(16		)
Income tax benefits on other comprehensive income (loss)	—			—			(4		)	(4		)
Other comprehensive income (loss), net of tax	2			—			(14		)	(12		)

AOCI Balance as of September 30, 2018	$	(12	)	$	—		$	73		$	61

AOCI balance as of July 1, 2017	$	(26	)	$	61		$	128		$	163

Other comprehensive income before reclassifications	—			27			—			27
Amounts reclassified from AOCI^{(1) (2)}	4			(33		)	(19		)	(48		)
Other comprehensive income (loss)	4			(6		)	(19		)	(21		)
Income taxes (benefits) on other comprehensive income (loss)	1			(3		)	(7		)	(9		)
Other comprehensive income (loss), net of tax	3			(3		)	(12		)	(12		)

AOCI Balance as of September 30, 2017	$	(23	)	$	58		$	116		$	151

	Gains & Losses on Cash Flow Hedges			Unrealized Gains on AFS Securities			Defined Benefit Pension & OPEB Plans			Total
	(In millions)
AOCI Balance as of January 1, 2018	$	(22	)	$	67		$	97		$	142

Other comprehensive income before reclassifications	—			(97		)	—			(97		)
Amounts reclassified from AOCI^{(1) (2) (3)}	6			(1		)	(55		)	(50		)
Deconsolidation of FES and FENOC	13			(8		)	—			5
Other comprehensive income (loss)	19			(106		)	(55		)	(142		)
Income taxes (benefits) on other comprehensive income (loss)	9			(39		)	(31		)	(61		)
Other comprehensive income (loss), net of tax	10			(67		)	(24		)	(81		)

AOCI Balance as of September 30, 2018	$	(12	)	$	—		$	73		$	61

AOCI Balance as of January 1, 2017	$	(28	)	$	52		$	150		$	174

Other comprehensive income before reclassifications	—			63			—			63
Amounts reclassified from AOCI^{(1) (2)}	8			(55		)	(55		)	(102		)
Other comprehensive income (loss)	8			8			(55		)	(39		)
Income taxes (benefits) on other comprehensive income (loss)	3			2			(21		)	(16		)
Other comprehensive income (loss), net of tax	5			6			(34		)	(23		)

AOCI Balance as of September 30, 2017	$	(23	)	$	58		$	116		$	151

⁽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".

Reclassification out of Accumulated Other Comprehensive Income

The following amounts were reclassified from AOCI for FirstEnergy in the three and nine months ended September 30, 2018 and 2017:



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						Affected Line Item in the Consolidated Statements of Income (Loss)
Reclassifications from AOCI⁽¹⁾	2018			2017			2018 ⁽³⁾			2017
	(In millions)
Gains & losses on cash flow hedges
Long-term debt	$	2		$	4		$	6		$	8		Interest expense
	—			(1		)	(1		)	(3		)	Income taxes
	$	2		$	3		$	5		$	5		Net of tax

Unrealized gains on AFS securities
Realized gains on sales of securities	$	—		$	(21	)	$	(1	)	$	(35	)	Discontinued Operations

Defined benefit pension and OPEB plans
Prior-service costs	$	(18	)	$	(19	)	$	(55	)	$	(55	)	⁽²⁾
	5			7			14			21			Income taxes
	$	(13	)	$	(12	)	$	(41	)	$	(34	)	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".

XML 38 R28.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Tables)

9 Months Ended

Sep. 30, 2018

Fair Value Disclosures [Abstract]

Assets and Liabilities Measured on Recurring Basis

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




	September 30, 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	—		—		10			10			—		—		3			3
Equity securities⁽¹⁾	329		—		—			329			297		—		—			297
Foreign government debt securities	—		12		—			12			—		23		—			23
U.S. government debt securities	—		22		—			22			—		21		—			21
U.S. state debt securities	—		251		—			251			—		247		—			247
Other⁽²⁾	436		106		—			542			588		38		—			626
Total assets	$	765	$	796	$	10		$	1,571		$	885	$	805	$	3		$	1,693

Liabilities
Derivative liabilities - FTRs	$	—	$	—	$	(1	)	$	(1	)	$	—	$	—	$	—		$	—
Derivative liabilities - NUG contracts⁽³⁾	—		—		(52		)	(52		)	—		—		(79		)	(79		)
Total liabilities	$	—	$	—	$	(53	)	$	(53	)	$	—	$	—	$	(79	)	$	(79	)

Net assets (liabilities)⁽⁴⁾	$	765	$	796	$	(43	)	$	1,518		$	885	$	805	$	(76	)	$	1,614


⁽¹⁾	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.


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


⁽³⁾	NUG contracts are subject to regulatory accounting treatment and changes in market values do not impact earnings.


⁽⁴⁾	Excludes $(33) million and $(11) million as of September 30, 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



	NUG Contracts⁽¹⁾									FTRs
	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			7			2			9
Purchases	—			—			—			5			(5		)	—
Settlements	—			25			25			(5		)	2			(3		)
September 30, 2018 Balance	$	—		$	(52	)	$	(52	)	$	10		$	(1	)	$	9

(1)NUG 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 September 30, 2018:

Fair Value, Net (In millions)

Valuation
Technique

Significant Input

Range

Weighted Average

Units

FTRs

Model

RTO auction clearing prices

$(0.40) to $8.60

$1.40

Dollars/MWH

NUG Contracts

(52

)

Model

Generation

400 to 1,437,000

293,000

MWH

Regional electricity prices

$30.60 to $32.70

$31.60

Dollars/MWH

Amortized Cost Basis, Unrealized Gains and Losses and Fair Values of Investments in Available-for-sale Securities



	September 30, 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	$	712	$	2	$	(23	)	$	691	$	774	$	11	$	(17	)	$	768
Equity securities	$	286	$	42	$	(1	)	$	327	$	254	$	40	$	—		$	294

⁽¹⁾ Excludes short-term cash investments of $57 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



	For the Three Months Ended September 30,						For the Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions)
Sale Proceeds	$	261		$	269		$	627		$	1,089
Realized Gains	3			20			31			70
Realized Losses	(7		)	(11		)	(34		)	(55		)
Interest and Dividend Income	11			9			31			28

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 FirstEnergy's long-term debt, which excludes capital lease obligations and net unamortized debt issuance costs, premiums and discounts as of September 30, 2018 and December 31, 2017:



	September 30, 2018		December 31, 2017
	(In millions)
Carrying Value	$	17,796	$	19,296
Fair Value	$	18,761	$	21,412

XML 39 R29.htm IDEA: XBRL DOCUMENT

Commitments, Guarantees and Contingencies (Tables)

9 Months Ended

Sep. 30, 2018

Commitments and Contingencies Disclosure [Abstract]

Schedule of Guarantor Obligations



Potential Collateral Obligations		AE Supply		Utilities and FET		FE		Total
	(In millions)
Contractual Obligations for Additional Collateral
At Current Credit Rating		$	1	$	—	$	—	$	1
Upon Further Downgrade		—		54		—		54
Surety Bonds (Collateralized Amount)		1		60		246		307
Total Exposure from Contractual Obligations		$	2	$	114	$	246	$	362

XML 40 R30.htm IDEA: XBRL DOCUMENT

Segment Information (Tables)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Segment Financial Information

Financial information for each of FirstEnergy's reportable segments is presented in the tables below.

Segment Financial Information



For the Three Months Ended	Regulated Distribution			Regulated Transmission		Corporate/ Other			Reconciling Adjustments			Consolidated
	(In millions)

September 30, 2018
Revenues	$	2,766		$	346	$	6		$	(54	)	$	3,064
Depreciation	202			64		1			16			283
Amortization of regulatory assets, net	65			2		—			—			67
Miscellaneous income (expense), net	34			4		19			(8		)	49
Interest expense	127			43		93			(8		)	255
Income taxes (benefits)	126			34		(27		)	—			133
Income (loss) from continuing operations	416			99		(128		)	—			387
Total assets	28,530			10,017		896			—			39,443
Total goodwill	5,004			614		—			—			5,618
Property additions	356			262		5			12			635

September 30, 2017
Revenues	$	2,609		$	341	$	10		$	(50	)	$	2,910
Depreciation	183			59		2			17			261
Amortization of regulatory assets, net	107			6		—			—			113
Impairment of assets	—			13		—			—			13
Miscellaneous income (expense), net	16			1		15			(13		)	19
Interest expense	133			38		104			(13		)	262
Income taxes (benefits)	183			49		(30		)	—			202
Income (loss) from continuing operations	314			84		(97		)	—			301
Total assets	27,866			9,356		938			5,489			43,649
Total goodwill	5,004			614		—			—			5,618
Property additions	286			248		14			45			593

For the Nine Months Ended

September 30, 2018
Revenues	$	7,694		$	1,010	$	28		$	(181	)	$	8,551
Depreciation	598			187		6			52			843
Amortization (deferral) of regulatory assets, net	(194		)	6		—			—			(188		)
Miscellaneous income (expense), net	146			11		34			(27		)	164
Interest expense	384			124		377			(27		)	858
Income taxes	357			104		42			—			503
Income (loss) from continuing operations	1,115			302		(577		)	—			840
Property additions	1,011			836		68			27			1,942

September 30, 2017
Revenues	$	7,380		$	981	$	37		$	(151	)	$	8,247
Depreciation	540			164		9			52			765
Amortization of regulatory assets, net	263			11		—			—			274
Impairment of assets	—			13		—			—			13
Miscellaneous income (expense), net	45			1		31			(33		)	44
Interest expense	405			116		263			(33		)	751
Income taxes (benefits)	442			154		(113		)	—			483
Income (loss) from continuing operations	756			264		(248		)	—			772
Property additions	854			717		43			233			1,847

XML 41 R31.htm IDEA: XBRL DOCUMENT

Organization and Basis of Presentation (Details Textuals) customer in Millions, $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018 USD ($) transmission_center company MW	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($) customer transmission_center company mi MW	Sep. 30, 2017 USD ($)	Sep. 26, 2018 USD ($)	Jan. 01, 2018 USD ($)	Aug. 31, 2017 MW
Property, Plant and Equipment [Line Items]
Length of transmission lines \| mi					24,500
Number of regional transmission centers \| transmission_center	2				2
Cash payment							$ 225.0
Capitalized cost of equity	$ 11.0		$ 8.0		$ 33.0	$ 25.0
Capitalized interest	$ 5.0		5.0		$ 14.0	14.0
Accounting Standards Update 2018-02 \| Retained Earnings
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle								$ 22.0
Regulated Distribution
Property, Plant and Equipment [Line Items]
Number of existing utility operating companies \| company	10				10
Number of customers served by utility operating companies \| customer					6
Plant capacity (in MW's) \| MW	3,790				3,790
FES \| Accounting Standards Update 2016-01 \| Retained Earnings
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle								115.0
FES and FENOC \| Accounting Standards Update 2018-02 \| Retained Earnings
Property, Plant and Equipment [Line Items]
Cumulative effect of new accounting principle								$ 8.0
Purchase Agreement with Subsidiary of LS Power
Property, Plant and Equipment [Line Items]
Plant capacity (in MW's) \| MW									1,615
Discontinued Operations, Disposed of by Means Other than Sale \| FES and FENOC
Property, Plant and Equipment [Line Items]
Fair value of investments	$ 0.0	$ 0.0			$ 0.0
Gain (Loss) on disposal of FES and FENOC, net of tax	(834.0)	$ 1,200.0	$ 0.0		405.0	$ 0.0
Terms of settlement agreement					66.0
Estimated tax payments that have been made					20.0
Probable loss with respect to bankruptcy	(1,200.0)
Discontinued Operations, Disposed of by Means Other than Sale \| FES and FENOC \| Tax Year 2017
Property, Plant and Equipment [Line Items]
Overpayment of NOL's waived							71.0
Discontinued Operations, Disposed of by Means Other than Sale \| FES and FENOC \| Tax Year 2018
Property, Plant and Equipment [Line Items]
Overpayment of NOL's waived							88.0
Other Operating Expense \| Accounting Standards Update 2017-07
Property, Plant and Equipment [Line Items]
Effect of change on net income	(7.0)				(23.0)
Miscellaneous Income \| Accounting Standards Update 2017-07
Property, Plant and Equipment [Line Items]
Effect of change on net income	$ 7.0				$ 23.0
Corporate/Other
Property, Plant and Equipment [Line Items]
Plant capacity (in MW's) \| MW	1,367				1,367
Loans Payable \| Intercompany Income Tax Allocation Agreement \| FES
Property, Plant and Equipment [Line Items]
Face amount of debt							628.0
Line of Credit \| Secured Credit Facility \| FES
Property, Plant and Equipment [Line Items]
Maximum amount borrowed under revolving credit facility							500.0
Line of Credit \| Credit Agreement \| FES
Property, Plant and Equipment [Line Items]
Maximum amount borrowed under revolving credit facility							$ 200.0
Pleasants Power Station \| Purchase Agreement with Subsidiary of LS Power
Property, Plant and Equipment [Line Items]
Plant capacity (in MW's) \| MW									1,300
Pleasants Power Station \| McElroy's Run Impoundment Site
Property, Plant and Equipment [Line Items]
Increase in asset retirement obligation	$ 43.0
Pleasants Power Station \| McElroy's Run Impoundment Site \| Regulation of Waste Disposal \| AE Supply
Property, Plant and Equipment [Line Items]
Increase in asset retirement obligation	$ 43.0
Affiliated Companies \| Services Agreements \| Discontinued Operations, Disposed of by Means Other than Sale \| FES and FENOC \| FES
Property, Plant and Equipment [Line Items]
Amounts of transaction					$ 110.0
Affiliated Companies \| Scenario, Forecast \| Services Agreements \| Discontinued Operations, Disposed of by Means Other than Sale \| FES and FENOC \| FES
Property, Plant and Equipment [Line Items]
Amounts of transaction				$ 112.5

XML 42 R32.htm IDEA: XBRL DOCUMENT

Revenue (Details)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2018

USD ($)

company

Sep. 30, 2017

USD ($)

Sep. 30, 2018

USD ($)

company

Sep. 30, 2017

USD ($)

$ 2,986

$ 8,313

190

Distribution services | Customer

^[1]

3,064

$ 2,910

8,551

$ 8,247

Retail generation | Customer

1,418

3,868

Wholesale sales | Customer

1,045

2,939

139

393

Transmission | Customer

341

996

Other | Customer

Derivative Revenue | Other Non-Customer Revenue

117

Regulated Distribution

Number of existing utility operating companies | company

2,499

6,930

Reduction in revenue

$ 27

$ 109

Megawatts of net demonstrated capacity of competitive segment | MW

3,790

Utility customer payment period

30 days

Regulated Distribution | Residential

Regulated Distribution | Commercial

$ 1,572

$ 4,290

Regulated Distribution | Industrial

628

1,778

Regulated Distribution | Other

276

792

Regulated Transmission

Regulated Transmission | JCP&L | FERC

341

996

Reduction in revenue

Recovery of revenue

Annual revenue requirement

155

Regulated Transmission | ATSI

Regulated Transmission | TrAIL

167

492

Regulated Transmission | MAIT

183

Regulated Transmission | Other

106

Operating Segments | Customer

215

Operating Segments | Regulated Distribution

Reduction in revenue

113

2,675

7,420

190

Operating Segments | Regulated Distribution | Distribution services | Customer

2,766

2,609

7,694

7,380

Operating Segments | Regulated Distribution | Retail generation | Customer

1,440

3,949

Operating Segments | Regulated Distribution | Wholesale sales | Customer

1,059

2,981

Operating Segments | Regulated Distribution | Transmission | Customer

133

377

Operating Segments | Regulated Distribution | Other | Customer

Operating Segments | Regulated Transmission

113

341

996

Operating Segments | Regulated Transmission | Distribution services | Customer

346

$ 341

1,010

$ 981

Operating Segments | Regulated Transmission | Retail generation | Customer

Operating Segments | Regulated Transmission | Wholesale sales | Customer

Operating Segments | Regulated Transmission | Transmission | Customer

Operating Segments | Regulated Transmission | Other | Customer

341

996

Corporate/Other and Reconciling Adjustments

(30)

(103)

(18)

(50)

Corporate/Other and Reconciling Adjustments | Distribution services | Customer

(48)

(153)

Corporate/Other and Reconciling Adjustments | Retail generation | Customer

(22)

(81)

Corporate/Other and Reconciling Adjustments | Wholesale sales | Customer

(14)

(42)

Corporate/Other and Reconciling Adjustments | Transmission | Customer

Corporate/Other and Reconciling Adjustments | Other | Customer

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

$ 0

$ 4

[1]	Includes excise tax collections of $104 million and $102 million in the three months ended September 30, 2018 and 2017, respectively, and $293 million in the nine months ended September 30, 2018 and 2017.

XML 43 R33.htm IDEA: XBRL DOCUMENT

Discontinued Operations - Narrative (Details) $ in Millions				1 Months Ended	3 Months Ended			9 Months Ended
Discontinued Operations - Narrative (Details) $ in Millions	Apr. 06, 2018 USD ($)	Mar. 16, 2018 USD ($)	Mar. 09, 2018 USD ($) MW	Aug. 31, 2017 Natural_gas_plant MW	Sep. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	May 11, 2018 USD ($)	Dec. 31, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Short-term borrowings					$ 1,700.0				$ 1,700.0			$ 300.0
Interest accrued					255.0		$ 262.0		858.0	$ 751.0
Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant capacity (in MW's) \| MW				1,615
AE Supply \| Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of gas generating plants \| Natural_gas_plant				4
AGC \| Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Ownership percentage				59.00%
Pleasants Power Station \| Purchase Agreement with Subsidiary of LS Power
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant capacity (in MW's) \| MW				1,300
Bay Shore Unit 1 \| Asset Purchase Agreement with Walleye Energy, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Plant capacity (in MW's) \| MW			136
Promissory Notes \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Interest accrued					8.0				16.0
Promissory Notes \| AE Supply \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Outstanding borrowings					102.0				102.0
Revolving Credit Facility \| Line of Credit \| FES
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Line of credit outstanding			$ 500.0		500.0				500.0
Loan reserves						$ 500.0
Money Pool \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Short-term borrowings		$ 4.0
Reinstated debt under settlement agreement		88.0
Money Pool \| Adjustment \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Short-term borrowings		$ 92.0
Discontinued Operations, Disposed of by Means Other than Sale \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Investments in subsidiaries					0.0				0.0
Assumption of benefit obligations retained at FE (including Pension, OPEB and EDCP)					0.0	(820.0)			820.0
Settlement payments	$ 72.0
Terms of settlement agreement									66.0
Estimated tax payments that have been made									20.0
Tax consequence of outside basis difference					950.0				950.0
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											$ 58.0
Services Agreements \| Affiliated Companies \| Discontinued Operations, Disposed of by Means Other than Sale \| FES \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Amounts of transaction									110.0
Services Agreements \| Affiliated Companies \| Discontinued Operations, Disposed of by Means Other than Sale \| Scenario, Forecast \| 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					21.0				21.0
Purchases from related party					74.0				248.0
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					88.0				88.0
FE \| Promissory Notes \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loan reserves					$ 8.0	102.0			$ 16.0
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						92.0
FE \| Money Pool \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loan reserves						4.0
FE \| Reinstated Debt under Money Pool [Member] \| FES and FENOC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Loan reserves						$ 88.0

XML 44 R34.htm IDEA: XBRL DOCUMENT

Discontinued Operations - Summarized Results of Discontinued Operations (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2018

Mar. 31, 2018

Sep. 30, 2017

Sep. 30, 2018

Sep. 30, 2017

Income tax expense (benefit)

$ (354)

$ 37

$ (1,300)

$ (1)

Income (Loss) from discontinued operations, net of tax

405

Income (Loss) from discontinued operations

^[1]

(845)

370

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]

Provision for depreciation

788

934

2,299

Fuel

(52)

(237)

(269)

(671)

Purchased power

(66)

(85)

(189)

Other operating expenses

(24)

(290)

(414)

(1,097)

(18)

(28)

(96)

(80)

General taxes

(4)

(15)

(32)

(74)

Income (Loss) from discontinued operations, before tax

(18)

(149)

Other expense, net

(1)

(2)

(82)

(37)

(16)

132

(44)

Income tax expense (benefit)

(5)

(9)

(1)

Income (Loss) from discontinued operations, net of tax

(11)

(35)

Gain (Loss) on disposal of FES and FENOC, net of tax

(834)

$ 1,200

405

Income (Loss) from discontinued operations

$ (845)

$ 95

370

$ 3

Tax benefit from excess deferred tax liabilities

$ 32

[1]	Net of income tax expense (benefit) of $(354) million and $37 million for the three months ended September 30, 2018 and 2017, respectively, and income tax benefits of $(1.3) billion and $(1) million for the nine months ended September 30, 2018 and 2017, respectively.

XML 45 R35.htm IDEA: XBRL DOCUMENT

Discontinued Operations - Gain on Deconsolidation (Details) - FES and FENOC - Discontinued Operations, Disposed of by Means Other than Sale - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Removal of investment in FES and FENOC	$ 0			$ 2,193
Assumption of benefit obligations retained at FE	0	$ 820		(820)
Guarantees and credit support provided by FE	0			(139)
Reserve on receivables and allocated Pension/OPEB mark-to-market	0			(914)
Settlement Consideration and Services Credit	(1,183)			(1,183)
Loss on disposal of FES and FENOC, before tax	(1,183)			(863)
Income tax benefit, including estimated worthless stock deduction	349			1,268
Gain (Loss) on disposal of FES and FENOC, net of tax	$ (834)	$ 1,200	$ 0	$ 405	$ 0

XML 46 R36.htm IDEA: XBRL DOCUMENT

Discontinued Operations - Major Classes of Assets and Liabilities as Discontinued Operations (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Total current assets	$ 17	$ 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 and cash equivalents	0	1
Restricted cash	0	3
Receivables	0	202
Materials and supplies	17	227
Prepaid taxes and other	0	199
Total current assets	17	632
Property, plant and equipment	0	1,132
Investments	0	1,875
Other noncurrent assets	0	356
Total noncurrent assets	0	3,363
Total assets included in discontinued operations	17	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 noncurrent liabilities	0	244
Total noncurrent liabilities	0	3,528
Total liabilities included in discontinued operations	$ 0	$ 4,506

XML 47 R37.htm IDEA: XBRL DOCUMENT

Discontinued Operations - Major Classes of Cash Flow Items from Discontinued Operations (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2018

Sep. 30, 2017

Sep. 30, 2018

Sep. 30, 2017

CASH FLOWS FROM OPERATING ACTIVITIES:

Income from discontinued operations

^[1]

$ (845)

$ 95

$ 370

$ 3

Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs

1,003

1,307

Unrealized (gain) loss on derivative transactions

(5)

CASH FLOWS FROM INVESTING ACTIVITIES:

Sales of investment securities held in trusts

(635)

(593)

(1,942)

(1,847)

Nuclear fuel

(156)

736

1,923

Purchases of investment securities held in trusts

(780)

(1,995)

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

CASH FLOWS FROM OPERATING ACTIVITIES:

Income from discontinued operations

$ (845)

$ 95

370

Depreciation and amortization, including nuclear fuel, regulatory assets, net, intangible assets and deferred debt-related costs

110

245

Unrealized (gain) loss on derivative transactions

(15)

CASH FLOWS FROM INVESTING ACTIVITIES:

Sales of investment securities held in trusts

(27)

(233)

Nuclear fuel

(156)

109

834

Purchases of investment securities held in trusts

$ (122)

$ (878)

[1]	Net of income tax expense (benefit) of $(354) million and $37 million for the three months ended September 30, 2018 and 2017, respectively, and income tax benefits of $(1.3) billion and $(1) million for the nine months ended September 30, 2018 and 2017, respectively.

XML 48 R38.htm IDEA: XBRL DOCUMENT

Earnings Per Share Of Common Stock (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

9 Months Ended

Jan. 31, 2018

Sep. 30, 2018

Sep. 30, 2017

Sep. 30, 2018

Sep. 30, 2017

Earnings Per Share [Abstract]

Amount of beneficial conversion

$ 296

$ 0

EPS of Common Stock

Income from continuing operations

$ 387

$ 301

840

772

Less: Preferred dividends

(19)

(61)

Less: Amortization of beneficial conversion feature

(35)

(296)

Less: Undistributed earnings allocated to preferred shareholders

Income from continuing operations available to common stockholders

333

301

483

772

Discontinued operations, net of tax

^[1]

(845)

370

Less: Undistributed earnings allocated to preferred shareholders

Income (loss) from discontinued operations available to common stockholders

(845)

370

NET INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCKHOLDERS

$ (512)

$ 396

$ 853

$ 775

Share Count information:

Weighted average number of basic shares outstanding (in shares)

503

444

485

444

Assumed exercise of dilutive stock options and awards (in shares)

Weighted average number of diluted shares outstanding

505

446

487

445

Income (loss) available to common stockholders, per common share:

Income from continuing operations, basic (in dollars per share)

$ 0.66

$ 0.68

$ 1.00

$ 1.74

Discontinued operations, basic (in dollars per share)

(1.68)

0.21

0.76

0.01

Basic - Net Income Attributable to Common Stockholders (in dollars per share)

(1.02)

0.89

1.76

1.75

Income from continuing operations, diluted (in dollars per share)

0.66

0.68

0.99

1.73

Discontinued operations, diluted (in dollars per share)

(1.68)

0.21

0.76

0.01

Diluted - Net Income Attributable to Common Stockholders (in dollars per share)

$ (1.02)

$ 0.89

$ 1.75

$ 1.74

Stock Options

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

Shares excluded from the calculation of diluted shares outstanding, in shares

Preferred Stock

Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]

Shares excluded from the calculation of diluted shares outstanding, in shares

[1]	Net of income tax expense (benefit) of $(354) million and $37 million for the three months ended September 30, 2018 and 2017, respectively, and income tax benefits of $(1.3) billion and $(1) million for the nine months ended September 30, 2018 and 2017, respectively.

XML 49 R39.htm IDEA: XBRL DOCUMENT

Pension and Other Postemployment Benefits (Details) $ in Millions	1 Months Ended	2 Months Ended	3 Months Ended		9 Months Ended
	Jan. 31, 2018 USD ($)	Jul. 31, 2018 employee	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Additional funding contributions	$ 750
FES and FENOC \| Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount billed for pension and OPEB service costs			$ 14		$ 28
Pension
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs			56	$ 52	168	$ 156
Interest costs			93	97	279	291
Expected return on plan assets			(144)	(112)	(432)	(336)
Amortization of prior service costs (credits)			2	2	6	6
Special termination costs			21	0	21	0
Net periodic costs (credits), including amounts capitalized			28	39	42	117
Net periodic costs (credits), recognized in earnings			5	30	(27)	89
Pension \| FES and FENOC \| Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits), including amounts capitalized				16	13	47
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Service costs			1	1	3	3
Interest costs			6	7	18	21
Expected return on plan assets			(7)	(7)	(22)	(22)
Amortization of prior service costs (credits)			(20)	(20)	(60)	(60)
Special termination costs			6	0	6	0
Net periodic costs (credits), including amounts capitalized			(14)	(19)	(55)	(58)
Net periodic costs (credits), recognized in earnings			$ (15)	(14)	(57)	(43)
OPEB \| FES and FENOC \| Discontinued Operations, Disposed of by Means Other than Sale
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Net periodic costs (credits), including amounts capitalized				$ (8)	$ (10)	$ (24)
Minimum
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions by employer	$ 500
FE Tomorrow Initiative
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Number of employees that accepted a voluntary enhanced retirement package \| employee		500
Percentage of employees that accepted the voluntary enhanced retirement package		80.00%

XML 50 R40.htm IDEA: XBRL DOCUMENT

Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	$ 73	$ 163	$ 142	$ 174
Other comprehensive income before reclassifications		27	(97)	63
Amounts reclassified from AOCI	(16)	(48)	(50)	(102)
Deconsolidation of FES and FENOC			5
Other comprehensive loss	(16)	(21)	(142)	(39)
Income taxes (benefits) on other comprehensive income (loss)	(4)	(9)	(61)	(16)
Other comprehensive loss, net of tax	(12)	(12)	(81)	(23)
AOCI Ending Balance	61	151	61	151
Gains & Losses on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	(14)	(26)	(22)	(28)
Other comprehensive income before reclassifications		0	0	0
Amounts reclassified from AOCI	2	4	6	8
Deconsolidation of FES and FENOC			13
Other comprehensive loss	2	4	19	8
Income taxes (benefits) on other comprehensive income (loss)	0	1	9	3
Other comprehensive loss, net of tax	2	3	10	5
AOCI Ending Balance	(12)	(23)	(12)	(23)
Unrealized Gains on AFS Securities
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	0	61	67	52
Other comprehensive income before reclassifications		27	(97)	63
Amounts reclassified from AOCI	0	(33)	(1)	(55)
Deconsolidation of FES and FENOC			(8)
Other comprehensive loss	0	(6)	(106)	8
Income taxes (benefits) on other comprehensive income (loss)	0	(3)	(39)	2
Other comprehensive loss, net of tax	0	(3)	(67)	6
AOCI Ending Balance	0	58	0	58
Defined Benefit Pension & OPEB Plans
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
AOCI Beginning Balance	87	128	97	150
Other comprehensive income before reclassifications		0	0	0
Amounts reclassified from AOCI	(18)	(19)	(55)	(55)
Deconsolidation of FES and FENOC			0
Other comprehensive loss	(18)	(19)	(55)	(55)
Income taxes (benefits) on other comprehensive income (loss)	(4)	(7)	(31)	(21)
Other comprehensive loss, net of tax	(14)	(12)	(24)	(34)
AOCI Ending Balance	$ 73	$ 116	$ 73	$ 116

XML 51 R41.htm IDEA: XBRL DOCUMENT

Accumulated Other Comprehensive Income (Details 1) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$ (255)	$ (262)	$ (858)	$ (751)
Income taxes	(133)	(202)	(503)	(483)
Prior-service costs	(739)	(652)	(2,363)	(1,958)
NET INCOME (LOSS)	(458)	396	1,210	775
Reclassifications from AOCI \| Gains & losses on cash flow hedges
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes	0	(1)	(1)	(3)
Net of tax	2	3	5	5
Reclassifications from AOCI \| Gains & losses on cash flow hedges \| Long-term debt
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	2	4	6	8
Reclassifications from AOCI \| Unrealized gains on AFS securities
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Net of tax	0	(21)	(1)	(35)
Reclassifications from AOCI \| Net prior service costs
Reclassification Out of Accumulated Other Comprehensive Income [Line Items]
Income taxes	5	7	14	21
Prior-service costs	(18)	(19)	(55)	(55)
NET INCOME (LOSS)	$ (13)	$ (12)	$ (41)	$ (34)

XML 52 R42.htm IDEA: XBRL DOCUMENT

Income Taxes (Details) - USD ($)	3 Months Ended			9 Months Ended
Income Taxes (Details) - USD ($)	Sep. 30, 2018	Mar. 31, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Taxes (Textuals) [Abstract]
Effective tax rate (percent)	25.60%		40.20%	37.50%	38.50%
Unrecognized tax benefits from lapse of statute of limitations				$ 2,000,000
State and Local Jurisdiction \| West Virginia
Income Taxes (Textuals) [Abstract]
Re-measurement in state deferred taxes	$ 126,000,000
State and Local Jurisdiction \| Pennsylvania
Income Taxes (Textuals) [Abstract]
Decrease resulting from settlements with taxing authorities		$ 45,000,000
Unrecognized tax benefits that would impact effective tax rate	$ 0			$ 0

XML 53 R43.htm IDEA: XBRL DOCUMENT

Variable Interest Entities (Details Textuals)	3 Months Ended		9 Months Ended
Variable Interest Entities (Details Textuals)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($) agreement entity	Sep. 30, 2017 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Variable Interest Entities (Textuals) [Abstract]
Long-term transition bond	$ 45,000,000		$ 45,000,000				$ 56,000,000
Long-term pollution control bond	359,000,000		359,000,000				383,000,000
Guarantor obligations	362,000,000		$ 362,000,000
Number of contracts that may contain variable interest \| entity			1
Purchased power	$ 876,000,000	$ 774,000,000	$ 2,393,000,000	$ 2,215,000,000
Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	0.00%		0.00%
Number of long-term power purchase agreements maintained by FirstEnergy with NUG entities \| agreement			12
Phase In Recovery Bonds
Variable Interest Entities (Textuals) [Abstract]
Long-term debt and other long-term obligations	$ 292,000,000		$ 292,000,000				$ 315,000,000
Ohio Funding Companies
Variable Interest Entities (Textuals) [Abstract]
Annual servicing fees			445,000
Other FE subsidiaries \| Power Purchase Agreements
Variable Interest Entities (Textuals) [Abstract]
Purchased power	$ 27,000,000	$ 29,000,000	$ 85,000,000	$ 82,000,000
Path-WV
Variable Interest Entities (Textuals) [Abstract]
Percentage of high-voltage transmission line project owned by subsidiary of FE on the Allegheny Series	100.00%		100.00%
Percentage of high-voltage transmission line project owned by subsidiary of FE on the West Virginia Series	50.00%		50.00%
Equity method investments	$ 17,000,000		$ 17,000,000
Global Holding \| Line of Credit \| Term Loan Facility Due March 2020
Variable Interest Entities (Textuals) [Abstract]
Face amount of debt	$ 300,000,000		$ 300,000,000		$ 300,000,000
Global Holding \| Guarantee of senior secured loan facility
Variable Interest Entities (Textuals) [Abstract]
Guarantor obligations					$ 220,000,000
Signal Peak \| Global Holding \| FEV
Variable Interest Entities (Textuals) [Abstract]
Ownership interest	33.33%		33.33%
FES and FENOC \| Discontinued Operations, Disposed of by Means Other than Sale
Variable Interest Entities (Textuals) [Abstract]
Fair value of investments	$ 0		$ 0			$ 0

XML 54 R44.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details) - Recurring - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets
Fair value, assets	$ 1,571	$ 1,693
Liabilities
Fair value, liabilities	(53)	(79)
Net assets (liabilities)	1,518	1,614
FTRs \| Derivative Liabilities
Liabilities
Fair value, liabilities	(1)	0
NUG contracts \| Derivative Liabilities
Liabilities
Fair value, liabilities	(52)	(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	329	297
Foreign government debt securities
Assets
Fair value, assets	12	23
U.S. government debt securities
Assets
Fair value, assets	22	21
U.S. state debt securities
Assets
Fair value, assets	251	247
Other
Assets
Fair value, assets	542	626
Level 1
Assets
Fair value, assets	765	885
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	765	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	329	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	436	588
Level 2
Assets
Fair value, assets	796	805
Liabilities
Fair value, liabilities	0	0
Net assets (liabilities)	796	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	12	23
Level 2 \| U.S. government debt securities
Assets
Fair value, assets	22	21
Level 2 \| U.S. state debt securities
Assets
Fair value, assets	251	247
Level 2 \| Other
Assets
Fair value, assets	106	38
Level 3
Assets
Fair value, assets	10	3
Liabilities
Fair value, liabilities	(53)	(79)
Net assets (liabilities)	(43)	(76)
Level 3 \| FTRs \| Derivative Liabilities
Liabilities
Fair value, liabilities	(1)	0
Level 3 \| NUG contracts \| Derivative Liabilities
Liabilities
Fair value, liabilities	(52)	(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

XML 55 R45.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details 1) - Level 3 - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
NUG contracts
Reconciliation of changes in the fair value of FTRs 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 loss, Derivative Liabilities	2	(10)
Unrealized 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	25	39
Settlements, Net	25	38
Ending Balance, Derivative Assets	0	0
Ending Balance, Derivative Liabilities	(52)	(79)
Ending Balance, Net	(52)	(79)
FTRs
Reconciliation of changes in the fair value of FTRs contracts
Beginning Balance, Derivative Assets	3	3
Beginning Balance, Derivative Liabilities	0	(1)
Beginning Balance, Net	3	2
Unrealized gain (loss), Derivative Assets	7	1
Unrealized loss, Derivative Liabilities	2	(1)
Unrealized loss, Net	9	0
Purchases, Derivative Assets	5	3
Purchases, Derivative Liabilities	(5)	0
Purchases, Net	0	3
Settlements, Derivative Assets	(5)	(4)
Settlements, Derivative Liabilities	2	2
Settlements, Net	(3)	(2)
Ending Balance, Derivative Assets	10	3
Ending Balance, Derivative Liabilities	(1)	0
Ending Balance, Net	$ 9	$ 3

XML 56 R46.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details 2) - Level 3 $ in Millions	9 Months Ended
Fair Value Measurements (Details 2) - Level 3 $ in Millions	Sep. 30, 2018 USD ($) MWh $ / MWh	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
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 \| $	(52)	$ (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 \| $	$ (52)
Model \| Minimum \| FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	(0.40)
Model \| Minimum \| NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) \| MWh	400
Fair Value Inputs, Power, Regional Prices (in $/MWH)	30.60
Model \| Maximum \| FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	8.60
Model \| Maximum \| NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) \| MWh	1,437,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	32.70
Model \| Weighted Average \| FTRs
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, RTO Auction Clearing Prices (in $/MWH)	1.40
Model \| Weighted Average \| NUG contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs, Power (in MWH) \| MWh	293,000
Fair Value Inputs, Power, Regional Prices (in $/MWH)	31.60

XML 57 R47.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details 3) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
Fair Value Measurements (Details 3) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Debt securities
Debt Securities, Available-for-sale [Line Items]
Cost Basis	$ 712	$ 774
Unrealized Gains	2	11
Unrealized Losses	(23)	(17)
Fair Value	691	768
Equity securities
Amortized cost basis, unrealized gains and losses and fair values of investments in available-for-sale securities
Cost Basis	286	254
Unrealized Gains	42	40
Unrealized Losses	(1)	0
Fair Value	$ 327	$ 294

XML 58 R48.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details 4) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Fair Value Measurements (Details 4) - USD ($) $ in Millions	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Proceeds from the sale of investments in available-for-sale securities, realized gains and losses on those sales, and interest and dividend income
Sale Proceeds	$ 261	$ 269	$ 627	$ 1,089
Realized Gains	3	20	31	70
Realized Losses	(7)	(11)	(34)	(55)
Interest and Dividend Income	$ 11	$ 9	$ 31	$ 28

XML 59 R49.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details 5) - USD ($) $ in Millions	Sep. 30, 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	$ 17,796	$ 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	$ 18,761	$ 21,412

XML 60 R50.htm IDEA: XBRL DOCUMENT

Fair Value Measurements (Details Textuals) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Fair Value of Financial Instruments [Line Items]
Investment excludes receivables, payables and accrued income	$ (33)	$ (11)
Cash balance excluded from available for sale securities	57	11
Investments not required to be disclosed	$ 254	$ 255
NUG contracts
Fair Value of Financial Instruments [Line Items]
Period of future observable data to determine contract price	2 years

XML 61 R51.htm IDEA: XBRL DOCUMENT

Derivative Instruments (Details Textuals)	3 Months Ended	9 Months Ended
Derivative Instruments (Details Textuals)	Sep. 30, 2018 USD ($) agreement	Sep. 30, 2018 USD ($) agreement	Dec. 31, 2017 USD ($) agreement
Cash Flow Hedges
Derivative [Line Items]
Unamortized losses associated with prior interest rate hedges	$ 16,000,000	$ 16,000,000	$ 22,000,000
Gains (losses) to be amortized to interest expenses during next twelve months		$ (3,000,000)
Number of outstanding commodity or interest rate derivatives \| agreement	0	0	0
Fair Value Hedging
Derivative [Line Items]
Number of fixed-for-floating interest rate swap agreements outstanding \| agreement	0	0	0
Gains included in long-term debt associated with prior fixed-for-floating interest rate swap agreements	$ 2,000,000	$ 2,000,000	$ 3,000,000
NUGs
Derivative [Line Items]
Liability position	52,000,000	52,000,000	79,000,000
Settlements	9,000,000	25,000,000
Unrealized gain (loss)	4,000,000	2,000,000
FTRs
Derivative [Line Items]
Settlements	0	(3,000,000)
Unrealized gain (loss)	9,000,000	9,000,000
Net asset position	$ 9,000,000	$ 9,000,000	$ 3,000,000

XML 62 R52.htm IDEA: XBRL DOCUMENT

Capitalization (Details)	Sep. 30, 2018 $ / shares shares	Jan. 22, 2018 USD ($) employee $ / shares shares	Dec. 31, 2017 $ / shares
Class of Stock [Line Items]
Proceeds from issuance of equity		$ 2,500,000,000
Par Value, in dollars per share \| $ / shares	$ 100	$ 100
Amount of private placement shares \| shares		30,120,482
Common stock, par value (in dollars per share) \| $ / shares	$ 0.1	$ 0.10	$ 0.1
Amount of private placement		$ 850,000,000
Liquidation preference value		$ 1,000
Conversion price (in dollars per share) \| $ / shares		$ 27.42
Conversion threshold of Preferred Stock (in shares) \| shares		323,200
Number of shares to be converted within two years \| shares		0
Common stock share cap (in shares) \| shares		58,964,222
RWG number of board members \| employee		2
Preferred Stock
Class of Stock [Line Items]
Number of shares converted (in shares) \| shares	911,411
Other Paid-in Capital
Class of Stock [Line Items]
Amount of private placement		$ 847,000,000
Common Stock
Class of Stock [Line Items]
Amount of private placement		$ 3,000,000
Number of shares issued (in shares) \| shares	33,238,910
Series A Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock shares issued \| shares	1,616,000	1,616,000
Amount of preferred stock investment		$ 1,620,000,000
Series A Convertible Preferred Stock \| Preferred Stock
Class of Stock [Line Items]
Amount of preferred stock investment		162,000,000
Series A Convertible Preferred Stock \| Other Paid-in Capital
Class of Stock [Line Items]
Amount of preferred stock investment		$ 1,460,000,000
FirstEnergy
Class of Stock [Line Items]
RWG number of board members \| employee		3

XML 63 R53.htm IDEA: XBRL DOCUMENT

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Asset Retirement Obligation [Abstract]
Asset retirement obligation	$ 630	$ 570
McElroy's Run Impoundment Site \| Pleasants Power Station
Public Utility, Property, Plant and Equipment [Line Items]
Increase in asset retirement obligation	$ 43

XML 64 R54.htm IDEA: XBRL DOCUMENT

Regulatory Matters - Maryland and New Jersey (Details) $ in Millions										9 Months Ended	36 Months Ended
	Oct. 05, 2018 USD ($)	Aug. 24, 2018 USD ($) program	Aug. 17, 2018 USD ($)	Jul. 13, 2018 USD ($)	Mar. 26, 2018 USD ($)	Jan. 19, 2018 USD ($) rebate	Dec. 12, 2016 USD ($)	Jul. 16, 2015	Feb. 27, 2013 USD ($)	Sep. 30, 2018 component	Dec. 31, 2020 USD ($)	Feb. 15, 2018 USD ($)
Maryland
Regulatory Matters [Line Items]
Expected infrastructure investments									$ 2,700.0
Period of expected infrastructure investments									15 years
New Jersey
Regulatory Matters [Line Items]
Number of supply components \| component										2,000,000
PE \| Maryland
Regulatory Matters [Line Items]
Recovery period for expenditures for cost recovery program										3 years
Incremental energy savings goal in the next 12 months (percent)								0.97%
Incremental energy savings goal per year (percent)								0.20%
Incremental energy savings goal thereafter (percent)								2.00%
Amortization period										5 years
PE \| MPSC
Regulatory Matters [Line Items]
Number of residential charging equipment rebates \| rebate						2,000
Number of commercial charging equipment rebates \| rebate						259
Cost of charging equipment rebates						$ 12.0
Charging equipment rebates amortization period						5 years
PE \| MPSC \| Maryland
Regulatory Matters [Line Items]
Approved amount of annual increase (decrease)			$ (6.5)
Amount of requested rate increase (decrease)		$ 19.7
Number of enhanced service reliability programs \| program		4
Revised requested rate increase		$ 7.3
JCP&L \| NJBPU \| New Jersey
Regulatory Matters [Line Items]
Approved amount of annual increase (decrease)					$ (28.6)		$ 80.0
Approved rider due to change in tax rate					$ 1.3
JCP&L \| NJBPU \| JCP&L Reliability Plus
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)				$ 386.8
JCP&L \| NJBPU \| JCP&L Reliability Plus \| New Jersey
Regulatory Matters [Line Items]
Infrastructure investment period				4 years
Scenario, Forecast \| PE \| Maryland
Regulatory Matters [Line Items]
Recovery period for expenditures for cost recovery program											3 years
Expenditures for cost recovery program											$ 116.0
Subsequent Event \| PE \| MPSC \| Maryland
Regulatory Matters [Line Items]
Approved amount of annual increase (decrease)	$ (5.0)
Minimum \| PE \| MPSC \| Maryland
Regulatory Matters [Line Items]
Impact on base rate												$ 7.0
Maximum \| PE \| MPSC \| Maryland
Regulatory Matters [Line Items]
Impact on base rate												$ 8.0

XML 65 R55.htm IDEA: XBRL DOCUMENT

Regulatory Matters - Ohio (Details) $ in Millions							9 Months Ended
Regulatory Matters - Ohio (Details) $ in Millions	Apr. 25, 2018 USD ($)	Mar. 12, 2018	Dec. 01, 2017 USD ($)	Oct. 12, 2016 USD ($)	Apr. 15, 2016	Aug. 07, 2013 USD ($) auction	Sep. 30, 2018 USD ($)	Feb. 15, 2018 USD ($)
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)							90.00%
Ohio
Regulatory Matters [Line Items]
Energy efficient portfolio plan term					3 years
Estimated cost of plans							$ 268.0
Credit to non-shopping customers						$ 43.4
Ohio \| PUCO
Regulatory Matters [Line Items]
Proposed goal to reduce CO2 pollution (percent)				90.00%
Requested removal of cost cap		4.00%
Number of renewable energy auctions \| auction						1
Reversal of reserve	$ 72.0
Ohio \| Distribution Modernization Rider
Regulatory Matters [Line Items]
Amount of rider valuation				$ 558.0
Period of rider valuation				8 years
Ohio \| Distribution Modernization Rider \| PUCO
Regulatory Matters [Line Items]
Annual revenue cap for rider				$ 132.5
Recovery period				3 years
Possible extension period				2 years
Approved amount for rider				$ 168.0
Excessive earnings test exclusion period				3 years
Renewal period for excessive earnings test exclusion period				2 years
Ohio \| Delivery Capital Recovery Rider \| PUCO
Regulatory Matters [Line Items]
Annual revenue cap for rider				$ 30.0
Annual revenue cap for rider for years three through six				20.0
Annual revenue cap for rider for years six through eight				15.0
Ohio \| Distribution Platform Modernization Plan \| PUCO
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)			$ 450.0
Ohio \| Energy Conservation, Economic Development and Job Retention \| PUCO
Regulatory Matters [Line Items]
Contribution amount				$ 51.0
The Ohio Companies \| Ohio \| PUCO
Regulatory Matters [Line Items]
Impact on base rate								$ 40.0

XML 66 R56.htm IDEA: XBRL DOCUMENT

Regulatory Matters - Pennsylvania and West Virginia (Details) $ in Millions							1 Months Ended	6 Months Ended		9 Months Ended
	Aug. 31, 2018 USD ($)	May 30, 2018 USD ($)	Mar. 09, 2018 USD ($)	Jun. 14, 2017 USD ($)	Jan. 19, 2017 USD ($)	Jun. 19, 2015	Mar. 31, 2016 USD ($)	Jun. 30, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 proposal
Pennsylvania \| DSP June 2017- May 2019
Regulatory Matters [Line Items]
Number of RFP's \| proposal										1
RFP term										2 years
Pennsylvania \| DSP June 2019- May 2023
Regulatory Matters [Line Items]
Number of RFP's \| proposal										2
RFP term										2 years
Pennsylvania \| Three Month Period \| DSP June 2019- May 2023
Regulatory Matters [Line Items]
Term of energy contract										3 months
Pennsylvania \| Twelve month period \| DSP June 2017- May 2019
Regulatory Matters [Line Items]
Term of energy contract										12 months
Pennsylvania \| Twelve month period \| DSP June 2019- May 2023
Regulatory Matters [Line Items]
Term of energy contract										12 months
Pennsylvania \| Twenty-four month period \| DSP June 2017- May 2019
Regulatory Matters [Line Items]
Term of energy contract										24 months
Pennsylvania \| Twenty-four month period \| DSP June 2019- May 2023
Regulatory Matters [Line Items]
Term of energy contract										24 months
Pennsylvania \| Pennsylvania Companies \| PPUC \| EE&C Phase III
Regulatory Matters [Line Items]
Approved amount of annual increase							$ (390.0)
Pennsylvania \| ME
Regulatory Matters [Line Items]
Approved amount of annual increase					$ (96.0)
Pennsylvania \| ME \| PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed						1.80%
Energy consumption reduction targets proposed						4.00%
Amount of requested rate increase (decrease)				$ (51.3)
Net annual effect on rates			$ 37.0
Pennsylvania \| Penn
Regulatory Matters [Line Items]
Approved amount of annual increase					(29.0)
Pennsylvania \| Penn \| PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed						1.70%
Energy consumption reduction targets proposed						3.30%
Amount of requested rate increase (decrease)				(33.2)
Net annual effect on rates			9.0
Pennsylvania \| WP
Regulatory Matters [Line Items]
Approved amount of annual increase					(66.0)
Pennsylvania \| WP \| PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed						1.80%
Energy consumption reduction targets proposed						2.60%
Amount of requested rate increase (decrease)				(50.1)
Net annual effect on rates			30.0
Pennsylvania \| PN
Regulatory Matters [Line Items]
Approved amount of annual increase					$ (100.0)
Pennsylvania \| PN \| PPUC
Regulatory Matters [Line Items]
Demand reduction targets proposed						0.00%
Energy consumption reduction targets proposed						3.90%
Amount of requested rate increase (decrease)				$ (44.8)
Net annual effect on rates			$ 40.0
West Virginia \| MP and PE \| WVPSC
Regulatory Matters [Line Items]
Net annual effect on rates		$ 26.2
West Virginia \| MP and PE \| WVPSC \| ENEC
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)	$ (100.9)
Net annual effect on rates	25.6
West Virginia \| MP and PE \| WVPSC \| Elimination of Energy Efficiency Cost Rate Surcharge
Regulatory Matters [Line Items]
Amount of requested rate increase (decrease)	$ (2.1)
Requested rate decrease (percentage)	(7.20%)
Scenario, Forecast \| Pennsylvania \| PPUC \| Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Rate filing period								3 years
Scenario, Forecast \| Pennsylvania \| ME \| PPUC \| Temporary Rates Order
Regulatory Matters [Line Items]
Approved amount of annual increase									$ (19.0)
Rate filing period									6 months
Scenario, Forecast \| Pennsylvania \| ME \| PPUC \| Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of annual increase								$ 12.0
Scenario, Forecast \| Pennsylvania \| Penn \| PPUC \| Temporary Rates Order
Regulatory Matters [Line Items]
Approved amount of annual increase									$ (5.0)
Scenario, Forecast \| Pennsylvania \| Penn \| PPUC \| Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of annual increase								3.0
Scenario, Forecast \| Pennsylvania \| WP \| PPUC \| Temporary Rates Order
Regulatory Matters [Line Items]
Approved amount of annual increase									(15.0)
Scenario, Forecast \| Pennsylvania \| WP \| PPUC \| Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of annual increase								10.0
Scenario, Forecast \| Pennsylvania \| PN \| PPUC \| Temporary Rates Order
Regulatory Matters [Line Items]
Approved amount of annual increase									$ (20.0)
Scenario, Forecast \| Pennsylvania \| PN \| PPUC \| Temporary Rates Order Tracked Value
Regulatory Matters [Line Items]
Approved amount of annual increase								$ 13.0

XML 67 R57.htm IDEA: XBRL DOCUMENT

Regulatory Matters - Reliability Matters and FERC (Details) - FERC $ in Millions							3 Months Ended		12 Months Ended
	May 14, 2018	Feb. 20, 2017	Jan. 19, 2017	Jun. 15, 2016 kv	Aug. 04, 2014	Aug. 24, 2012 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Dec. 31, 2016	Dec. 31, 2015	Apr. 10, 2018 condition
Regulatory Matters [Line Items]
Power threshold \| kv				500
Denied recovery charges of exit fees							$ 78.8
Number of alternative proposals filed \| condition											2
PJM Transmission Rates
Regulatory Matters [Line Items]
Load-ratio share									100.00%	50.00%
Solution-based distribution factor										50.00%
Gain related to settlement							$ 42.0	$ 73.0
PATH-Allegheny
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets						$ 62.0
Path-WV
Regulatory Matters [Line Items]
Cost recovery, PP&E reclassified to Regulatory Assets						$ 59.0
PATH
Regulatory Matters [Line Items]
Proposed return on equity						10.90%
Base return on equity		10.40%	8.11%			10.40%
Return on equity granted for regional transmission organization participation						0.50%
Remaining recovery period of regulatory assets						5 years
The Ohio Companies \| ESP IV PPA
Regulatory Matters [Line Items]
Term of proposed purchase power agreement					8 years
ME, PN and Penn
Regulatory Matters [Line Items]
Requested rate increase (percentage)	6.70%

XML 68 R58.htm IDEA: XBRL DOCUMENT

Commitments, Guarantees and Contingencies (Details) $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 362
Curing period	30 days
At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	$ 1
Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	54
Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	307
Utilities and FET
Guarantor Obligations [Line Items]
Guarantor obligations	114
Utilities and FET \| At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
Utilities and FET \| Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	54
Utilities and FET \| Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	60
FirstEnergy
Guarantor Obligations [Line Items]
Guarantor obligations	246
FirstEnergy \| At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	0
FirstEnergy \| Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
FirstEnergy \| Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	246
AE Supply
Guarantor Obligations [Line Items]
Guarantor obligations	2
AE Supply \| At Current Credit Rating
Guarantor Obligations [Line Items]
Guarantor obligations	1
AE Supply \| Upon Further Downgrade
Guarantor Obligations [Line Items]
Guarantor obligations	0
AE Supply \| Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Guarantor obligations	$ 1

XML 69 R59.htm IDEA: XBRL DOCUMENT

Commitments, Guarantees and Contingencies (Details Textuals) - USD ($)	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	$ 1,700,000,000	$ 1,700,000,000
New syndicated senior secured term loan facility	362,000,000	$ 362,000,000
Curing period		30 days
Proposed goal to reduce CO2 pollution (percent)		90.00%
Nuclear plant decommissioning trusts	822,000,000	$ 822,000,000		$ 822,000,000
Clean Water Act
Guarantor Obligations [Line Items]
Waste water discharge permit renewal cycle		5 years
Regulation of Waste Disposal
Guarantor Obligations [Line Items]
Accrual for environmental loss contingencies	115,000,000	$ 115,000,000
Environmental liabilities former gas facilities	78,000,000	78,000,000
Regulated Distribution
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions	$ 10,000,000	$ 10,000,000
Global Holding \| Senior Secured Term Loan \| Senior Loans \| Signal Peak, Global Rail and Affiliates
Guarantor Obligations [Line Items]
Investment ownership percentage	69.99%	69.99%
FEV \| Senior Secured Term Loan \| Senior Loans \| Signal Peak \| Global Holding
Guarantor Obligations [Line Items]
Investment ownership percentage	33.33%	33.33%
WMB Marketing Ventures, LLC \| Senior Secured Term Loan \| Senior Loans \| Signal Peak \| Global Holding
Guarantor Obligations [Line Items]
Investment ownership percentage	33.33%	33.33%
AE Supply
Guarantor Obligations [Line Items]
Company posted collateral related to net liability positions	$ 1,000,000	$ 1,000,000
New syndicated senior secured term loan facility	2,000,000	2,000,000
JCP&L, ME and PN \| Nuclear Plant Matters \| Financial Guarantee
Guarantor Obligations [Line Items]
Nuclear plant decommissioning trusts	800,000,000	800,000,000
Minimum \| Clean Water Act
Guarantor Obligations [Line Items]
Capital investment required to install technology to meet TDS and Sulfate limits		150,000,000
Maximum \| Clean Water Act
Guarantor Obligations [Line Items]
Capital investment required to install technology to meet TDS and Sulfate limits		300,000,000
FES and FENOC
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	352,000,000	352,000,000
FE
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	1,000,000,000	1,000,000,000
Other Guarantee
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	220,000,000	220,000,000
Other Assurances
Guarantor Obligations [Line Items]
Outstanding guarantees and other assurances aggregated	141,000,000	141,000,000
Term Loan Facility Due March 2020 \| Line of Credit \| Global Holding
Guarantor Obligations [Line Items]
Face amount of debt	300,000,000	300,000,000	$ 300,000,000
Little Bull Run \| Line of Credit \| Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Maximum amount borrowed under revolving credit facility	169,000,000	169,000,000
Hatfield Ferry \| Line of Credit \| Surety Bond (Collateralized Amount)
Guarantor Obligations [Line Items]
Maximum amount borrowed under revolving credit facility	31,000,000	$ 31,000,000
McElroy's Run Impoundment Site \| Pleasants Power Station
Guarantor Obligations [Line Items]
Increase in asset retirement obligation	43,000,000
McElroy's Run Impoundment Site \| Pleasants Power Station \| AE Supply \| Regulation of Waste Disposal
Guarantor Obligations [Line Items]
Increase in asset retirement obligation	$ 43,000,000

XML 70 R60.htm IDEA: XBRL DOCUMENT

Segment Information (Details Textuals) mi² in Thousands, customer in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) mi² customer company MW
Regulated Distribution
Segment Reporting Information [Line Items]
Number of existing utility operating companies \| company	10
Number of customers served by utility operating companies \| customer	6
Number of square miles in service area \| mi²	65
Megawatts of net demonstrated capacity of competitive segment	3,790
Other/Corporate
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	1,637
Long-term debt and other long-term obligations \| $	$ 5,350
FirstEnergy \| Revolving Credit Facility \| Other/Corporate
Segment Reporting Information [Line Items]
Long-term line of credit \| $	$ 1,700
Corporate/Other
Segment Reporting Information [Line Items]
Megawatts of net demonstrated capacity of competitive segment	1,367

XML 71 R61.htm IDEA: XBRL DOCUMENT

Segment Information (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2018

Sep. 30, 2017

Sep. 30, 2018

Sep. 30, 2017

Dec. 31, 2017

^[1]

$ 3,064

$ 2,910

$ 8,551

$ 8,247

283

261

843

765

113

(188)

274

164

255

262

858

751

133

202

503

483

387

301

840

772

39,443

43,649

39,443

43,649

$ 42,257

5,618

$ 5,618

635

593

1,942

1,847

Regulated Distribution

2,499

6,930

1,115

756

Regulated Transmission

341

996

Operating Segments | Regulated Distribution

302

264

2,766

2,609

7,694

7,380

202

183

598

540

107

(194)

263

146

127

133

384

405

126

183

357

442

416

314

28,530

27,866

28,530

27,866

5,004

Operating Segments | Regulated Transmission

356

286

1,011

854

346

341

1,010

981

187

164

124

116

104

154

10,017

9,356

10,017

9,356

614

262

248

836

717

Corporate/Other

104

377

263

(27)

(30)

(113)

(128)

(97)

(577)

(248)

896

938

896

938

Reconciling Adjustments

(54)

(50)

(181)

(151)

(8)

(13)

(27)

(33)

(8)

(13)

(27)

(33)

5,489